Search

[Display omitted] • A novel coal-fired power plant coupling with waste incineration scheme is proposed. • The PCDD/Fs emission could be suppressed by a three stages controlling method. • The flue gas circulation can also suppress the emission of PCDD/Fs effectively. The production of organic solid waste is increasing as the development of society. However, the investment of waste incineration power plant is very high and the thermal efficiency is very low. At the same time, the load of coal-fired power plant is suppressed due to the carbon neutralization policy. Therefore, using the existed coal-fired power plant to co-process the organic solid waste is a feasible method. In this paper, a coal-fired power plant indirect coupling with waste incineration technology based on flue gas circulation was proposed and studied on a 100 kW pilot-test bench. In this technology, the polychlorinated dibenzo-p-dioxins/dibenzofurans (PCDD/Fs) was reduced by a three stages controlling method, which adopts the blending of multi-source organic wastes, high-temperature decomposition and selective catalytic reduction (SCR) catalyst decomposition, simultaneously. The effects of waste incineration coupling, replacement ratio of coal, and flue gas circulation on the combustion and pollutant emission characteristics of the system were studied. The experimental results indicate that the waste incineration coupling has minor influence on the temperature distribution and the toxicity of fly ash of the coal-fired furnace. The NO, HCl, and PCDD/Fs concentrations of flue gas of coal-fired furnace generally decrease as the replacement ratio of coal increases, while the SO 2 concentration increases. With the help of three stages controlling method or the flue gas circulation, the PCDDFs concentration of the flue gas of coal-fired furnace can be much lower than 0.1 TEQ ng/Nm3. [ABSTRACT FROM AUTHOR]

• The NO emission characteristics of co-combustion of pulverized coal and NH 3 at O 2 /N 2 and O 2 /CO 2 atmospheres were studied. • The effects of temperature, NH 3 blending ratio and combustion atmosphere on NO emission during co-combustion were investigated. • The molecular dynamics simulation was used to study the migration pathways of N in NH 3. The use of ammonia as a co-combustion fuel instead of fossil fuel combustion is an important way to reduce carbon emissions from coal-fired power plants. This paper investigates the NO emission characteristics of coal/NH 3 co-combustion at O 2 /N 2 and O 2 /CO 2 atmospheres through experiments and molecular dynamics studies. The results demonstrate that increasing the combustion temperature enhances the formation of NO with the NH 3 blending ratio is 0–60 %. When coal and NH 3 are burned together, the emission of NO is lower at O 2 /CO 2 atmosphere compared to that at O 2 /N 2 atmosphere. Reactive force field molecular dynamics (ReaxFF MD) simulation results show that the effect of high concentration of CO 2 on nitrogen conversion is mainly related to temperature. When the temperature is low, the physical characteristics of CO 2 with large specific heat capacity inhibits the conversion of NH 3 to NO. However, at high temperature, CO 2 participates in the reaction in large amounts, which increases the number of OH radicals in the combustion process and promotes the conversion of NH 3 to NO. The results show that with the increase of combustion temperature, the conversion of nitrogen-containing intermediates to NO is promoted. Furthermore, the reactive molecular dynamics simulation revealed the transfer pathway of N atoms in NH 3 during co-combustion process at two atmospheres. [ABSTRACT FROM AUTHOR]

• Studied the effects of NH 3 cofiring ratio, injection mode and OFA on NO x emission. • NO x exhibited a variety of trends under different injection modes and OFA rates. • Revealed all the different NO x trends are governed by the same NO mechanism. • Found air-staging is not always effective in the NO x reduction of NH 3 cofiring. Ammonia (NH 3) cofiring is a promising approach to reduce the CO 2 emissions from coal-fired power plants. However, the potential drastic increase of NO x emissions may inhibit the wide implementation of NH 3 cofiring. To explore the potential NO x control strategies, the effects of NH 3 cofiring ratio (R N H 3 ), NH 3 injection mode and overfire air (OFA) rates on the NO x emission characteristics of NH 3 /coal cofiring are studied in a test furnace that allow for flexible control of the injection positions and combustion environment of NH 3. The results show that when NH 3 is injected with coal stream (top mixing mode), the NO x emissions increase and then decrease with the increase of R N H 3 under all OFA rates. However, when NH 3 is fed through the side port of furnace separately (side mixing mode), the NO x emissions exhibit distinct trends under different OFA rates. Under lower OFA rates, the NO x emissions show monotonical decrease with the increase of R N H 3 , while under higher OFA rates the NO x emissions first decrease and then increase with the increase of R N H 3 . Consequently, higher OFA rates could produce higher NO x emissions than lower OFA rates. This indicates that air-staging is not always effective in the NO x reduction of NH 3 cofiring. Thus, although the side mixing mode of NH 3 cofiring exhibits overall better performance in NO x control, caution is needed to accommodate the OFA rate with NH 3 cofiring ratio. Although a variety of trends of NO x emissions were observed in this study, the results demonstrate that all these trends are in fact governed by the same mechanism – the competition between the NO-formation and NO-reduction reactions of NH 3 in the varying O 2 environment in the furnace. By creating appropriate O 2 environment in the furnace, the NO x emissions of NH 3 /coal cofiring could be substantially lower than that of pure coal combustion. The findings of these paper are instrumental in the design and operation of NH 3 cofiring system in full scale coal-fired boilers to achieve effective NO x control. [ABSTRACT FROM AUTHOR]

This paper presents a general review of the Flue Gas Desulphurisation (FGD) technologies used to abate sulphur emissions from coal-fired power plants, and exposes the major physic-chemical processes occurring during wet limestone FGD. The abatement capacity of major, minor, and trace elements and the fate of trace pollutants during wet limestone FGD, as well as the features of wet limestone FGD by-products are discussed. It can be stated that wet limestone FGD system is the FGD process most widely used because of its high desulphurisation performance and low operating cost. Among control parameters evaluated in this review, pH range > limestone reactivity and SO 2 concentration > efficiency of particulate control devices > water re-circulation to the scrubber > entrainment of particles by the OUT-FGD gas, are the key factors of wet limestone FGDs. It is noted that, the enrichment of inorganic trace pollutants in FGD waters because of the re-circulation of water to the scrubber from gypsum slurry filtration, and the entrainment of accumulated fly ash particles in gypsum sludge, those of unreacted limestone, and the particles and droplets from gypsum slurry by the outgoing FGD (OUT-FGD) gas reduce considerably the desulphurisation efficiency and the abatement capacity of trace pollutants by wet limestone FGDs. The paper concludes with a number of issues to be investigated in depth in view of the worldwide FGD market growth and the forthcoming implementation of one of the most promising technologies to reduce CO 2 emissions, oxy-fuel combustion, in Pulverised Coal Combustion (PCC)–FGD processes at an industrial scale. [ABSTRACT FROM AUTHOR]

• DFT application on arsenic behavior in coal-fired power plants. • Mechanisms of arsenic behavior in a typical pulverized coal combustion system and related equipment. • Current gaseous arsenic capture technologies using sorbents. • An outlook on DFT application on arsenic behavior in power units. Arsenic is one of the World Health Organization's 10 chemicals of major public concern. Coal-fired power is the major anthropogenic source for arsenic emission, and will remains a major contributor to energy production worldwide in the foreseeable future. In combination with experiments, quantum chemistry offers a profound overview of arsenic behavior and possess a predicted effect for arsenic emission. This work summarizes the application of density functional theory (DFT) on arsenic behavior in coal-fired power plants, and is divided into two parts: (1) Mechanisms of arsenic behavior in a typical pulverized coal combustion system and related equipment, with the aim of enhancing cooperative control of arsenic emission from existing equipment in power units. Given that trapping gaseous arsenic species on large particles using sorbent is an effective method to suppress the arsenic emission, part (2) introduces the current gaseous arsenic capture technologies using sorbents, and summarizes information on arsenic adsorption for typical sorbents including Ca, Fe and Al-based materials. Finally, the paper provides an outlook on DFT application on arsenic behavior in power units to guide the development of new cost-effective approaches for reducing the arsenic emission. [ABSTRACT FROM AUTHOR]

• This paper studied the low NO x combustion optimization based on PDOBLPSO. • Opposition-based learning is carried out with some learning probability. • The optimized NO x emissions are lower when the learning probability is in [0.1 0.3]. • Optimized NO x emissions based on PDOBLPSO are lowest among the studied algorithms. • Low NO x combustion optimization based on PDOBLPSO is most stable among the studied algorithms. NO x emissions emitted from coal-fired power plants are threatening human beings. Combustion optimization is an important technology to reduce NO x emissions. However, this technology is troubled with premature when swarm algorithms are employed. This paper studied low NO x combustion optimization based on partial dimension opposition-based learning particle swarm optimization. In this algorithm, opposition-based learning is carried out with some learning probability for each dimension of global best particle. The proposed algorithm was applied to the combustion optimization of some 600 MW boiler. Results show that median optimized NO x emissions and mean optimized NO x emissions are lower when the learning probability is located between 0.1 and 0.3. Median optimized NO x emissions and mean optimized NO x emissions based on partial dimension opposition-based learning particle swarm optimization are lowest among the studied algorithms in most cases with limited iterations. Up to 37.72 mg/Nm3 median NO x emissions can be further reduced by partial dimension opposition-based learning particle swarm optimization compared with the optimized result provided by particle swarm optimization in some case. Besides, low NO x combustion optimization based on partial dimension opposition-based learning particle swarm optimization is most stable among the studied algorithms. [ABSTRACT FROM AUTHOR]

Highlights • SO 3 formation and phase transformation mechanism in coal-fired plants are studied. • The adverse effects of SO 3 on the utility operations and environment are analyzed. • Different SO 3 test standards and measurement methods are compared. • Various SO 3 control technologies are reviewed and compared. • Future trends of SO 3 emission limits and control strategies are prospected. Abstract The formation and emission of sulfur trioxide (SO 3) in coal-fired power plants has received increasing attention due to its adverse effects on the operation of plant and environment. With the wide application of selective catalytic reduction (SCR) systems, the problem caused by SO 3 has become severe, especially when high sulfur coal is burned. Emission regulations of SO 3 for coal-fired power plants, which promote the development of SO 3 measurement and control technologies, have been set in some countries and regions. In this paper, recent advances in the formation, transformation, measurement, and control mechanism and technologies of SO 3 in coal-fired power plants were summarized. The formation mechanisms of SO 3 in boiler and SCR systems and its form transition and corresponding effects on the performance of power plants were analyzed. Different SO 3 test standards and methods were compared, and online SO 3 monitor based on isopropanol absorption method were developed. Various SO 3 control technologies, including simultaneous and specific removal technology, were summarized. Low-low temperature and wet electrostatic precipitators could remove up to 90% SO 3 /H 2 SO 4 aerosol, and the removal efficiency of SO 3 in wet flue gas desulfurization can be enhanced to 80% by absorber optimization and inlet flue gas temperature decrease. For power plants that burn high-sulfur coal, the injection of alkaline sorbent before the SCR or air preheater system can remove more than 90% of SO 3 to decrease the formation of NH 4 HSO 4 and the pressure drop in the air preheater. High SO 3 removal technology and strategies for different scenarios were proposed to meet different SO 3 emission requirements in the future. [ABSTRACT FROM AUTHOR]

Highlights • Steady and dynamic ORP models are developed using LSSVM and WFGD operating data. • Input parameters are analyzed to develop the steady ORP model. • Time delays of input parameters are optimized to develop the dynamic ORP model. • Sensitivity analysis was made to analyze influence of parameters and time delays. • Models can be extended to conduct optimization of WFGDs to mitigate Hg re-emission. Abstract The oxidation-reduction potential (ORP) is highly related to Hg re-emission in wet flue gas desulfurization (WFGD) systems in coal-fired power plants. Developing an accurate model that describes the ORP characteristics is beneficial to achieve the operation optimization of the WFGD system and Hg re-emission reduction. In this paper, steady and dynamic ORP models were reported based on the least squares support vector machine (LSSVM) technique and using operating data acquired from a coal-fired power plant. For the steady model, input parameters consisted of flue gas flow, flue gas temperature, inlet SO 2 concentration, oxidation air flow, recycle pump currents, and slurry feed flow. For the dynamic model, in addition to the parameters listed above, time delays of these parameters were also considered in the modeling scheme. Both models achieved high accurate predictions. Model sensitivity analysis was conducted to investigate the influence of the input parameters and time delays on ORP. Results show that the parameters are adequate to describe the characteristics of the ORP. In addition, parametric time delays play an important role to represent the dynamic characteristics of the ORP. These models can be extended to design process control strategy and conduct the ORP operation optimization of the WFGD system in power plants to mitigate Hg re-emission from the scrubber. [ABSTRACT FROM AUTHOR]

Abstract: Trace elements such as mercury, arsenic and selenium present in coal are known to be of concern for public health. Coal-fired power plants have resulted in emission of several tons of TEs in environment. These elements mostly evaporate during combustion and condense either homogeneously as sub-micron ash or heterogeneously onto already existing fine ash. The coal–mineral and mineral–mineral associations play an important role in the formation of fine particles and in subsequent condensation of trace elements in various phases. Any retention of these elements in fly ash particles is strongly influenced by their association with other minerals in individual coal and mineral grains. Clean coal technology development is, therefore, a priority area for research and needs continuous improvements in increased efficiency and decreased pollutant emission. The paper will include trace elements in different coals from around the world. It will consider different modes of occurrences present in coals, the ash formation and evaporation of trace elements and emissions. The typical emissions from typical power stations will be presented. The paper will also review different approaches adopted in estimating the deportment of these elements. The paper at the end would discuss control strategies for reducing emissions and future directions. [Copyright &y& Elsevier]

Abstract: The objective of this study was to develop an engineering tool by which the combustion behavior of coals in coal-fired utility boilers can be predicted. We presented in this paper that computational fluid dynamic (CFD) codes can successfully predict performance of- and emission from- full-scale pulverized-coal utility boilers of various types, provided that the model parameters required for the simulation are properly chosen and validated. For that purpose we developed a methodology combining measurements in a 50kW pilot-scale test facility with CFD simulations using the same CFD code configured for both test and full-scale furnaces. In this method model parameters of the coal processes are extracted and validated. This paper presents the importance of the validation of the model parameters which are used in CFD codes. Our results show very good fit of CFD simulations with various parameters measured in a test furnace and several types of utility boilers. The results of this study demonstrate the viability of the present methodology as an effective tool for optimization coal burning in full-scale utility boilers. [Copyright &y& Elsevier]

Solvent-based post-combustion CO 2 capture plant has to be operated in a flexible manner because of its high energy consumption and the frequent load variation of upstream power plants. Such a flexible operation brings out two objectives for the control system: i) the system should be able to change the CO 2 capture rate quickly and smoothly in a wide operating range; ii) the system should effectively remove the disturbances from power plant flue gas. To achieve these goals, this paper proposed a multi-model predictive control (MMPC) strategy for solvent-based post-combustion CO 2 capture plant. Firstly, local models of the CO 2 capture plant at different operating points are identified through subspace identification method. Nonlinearity analysis of the plant is then performed and according to the results, suitable local models are selected, on which the multi-model predictive controller is designed. To enhance the flue gas disturbance rejection property of the CO 2 capture plant and attain a better adaption to the power plant load variation, the flue gas flow rate is considered in the local model identification as an additional measured disturbance, thus the predictive controller can calculate the optimal control input even in the case of flue gas flow rate variation. Simulation results on an MEA-based CO 2 capture plant developed on gCCS show the effectiveness and advantages of the proposed MMPC controller over wide range capture rate variation and power plant flue gas variation. [ABSTRACT FROM AUTHOR]

• Different development aspects of oxy-fuel CFBC including combustion characteristics, heat transfer, emissions, fuels, and system optimization are presented. • The differences of pollute emissions and desulfurization mechanism between air combustion mode and oxy-fuel combustion mode in CFB are considered. • The effects of operation parameters on NO x /SO x emissions in Oxy-CFBC are concluded. • The new generation technology and the patent status for Oxy-CFBC were discussed. Oxy-fuel circulating fluidized bed combustion (Oxy-CFBC) is regarded as one of the most promising and sustainable technologies for carbon capture, utilization and sequestration (CCUS) in coal-fired power plants. The investigation of Oxy-CFBC technology has been rapidly developed in the past 15 years. The Oxy-CFBC facilities are from lab-scale to industrial-scale. The inlet oxygen concentration increased from 21 to 30 % in first generation of Oxy-CFBC to higher inlet oxygen concentration up to 50 % in second generation of Oxy-CFBC. This paper reviews the published materials on the aspects of research status including existing models, heat transfer, combustion characteristics, pollutant formation and emission, and Oxy-CFB power plant system optimization. In particular, research fuels included coal, biomass, sewage sludge and oil shale, and the differences of NO x emission and desulfurization mechanism between air combustion mode and oxy-combustion mode are considered in the review. The NO emissions (in mg/MJ) are lower and the direct desulfurization will occur under Oxy-CFBC conditions as compared to that in air-fired conditions. In Oxy-CFBC, the increase in inlet oxygen concentration and temperature will improve the combustion efficiency and desulfurization efficiency, but increase NO emissions as well. Gas staging and oxygen staging are effective ways to reduce NO emissions. Moreover, the new generation of Oxy-CFBC technologies such as pressurized Oxy-CFBC and oxygen-steam combustion, the published patent status about Oxy-CFBC and the challenges of Oxy-CFBC technology in China are also analyzed for future research and technology industrial application. [ABSTRACT FROM AUTHOR]

This paper discusses the limitations and prospects of using equilibrium-based column models for the dynamic simulation of post-combustion CO 2 capture processes. Based on their features, one of three available commercial process simulators was chosen for this study. A pilot plant configuration adopted from literature was modeled and simulated using this simulator. Simulation results were compared with plant data and with results using standard rate-based models as available in literature. Temperature profiles in columns and overall mass and energy balances were found to be similar to plant data; however, CO 2 capture-rate, reboiler-duty, and rich-loading using the model were overestimated. A method of reduced stage efficiencies in the absorber was used, which improved performance prediction further with a maximum deviation of 5%. Further, this dynamic model was used to analyze the process subjected to variation in flue gas flow-rate with a similar trend of futuristic power plants by controlling either liquid to gas ratio or CO 2 capture-rate. Controlling liquid to gas ratio provided more control over the reboiler-duty while controlling the capture-rate focused on maintaining a certain capture ratio. The advantages and disadvantages of both methods are discussed and based on that, the controlling capture ratio was found suitable for using while power plant works flexibly with stringent emission regulations. [ABSTRACT FROM AUTHOR]

[Display omitted] • Use of sorbent polymer composite allows for fulfilling emission norms from coal fired plants. • Velocity and mercury content have the biggest influence on performance of material. • Experimental and laboratory results indicate high mercury reduction potential. • Analysis proved that for assumed exploitation time tested material will hold its mercury reduction potential. • Numerical model was successfully used to simulate mercury reduction. This paper presents an experimental and numerical investigation of the performance of a sorbent polymer composite (SPC) material used for removing mercury from the flue gases in a full-scale industrial installation. The investigated material is an attractive alternative to activated carbon, which is commonly used for this purpose. While the application of the SPC is characterized by high capital expenditures, this technology offers not only very low operating expenditures but also high efficiency. This study investigates the SPC's mercury reduction capabilities concerning the most important flow parameters such as gas velocity, temperature, humidity, and mercury concentration. Small scale laboratory experiment was used to tune the kinetic data of the mercury adsorption. The resulting sub-model has been built into the CFD simulations validated against measurements at an industrial installation. The results showed that the most important parameters affecting the mercury reduction efficiency were the gas velocity and mercury content in the sorbent material. Numerical simulation proved that the material absorbs mercury within the entire reasonable operating temperature and humidity ranges, regardless of mercury speciation. [ABSTRACT FROM AUTHOR]

• Laboratory experiments were conducted in a furnace-temperature-controlled facility. • The impact of air-staged strategies on NH 3 /coal co-firing was analyzed. • Extending the burnout air addition position can effectively lower NO emissions. • High quantities of NO were generated in NH 3 /coal co-firing at high temperature. • The emission characteristics of pure NH 3 air-staged combustion was studied. Ammonia/coal co-firing in coal-fired power plants is an effective and promising route to achieve CO 2 reduction. This paper studies ammonia/coal co-firing in a 45 kW wall-temperature controlled staged combustion furnace employing overall air-staged combustion technology to meet the goal of low carbon and low NOx emissions. The effect of different burnout air addition positions and combustion environmental temperatures on the NO emissions, as well as the CO and H 2 S release characteristics of ammonia/coal co-firing was studied for ammonia co-firing ratios ranging from 0 % to 100 % (calorific value), with bituminous coal as the experimental object. To offer a qualitative overview of the experimental results, chemical reaction kinetic calculations were performed. The position of the burnout air addition has significant effects on the ammonia/coal co-firing products. The further the burnout air addition position is from the burner outlet, the lower the NO emission. When the distance is too great, however, the improvement in NO reduction efficiency is limited, which might have a negative impact on combustion efficiency. At 1300 °C, the NO emission concentration is substantially higher due to the deterioration of SNCR (selective non-catalytic reduction) capabilities of NH 3 at high temperatures. High temperatures also reduce coal char production, which results in less heterogeneous reduction reactions on char surface. Based on experimental results and chemical kinetic calculations, the release patterns and mechanisms of combustion products during ammonia/coal co-firing under various air-staged strategies were explored in this work, presenting a promising technically achievable solution for reducing CO 2 and NOx emissions from the coal-fired power plants. [ABSTRACT FROM AUTHOR]

[Display omitted] A carbon-capture system is required for coal-fired power plants to meet environmental regulation and provide support for grid penetration of renewable energy sources, when the integrated power plant-carbon capture system must operate in a highly flexible manner to accommodate the need for intermittent renewable power. To this end, this paper proposes a hierarchical scheduling scheme for the operation of integrated power plant-carbon capture system to fully exploit the decarbonization and flexibility of carbon capture technology in multiple timescales. The upper layer of the hierarchy implements a day-ahead stochastic scheduling to provide hourly operating instructions in the next 24 h so that the overall economic performance of the plant can be best achieved, including fuel consumption, load following and carbon trading. A novel index is then introduced to reflect the power adjustment contribution of carbon capture in the intraday scheduling layer and enhance the load ramping performance of power plant by flexible operation of the post-combustion carbon capture in minute timescale. In the lower layer of the hierarchy, control-perceptive scheduling based on close-loop dynamic model is proposed to coordinate the scheduling and underlying control, making the scheduling feasible for the operating practice. In addition, a new control system, which uses the reboiler steam flowrate to control the CO 2 production rate and solvent circulation flowrate to control reboiler temperature is proposed to achieve superior flexibility support role of carbon capture. The case study shows that the proposed scheduling approach can improve the load tracking performance by 36.7% with satisfactory performance in carbon capture, which verifies the efficacy of the proposed scheduling approach in the power system. The impact of the proposed control system is also investigated, providing a broad insight on the flexible operation of carbon capture technology integrated with the power plant. [ABSTRACT FROM AUTHOR]

• NH 3 /coal co-firing tests were conducted in one-dimensional down-fired furnace. • NO emission in NH 3 /coal co-firing can be controlled by air-staged combustion. • CO concentration can be highly enhanced by doping NH 3 in reduction zone. • NH 3 /coal co-firing can reduce the release of H 2 S in reduction zone. Ammonia is a carbon-free, hydrogen-rich fuel, which is considered as an alternative energy source with high utilization potential. Ammonia/coal co-firing in air-staged coal-fired boilers has attracted the attention of a number of academics in order to meet the aim of low carbon and NOx emissions. In this paper, ammonia/coal co-firing experiments were conducted under air-staged condition in a one-dimensional combustion-temperature controlled down-fired furnace with multi-path air inlets at 1100℃. The influence of ammonia co-firing ratio on NO and CO 2 emissions, as well as CO and H 2 S release characteristics, was studied using Shenhua bituminous coal in air-staged and non-staged combustion conditions. Chemical reaction kinetic calculations were conducted to provide a qualitative analysis of the experimental results. Ammonia plays a complex role in the ammonia/coal co-firing process. An effective CO 2 reduction was achieved with ammonia co-firing, and it was found that air-staged combustion is also effective for NO emission control in the ammonia/coal co-firing process. Considering the economy issue and NO emission control, 20–30 % ammonia co-firing ratio is recommended. However, ammonia/coal co-firing can greatly promote the coal gasification reaction, which leads to a higher concentration of CO in the reduction zone in air-staged combustion, compared with coal combustion. Meanwhile, ammonia co-firing has a significant inhibitory effect on the release of H 2 S from coal and will promote the subsequent decomposition process. This study explains the NO release pattern in ammonia/coal co-firing processes based on experimental results and chemical kinetics calculations, which provides a promising technical advancement direction for the coal-fired power plants to achieve a signification reduction of both CO 2 and NO emissions. [ABSTRACT FROM AUTHOR]

Gas-phase oxidation of elemental mercury (Hg 0 ) from flue gas by simulated electrostatic precipitators (ESP) electric field was explored in this paper. In order to enhance the removal efficiency of Hg 0 by ESP electric filed, a novel discharge activation reactor was designed and employed. The influence of HCl concentration, temperature, fly ash, and flue gas components on the Hg 0 removal were also considered, respectively. The Hg 0 removal efficiency increased with the increase of HCl concentration, temperature and discharge voltage. It has also been found that O 2 , H 2 O and fly ash showed a light promotion on the removal of Hg 0 while NO and SO 2 had a slight inhibition effect on Hg 0 oxidation. Furthermore, the novel discharge activation reactor could improve the generation of reactive chemical species, such as Cl· or Cl 2 , which facilitated the mercury removal. At the reaction temperature of 413 K, about 60% Hg 0 could be removed from simulated flue gas under 25.0 kV in presence of 10.0 ppmv HCl. When the novel discharge activation reactor was used, the Hg 0 removal efficiency increased to about 80% at the same experimental conditions. It appeared to be a promising technique to enhance the removal of Hg 0 by ESP. [ABSTRACT FROM AUTHOR]

Uranium is a trace elemental in coal. The uranium content from coal mines in China and its distribution in coal-fired power plant effluents was studied and reported in this paper. Chinese coal samples from eighteen coal mines were collected and analyzed for uranium. It was found that the uranium content for most of the coals was in the range from 1 to 3 mg/kg. Laboratory experiments with a tubular furnace indicate that the amount of uranium released from heated coal increases with temperature and with the retention time, when it combust. Most of the uranium (about 90%) in the coal can be transferred to the ash. Full-scale field tests were carried out at a coal-fired power plant to investigate the uranium distribution (and mass balance) in the coal, limestone, fly ash, bottom ash, gypsum and the flue gas. Almost all the uranium in the coal concentrated in the fly ash (about 80%) and the bottom ash (about 10%). The uranium content in the flue gas was less than 1/1000 of the total elemental input, between 0.043 and 0.069 μg/m 3 , which is much lower than the typical concentration of mercury or arsenic in flue gas of coal-fired power plant. The uranium content in the desulfurization gypsum product was found to be slightly larger than the uranium content of the limestone. [ABSTRACT FROM AUTHOR]

The paper presents a comparison between Pulverized Coal Fly Ashes (PCFA) and Spreader Stoker Coal Fly Ashes (SSCFA) by analyzing their chemical, mineralogical and physical characteristics. PCFA have been recognized as being valuable industrial by-products and many research studies have been published on their characteristics, properties and utilizations. On the contrary, relatively little is known about SSCFA due to a lack of research work and their valorisation appears to be a difficult task, mainly due to their high unburned carbon content. Three fly ashes are studied here, two resulting from pulverized coal power plants and one from spreader stoker power plant. The results show that the tested fly ashes have a similar chemical and mineralogical composition whatever the combustion process used. SSCFA presents some specific characteristics approaching those of normalized PCFA. However, the combustion system seems to have an impact on the physical properties and performance of fly ashes as supplementary cementitious materials when blended with Portland cement. SSCFA has indeed a high unburned carbon content, which could be explained by a combustion process not adapted for coal. Rheological and mechanical tests results show that SSCFA/cement Portland-based mortars have interesting properties and could be used in some specific industrial applications. [ABSTRACT FROM AUTHOR]

India has about a tenth of the world’s coal reserves, much of it with high mineral content. These coals produce a large amount of fly ash, which can affect human health and environmental quality aspects during utilization. In this paper, the petrological and biological aspects of some industrially important Indian coal fly ash (CFA) from a coal-based captive power plant are addressed. The petrology of the CFAs is also studied for the samples collected in different times. The study has revealed that the CFAs contain mainly glass fragments, spinel, quartz, and other minerals in lesser quantities. Fly ash carbons were present as chars, possibly from the incomplete combustion of the coals (bituminous and/or subbituminous) used in the power plant. The deposition of CFAs over the leaves of different plant species reduces the photosynthesis rate by about 95% within a period of 2 h. The CFAs also show minor effects to some test microbes. This investigation will be useful in assessment of the environmental impact of a coal-based power plant. [ABSTRACT FROM AUTHOR]

With increasing quantities of biomass being combusted in coal fired power stations, there is an urgent need to be able to predict the grindability of biomass in existing coal mills, but currently no standard biomass grindability test exists. In this study, the applicability of the Hardgrove Grindability Index (HGI) and Bond Work Index (BWI) as standard grindability tests for biomass were investigated for commercially sourced wood pellets, steam exploded pellets, torrefied pellets, sunflower pellets, eucalyptus pellets, miscanthus pellets, olive cake and Colombian La Loma coal. HGI predicts the behaviour of fuels in vertical spindle mills and BWI for tube and ball mills. Compared to La Loma (HGI of 46), all biomasses tested performed poorly with low HGI values (14–29). Miscanthus pellets had the highest BWI or W i at 426 kW h/t. Despite similar HGI values, some untreated biomasses showed lower BWI values (Eucalyptus pellets W i 87 kW h/t, HGI 22) compared to others (sunflower pellets W i 366 kW h/t, HGI 20). Torrefied pellets had the lowest W i (16 kW h/t), with La Loma coal at 23 kW h/t. Wood, miscanthus and sunflower pellets exhibited mill choking during the BWI test, as the amount of fines produced did not increase with an increasing revolution count. An approximate correlation between HGI and BWI was found for the biomass samples which did not experience mill choking in the BWI test. Milling results in this paper suggest that biomass pellets should be composed of pre-densified particles close to the target size in order to minimise the energy use in mills and possibility of mill choking. Our findings would also suggest that the BWI is a valid test for predicting the potential for mill choking of biomass in a tube and ball mill. HGI, however, appears to be a poor method of predicting the grindability of biomass in vertical spindle mills. A new standard grindability test is required to test the grindability of biomasses in such mills. [ABSTRACT FROM AUTHOR]

Integrating a power plant with CO 2 capture incurs serious efficiency and energy penalty due to use of energy for solvent regeneration in the capture process. Reducing the exergy destruction and losses associated with the power plant systems can improve the rational efficiency of the system and thereby reducing energy penalties. This paper presents steady state simulation and exergy analysis of supercritical coal-fired power plant (SCPP) integrated with post-combustion CO 2 capture (PCC). The simulation was validated by comparing the results with a greenfield design case study based on a 550 MWe SCPP unit. The analyses show that the once-through boiler exhibits the highest exergy destruction but also has a limited influence on fuel-saving potentials of the system. The turbine subsystems show lower exergy destruction compared to the boiler subsystem but more significance in fuel-saving potentials of the system. Four cases of the integrated SCPP-CO 2 capture configuration was considered for reducing thermodynamic irreversibilities in the system by reducing the driving forces responsible for the CO 2 capture process: conventional process, absorber intercooling (AIC), split-flow (SF), and a combination of absorber intercooling and split-flow (AIC + SF). The AIC + SF configuration shows the most significant reduction in exergy destruction when compared to the SCPP system with conventional CO 2 capture. This study shows that improvement in turbine performance design and the driving forces responsible for CO 2 capture (without compromising cost) can help improve the rational efficiency of the integrated system. [ABSTRACT FROM AUTHOR]

As countries across the world are pushing towards the increased use of renewable sources of energy the burning of biomass fuels makes up an important part of this strategy. Many coal fired power stations have been converted to co-firing and in some cases are being completely biomass fuelled. However, due to their variability in size, shape and the complex nature of gas–solids two-phase flow the monitoring of biomass particles in a pneumatic conveying pipeline is difficult. This paper presents the results of experimental investigations carried out using a novel electrostatic sensor array that is capable of measuring the particle velocity and concentration profiles over the whole diameter of the pipe. Experimental tests were carried out on horizontal and vertical pipe sections with different particle sizes of a common biomass fuel – willow, over a range of flow conditions. Results from the experiments indicate that smaller biomass particles have more stable flow characteristics across the whole diameter of the pipe. [ABSTRACT FROM AUTHOR]

The sub-models of comminution and classification for vertical spindle mill (VSM) presented in Part 1 of this paper have been integrated in the VSM simulation models for the E-mill, MPS mill and CKP mill. Plant survey data from an E-mill (ball-race) and MPS mill (roller-race), both including internal streams and external sampling, and the CKP mill (roller-race without internal classification) were used to calibrate the VSM sub-model parameters for each device. It was found that the fitted comminution and classification model parameters were closely related to the primary air flow rates in the VSM operation. Relationships between the sub-model parameters and the air flow rates were established. Once the models are calibrated, no further model parameters fitting is required. The VSM models have been implemented in Microsoft Excel via the MDK (Model Development Kits) protocol. A number of potential applications of the JKMRC VSM models for coal-fired power stations and other industries are discussed. [ABSTRACT FROM AUTHOR]

• The form of ammonia at SCR outlet was only gaseous ammonia. • Gaseous ammonia was effectively converted into filterable ammonia in air preheaters. • Ammonia concentration in the captured fly ash from rear storehouses is higher. • Less than 0.3 mg/Nm3 ammonia was discharged with the ultimate purified flue gas. • Discharging with the captured fly ash was the main emission pathway for ammonia. The coal-fired power plants in China have basically completed the upgrade and transformation for the ultra-low emission, and the reduction in traditional pollutant emission is significant. However, excessive ammonia emission has become one of the major concerns due to its adverse effects on environmental protection facilities and atmospheric environment. In this paper, four typical coal-fired power plants which have completed the ultra-low emission retrofits were measured on site to investigate the whole process emission characteristics of ammonia. The ammonia in the flue gas was classified into the gaseous ammonia, the filterable ammonia or the total ammonia, based on different sampling systems. Besides, the ammonia in the captured fly ash, desulfurization slurry, desulfurization wastewater, and gypsum was also analyzed to provide a quantitative overview of ammonia emission. Results showed that there was only gaseous ammonia detected at the outlet of SCR devices. Most gaseous ammonia was converted into filterable ammonia when it passed through the air preheater. Filterable ammonia, the predominant form of ammonia that made up about 65% to 95% of the total ammonia, could be effectively captured by the dust removers, with over 80% of it being removed. Higher ammonia concentration was measured from the fly ash collected in the rear storehouses. The concentration of ammonia emitted at the WFGD outlet was less than 0.5 mg/Nm3, with no more than 0.3 mg/Nm3 being discharged after the further removal by WESP. Discharging with the captured fly ash was the main pathway for ammonia emission, which should be considered in the further pollution control in coal-fired power plants. [ABSTRACT FROM AUTHOR]

• Three different MSS co-firing modes in large coal-fired power plants were known and field samples were taken. • The ash fusion characteristics of MSS and coal co-firing were investigated. • Based on factsage, the change of minerals in ash with temperature and mixing ratio was simulated. • The slag and ash obtained in the laboratory are compared with the ash and slag of the full-scale power plants. By coupling the treatment of municipal sewage sludge (MSS) with large coal-fired units not only does it overcome the shortcomings of difficult combustion and the low calorific value of sludge, but it can also use the existing exhaust emission treatment devices of power plants to treat toxic gases and various pollutants discharged in the combustion process. It is a competent method for treating MSS, which has been more frequently used in coal-fired power plants in China in recent years. In this paper, raw coal, municipal sludge, fly ash and slag are sampled and analyzed from three full-scale power plants which are actually mixed with MSS. The melting characteristics and composition of ash obtained from raw coal and MSS at different mixing ratios and various temperatures are analyzed by ash fusion point determination meters, XRF and XRD, and the mineral evolution is simulated by Factsage. The results of the lab-scale study indicate that the ash melting characteristic temperature of MSS in three power plants is obviously lower than that of pulverized coal, and with an increase in the mixing ratio, the ash melting characteristic temperature of the mixed samples gradually decreases. The higher iron content in MSS is the main reason why the ash melting characteristic temperature of MSS and mixed samples is lower than that of coal, and hematite formed from the process is a common fluxing mineral. The analysis results for the slag and ash from three full-scale power plants co-firing MSS indicate that the main composition of slag and ash is mullite, and that co-firing MSS has little effect on the ash melting characteristics. The experimental results can provide reference for practical coal-fired power plants in reasonable mixing sludge, avoiding slagging and improving boiler efficiency. [ABSTRACT FROM AUTHOR]

Abstract: Current approaches for mercury removal have been focusing on injection of powdered activated carbon sorbents into the flue gas stream. In particular, brominated activated carbon has been proven at pilot scale and plant trials to be effective at removing mercury from flue gases of coal-fired power plants. However, activated carbon is a costly source material. Using an industrial solid waste from biomass combustion as an alternative source material to produce sorbents for mercury emission control is an attractive option. This paper describes a novel chemical–mechanical bromination process for production of mercury sorbent from a biomass combustion ash, which is normally considered a solid waste. The chemical–mechanical brominated ash was characterized and tested for mercury capture and release at high temperatures. The brominated biomass ash was found to effectively capture mercury up to 390°C in lab scale tests. The tests of the new brominated sorbent in a 375MW coal fired power plant showed promising performance. [Copyright &y& Elsevier]

Abstract: A semi-industrial filtration facility is currently in operation at the ETSI-University of Seville, with financial support from the European Commission and the Spanish Ministry of the Environment. This pilot plant allows testing different elements and reverse-flow pulse cleaning strategies using real coal ash and under diverse operating conditions such as temperature and pressure. The aim of the on-going research is the evaluation of the alternatives for hot gas filtration technologies and the optimisation of the operation and performance of the filtering elements. The first experimental campaign carried out in the filtration facility commenced in 2005. Four types of elements were tested at maximum temperature and pressure of 235°C and 7.5barg respectively. This paper describes the main results obtained during the second phase of the experimental campaign, in which the temperature was increased up to 370–550°C. Three types of elements (one type of bag filter and two types of candles) were tested. Main parameters investigated for the characterisation of the filtering elements performance were the pressure drop across the element, the cleaning pulse interval, the baseline pressure drop, the filtration efficiency and the durability of the elements. Dependences on the particle loading and temperature among others were also established. Results obtained and conclusions extracted provide a useful tool for the implementation of the filtration technologies at industrial scale. [Copyright &y& Elsevier]

Abstract: Oxygen is commonly produced at industrial scales by air separation using cryogenic air separation units (CASU). Despite being the most matured technology, CASU is highly energy intensive. Approximately, 3–4% energy penalty is expected to be arising for oxygen production using CASU in the oxy-fuel process. As an alternative to CASU, this paper demonstrates the integrated chemical looping air separation (ICLAS) process for oxy-fuel thermal power plant which is expected to offset the energy penalty associated with CASU. In our recent comprehensive thermodynamic study, three metal oxide systems (Mn, Co and Cu) were found most suitable for chemical looping air separation (CLAS). The objective of this work is to find out the possible integration modes of the CLAS process with oxy-fuel coal-fired power plants. Thermodynamic process simulations were carried out for ICLAS in oxy-fuel using Fact-sage 6.1 database for all selected oxygen carriers and process kinetics have not been considered. The effect of several process parameters such as operating temperature, heat recovery, actual partial pressure in the reactors and chemical conversion of the oxygen carriers on the operating cost of the ICLAS process were investigated in detail. The results indicate that for acceptable process kinetics ICLAS can potentially run at much lower operating costs compared to an advanced CASU based system by 2020. [Copyright &y& Elsevier]

Abstract: The characteristics of both particulate formation and ash deposition play an important role in retrofitting the conventional air-fired coal power plant into the recycled oxy-fuel plant. In this paper, an intensively comparative study was performed with a 25kW quasi one-dimensional down-fired pulverized coal combustor for clarifying the differences between air combustion and recycled oxy-fuel combustion of bituminous coal. In oxy-fuel mode, the volume recycle ratio of flue gas (dry basis) was kept at 77.8%, and then the oxygen concentration at 30% to provide a similar heat flux output to the air mode. A nitrogen-aspirated, isokinetic particulate sampling probe, followed by either electric low-pressure impactor (ELPI) or scanning mobility particle spectroscopy (SMPS), was introduced to measure fine particulates, while an air-cooled deposition probe was designed to collect ash deposit samples. The results indicated that, under similar furnace temperature profiles, the oxy-fuel combustion leads to the higher fine particulate formation, finer bulk ash particle formation and lower ash deposition. The aerodynamic factor, instead of the chemical composition related to fine particulates, determines the difference in the ash deposition behavior in two combustion modes. [Copyright &y& Elsevier]

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. . 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. [Copyright &y& Elsevier]

Abstract: This paper reports about changes in mobility of hazardous elements contained in coal during combustion at a power plant in Santa Catarina (Brazil) and the environmental impact potential of ashes. Total and mobile element concentrations were determined by digestion and sequential extraction. Comparison of results within the mobile fraction showed that after combustion, oxidizable elements bound to organic matter and sulfides in coal were mostly transformed into elements easily soluble in water or slightly acidic conditions and, hence, most readily bioaccumulative in the environment in ashes, mainly U, Cr, and As. Capacity of ashes as a source of mobile pollutants was quantified by combining sequential extraction and annual production. Just considering the easily soluble fraction, coal ashes could leach up to 839tons of Al, 144tons of Fe, 100tons of Mn, 4.6tons of Zn, 3.1tons of Cr, 1.7tons of As, 1.5tons of Cu, 490kg of U, and 20kg of Pb every year. Bottom ashes are disposed of in landfill sites close to the plant. Fly ashes are recycled as construction material. Diagnostic processes do not consider checking for these highly mobile hazardous elements. Hence, uncontrolled dumping and use of these by-products may pose significant risks to environment and human health. [Copyright &y& Elsevier]

Abstract: The oxyfuel technology offers the possibility for CO2 sequestration from coal fired power plants. One drawback is the need for a high external flue gas recirculation to avoid inadmissible high flame temperatures. The concept of controlled staging with non-stoichiometric burners (CSNB) allows a significant reduction of the commonly proposed flue gas recirculation rate while fulfilling all requirements on temperature limitations. The concept aims at a more efficient oxyfuel process with a higher degree of freedom for heat-flux adjustments suitable for a new generation of oxyfuel boilers. The steam generator size could be reduced and in this way a more cost effective steam generator concept is possible. Additionally the energy demand for the flue gas recirculation is lowered. This paper presents the experimental investigations of non-stoichiometric oxycoal flames. Temperature and gas profiles were taken to analyze the combustion behavior of coal with high oxygen concentrations in the oxidizer under oxygen deficiency and accordingly oxygen excess. In addition an optical flame monitoring system allowed a comparison of ignition, flame shape and stability. In the test rig lignite was burned under different stoichiometries ranging from 0.5 to 2.5 and different oxygen concentrations in the oxidant ranging from 30 to 40vol.%. The thermal input of the burner was 70kW at a total thermal input of 140kW and a dry flue gas recirculation was used. The results were compared to a conventional air-blown combustion and showed that similar temperature ranges can be reached even with oxygen concentrations in the oxidizer as high as 40vol.%. [Copyright &y& Elsevier]

Abstract: Ammonium bisulfate (ABS) forms in coal-fired power plant exhaust systems when ammonia slip from the NO x control system reacts with the sulfur oxides and water in the flue gas. The critical temperature range for ABS formation occurs in the air preheater, where ABS is known to cause corrosion and pluggage that can require unplanned outages and expensive cleaning. To develop mitigation strategies for the deleterious effects of ABS in air preheaters, it is important to know its formation temperature and deposition process. This paper describes a bench-scale experimental simulation of a single-channel air preheater, with the appropriate temperature gradient, used in conjunction with simulated coal combustion flue gas, including sulfur oxides, ammonia, and water vapor, to investigate the formation of ABS. Formation was observed optically, and the formation temperature, as well as deposition characteristics for a realistic range of reactant concentrations are presented and compared with previous studies on ABS formation. This study presents data at realistic concentrations not earlier tested, and the reported data has smaller experimental uncertainty than previously obtained. We found that the measured ABS formation temperatures under air preheater channel conditions lies between the temperatures reported by others, and is in the range of 500–520K for typical flue gas concentrations of ammonia and sulfur oxide species. The results also show that, at least for this experimental configuration, ABS forms predominantly as an aerosol in the gas phase rather than as a condensate on the channel walls. [Copyright &y& Elsevier]

Abstract: Post-combustion capture by chemical absorption using MEA solvent remains the only commercial technology for large scale CO2 capture for coal-fired power plants. This paper presents a study of the dynamic responses of a post-combustion CO2 capture plant by modelling and simulation. Such a plant consists mainly of the absorber (where CO2 is chemically absorbed) and the regenerator (where the chemical solvent is regenerated). Model development and validation are described followed by dynamic analysis of the absorber and regenerator columns linked together with recycle. The gPROMS (Process Systems Enterprise Ltd.) advanced process modelling environment has been used to implement the proposed work. The study gives insights into the operation of the absorber–regenerator combination with possible disturbances arising from integrated operation with a power generation plant. It is shown that the performance of the absorber is more sensitive to the molar L/G ratio than the actual flow rates of the liquid solvent and flue gas. In addition, the importance of appropriate water balance in the absorber column is shown. A step change of the reboiler duty indicates a slow response. A case involving the combination of two fundamental CO2 capture technologies (the partial oxyfuel mode in the furnace and the post-combustion solvent scrubbing) is studied. The flue gas composition was altered to mimic that observed with the combination. There was an initial sharp decrease in CO2 absorption level which may not be observed in steady-state simulations. [Copyright &y& Elsevier]

Abstract: This paper presents experimental investigations into the ignition behaviors of pulverized coals and coal blends in a drop tube furnace using a flame monitoring system. Seven different ranks of coals and coal blends of different mixing proportion were tested. Characteristic parameters including relative ignition temperature, maximum ignition points, oscillation frequency, fluctuation ratio and combustion dynamic energy were determined from the flame monitoring system. The ignition behaviors of the coals are established by combining the parameters. Results demonstrate that the parameters are suitable for distinguishing ignition behaviors from homogeneous, hetero–homogeneous to heterogeneous in the ignition section of a drop tube furnace. The ignition behaviors of a coal blend are found to have similar characteristics as the coal of higher volatile matter in the blend and depend on its proportion in the blend. The results from this study are used to predict the operation of a coal fired power plant in terms of fuel selection, fuel blending, and flame stability. [Copyright &y& Elsevier]

Abstract: The paper takes into consideration a new approach for CO2 capture and transport, based on the formation of solid CO2 hydrates. Carbon dioxide sequestration from power plants can take advantage of the properties of gas hydrates. The formation and decomposition of hydrates from various N2–CO2 mixtures has been studied experimentally in a 2l reactor, to determine the CO2 separation in terms of hydrate composition and residual CO2 content in the reacted gas. Carbon dioxide acts as a co-former for the production of hydrates containing nitrogen, besides CO2. The mixed hydrates that are obtained are less stable than simple CO2 hydrates. When CO2 content in the flue gas is higher than 30% by volume, the hydrates formed at 5MPa are sufficiently concentrated (about 70% CO2) and carbon dioxide reduction in the reacted gas is acceptable. The application of a process based on hydrate formation could be especially interesting (for CO2 capture and transport) when connected to an oxy-coal combustion process; in this case the CO2 content in the flue gas is very high and the hydrate formation is greatly facilitated. [Copyright &y& Elsevier]

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. [Copyright &y& Elsevier]

Abstract: In the work presented in this paper, an alternative process concept that can be applied as retrofitting option in coal-fired power plants for CO2 capture is examined. The proposed concept is based on the combination of two fundamental CO2 capture technologies, the partial oxyfuel mode in the furnace and the post-combustion solvent scrubbing. A 330MWel Greek lignite-fired power plant and a typical 600MWel hard coal plant have been examined for the process simulations. In a retrofit application of the ECO-Scrub technology, the existing power plant modifications are dominated by techno-economic restrictions regarding the boiler and the steam turbine islands. Heat integration from processes (air separation, CO2 compression and purification and the flue gas treatment) can result in reduced energy and efficiency penalties. In the context of this work, heat integration options are illustrated and main results from thermodynamic simulations dealing with the most important features of the power plant with CO2 capture are presented for both reference and retrofit case, providing a comparative view on the power plant net efficiency and energy consumptions for CO2 capture. The operational characteristics as well as the main figures and diagrams of the plant’s heat balances are included. [Copyright &y& Elsevier]

Abstract: Power generation from fossil fuel-fired power plants is the largest single source of CO2 emissions. Post combustion capture via chemical absorption is viewed as the most mature CO2 capture technique. This paper presents a study of the post combustion CO2 capture with monoethanolamine (MEA) based on dynamic modelling of the process. The aims of the project were to compare two different approaches (the equilibrium-based approach versus the rate-based approach) in modelling the absorber dynamically and to understand the dynamic behaviour of the absorber during part load operation and with disturbances from the stripper. A powerful modelling and simulation tool gPROMS was chosen to implement the proposed work. The study indicates that the rate-based model gives a better prediction of the chemical absorption process than the equilibrium-based model. The dynamic simulation of the absorber indicates normal absorber column operation could be maintained during part load operation by maintaining the ratio of the flow rates of the lean solvent and flue gas to the absorber. Disturbances in the CO2 loading of the lean solvent to the absorber significantly affect absorber performance. Further work will extend the dynamic modelling to the stripper for whole plant analysis. [Copyright &y& Elsevier]

Abstract: Solid Recovered Fuels (SRF) are solid fuels prepared from high calorific fractions of non-hazardous waste materials intended to be co-fired in coal power plants and industrial furnaces (CEN/TC 343, Solid Recovered Fuels, 2003). They are composed of variety of materials of which some, although recyclable in theory, may have become in forms that made their recycling an unsound option. The SRF with an equivalent median diameter D 50 of 6.8mm are to be directly co-fired in an existing pulverised coal power plant. In comparison to pulverised coal, the particle size distribution of the SRF is of several magnitudes higher, resulting in a different burnout behaviour. Size reduction of the SRF to a fraction similar to coal is not economically feasible. As such, the idea is to co-fire SRF without any further size reduction, and of course this proceeding bears the risk of incomplete combustion. Accordingly, the prediction of the burner levels at which the SRF should be injected and whether or not a complete combustion will be achieved under full and part load conditions are the primary objectives of this paper. In this work, laboratory experiments have been conducted to forecast the success of co-firing the SRF in a commercial pulverised coal power plant. It involves the analyses of the fuel and its intermediate chars, generated at conditions comparable to boiler conditions, to determine some characteristic parameters, namely the burnout time, the aerodynamic lift velocity (ALV), and the apparent densities. The information gathered from the lab experiments are correlated to boiler conditions to determine the possible distances they are likely to travel under various regimes, full load and part load, before they are completely consumed. Different scenarios are examined, and based on the results, the optimal boiler injection points are predicted. [Copyright &y& Elsevier]

Abstract: Coal fired electric power plants produce large volumes of fly ash and other coal combustion by-products (CCBs) every year. Although almost 50% of the fly ash produced in the US is recycled for beneficial use, most of the ash material is disposed in dry landfills and ash lagoon impoundments. Fly ash may contain hazardous leachable trace elements such as As, B, Cr, Mo, Ni, Se, Sr and V which have a negative impact on the environment due to potential leaching by acid rain and groundwater with time. Many of the older CCB disposal facilities are unlined and unmonitored and as a result the EPA is currently developing national standards for monitoring CCB disposal sites. The cost to the US electric power industry could exceed one billion dollars if existing and closed CCB disposal facilities come under regulation. Thus simple, low-cost and effective in situ chemical treatment techniques are needed to stabilize hazardous leachable trace elements in the coal combustion by-product (CCB) materials. This paper reports the results of experiments designed to chemically treat fly ash with ferrous sulfate solutions to immobilize hazardous leachable trace elements after disposal. The current study is focused on three acidic and one alkaline fly ash samples collected from electric power plants located in the southeastern United States that were treated with two ferrous sulfate treatment solutions. The first treatment solution contained ferrous sulfate (FS) to give 322mg/L of dissolved iron, while the second treatment solution contained the same concentration of ferrous sulfate along with excess calcium carbonate (FS+CC) to buffer the pH. Fly ash treatment experiments were carried out at solid:liquid (S:L) ratios of 1:3 and 1:30. The effectiveness of the treatment methods was evaluated by sequentially leaching the treated and the untreated fly ash samples using a synthetic acid rain (SAR) solution (US EPA Method 1312B SPLP fluid) as the leachate. The best overall treatment result was shown by the unbuffered ferrous sulfate solution at the 1:30 S:L ratio, which substantially reduced the mobility of the oxyanion trace elements. The overall mobility reduction achieved for As was 23–72%, B mobility was reduced by 43–80%, Cr by 45–77%, Mo by 21–90%, Se by 41–85% and V by 41–53% The unbuffered ferrous sulfate treatment was not effective for immobilization of the cationic trace elements Ni and Sr. [Copyright &y& Elsevier]

Abstract: In order to reduce the CO2 emission from the coal-fired power plants, O2/CO2 recycle combustion (Oxy-combustion) technique has been proposed through combining a conventional combustion process with a cryogenic air separation process. The technique is capable of enriching CO2 concentration and then allowing CO2 sequestration in an efficient and energy-saving way. Taking into account the CO2 taxation and CO2 sale, the paper evaluates the economic feasibility of Oxy-combustion plants retrofitted from two typical existing conventional coal-fired power plants (with capacities of 2×300MW and 2×600MW, respectively) with Chinese data. The cost of electricity (COE) and the CO2 avoidance cost (CAC) are also considered in the evaluation. The COE of the retrofitted Oxy-combustion plant is nearly the same as that of the corresponding conventional plant if the unit price of CO2 sale reaches 17–22$/t (different cases). The CAC of the retrofitted 2×300MW Oxy-combustion plant is 1–3$/t bigger than that of the retrofitted 2×600MW Oxy-combustion plant. Supercritical plants are more economical and appropriate for Oxy-combustion retrofit. The result indicates that Oxy-combustion technique is not only feasible for CO2 emission control based on existing power plants but is also cost-effective. [Copyright &y& Elsevier]

Abstract: Pulverised coal-fired plants often play an important role in electricity grids as mid-merit plants that can operate flexibly in response to changes in supply and demand. As a consequence, these plants are required to operate over a wide output range. This paper presents an initial evaluation of some potential impacts of adding post-combustion CO2 capture on the part load performance of pulverised coal-fired plants. Preliminary results for ideal cases analysed using a simple high-level model indicate that post-combustion CO2 capture could increase the options available to power plant operators. In particular, solvent storage could allow higher effective plant load factors to be achieved to assist with capital recovery while still permitting flexible operation for grid support. A number of areas for more detailed analysis are identified. [Copyright &y& Elsevier]

• Life cycle VOCs emissions of coal-fired power plants in China are assessed. • Indirect VOC emissions accounted for 48.46%~68.13% of total VOC emissions. • The largest fraction of indirect emissions come from the coal mining stage. • APCDs and catalytic oxidation technology have great potential to reduce emissions. During the coal-fired power generation process, both direct and indirect volatile organic compounds (VOCs) emissions are generated and emitted, releasing aerosols and particulate matter in the atmosphere. However, the indirect VOC emissions from coal-fired power plants (CFPPs) are often ignored, which causes considerable underestimation of total VOC emissions and their polluting effects on the atmosphere and human health. In this work, for the first time, the direct and indirect VOC emissions from coal-fired power generation processes are comprehensively assessed through life cycle assessment (LCA). Results show that the VOC emissions from coal mining, coal-fired power generation systems, flue gas cleaning systems, and waste disposal systems are estimated to be 2.31E−03 to 1.10E−02, 2.24E−03 to 1.46E−02, 2.38E−03 to 2.36E−03, 1.30E−05 to 1.33E−05 kg/MWh, respectively. The life cycle VOC emissions from the coal-fired power generation process as a whole are calculated as: 1.78E−02 to 9.85E−02 kg/MWh, without considering air pollution control devices' effects (APCDs). This value is reduced to 6.95E−03 to 2.80E−02 kg/MWh if the APCDs are implemented (61–72% reduction). Indirect emissions account for 48.46%–68.13% of life cycle VOC emissions, mainly from coal mining and flue treatment system. If considering all the CFPPs in China, the value of the total VOC emissions reaches at least 3.29E+04 t in 2017, while indirect emissions are up to 2.32E+04 t. The paper also analyzes the impact of the change of key input variables on the overall VOC emissions. Based on the results, proposing possible abating measures, which can be considered by authorities and decision-makers for promoting strategies to abate VOC emissions. [ABSTRACT FROM AUTHOR]

• The effects of different kinds and contents of elements on modified sorbents performance was studied. • The formation of the solid solution improves hardness and strength of modified sorbents. • Mg2+ is a suitable doping element that can enhance the sorbent performance. • NaAlMg15 sorbent exhibit excellent attrition resistance and CO 2 capture capacity during CO 2 sorption/desorption process. The technology of removing CO 2 from coal-fired power plants by sodium-based sorbents has received increasing attention. However, the researches on sodium-based sorbents both with high CO 2 capture capacity and attrition resistance are still insufficient, which hindering the industrial applications of the sodium-based sorbent. This paper is devoted to solve this problem. Different elements, including Zr2+, Mg2+ and Ca2+, were separately doped in the sorbent and the corresponding CO 2 sorption and attrition resistance performances were studied. Under the desired doping content (1–15 wt%), Zr2+, Mg2+ and Ca2+ improved the mechanical strength of the sorbent with the order of Zr2+ < Mg2+ < Ca2+, while the corresponding CO 2 sorption capacity of the sorbent were improved with the order of Zr2+ < Ca2+ < Mg2+. NaAlMg15, with 15 wt% of Mg doping, performed good CO 2 sorption and attrition resistance due to that doping 15 wt% of Mg increased the alkaline sites and changed the cellular structure, which enhanced the strength of the sorbent. Finally, extrusion-spheronization method was used to fabricate the spherical sorbent with NaAlMg15, which exhibited excellent attrition resistance and CO 2 sorption performances. [ABSTRACT FROM AUTHOR]

• Retrofit scheme of system integration for selected solid sorbents differs. • Efficiency penalty increment is 1.4% per 1.0GJ/tCO 2 consumption. • Efficiency penalty increment is 0.67% per 10 °C regeneration temperature. • Solid amine sorbents perform the best with the lowest penalty of 9.59%. For post-combustion CO 2 capture technology, integration of CO 2 capture will lead to considerable efficiency penalty of the power plant. This paper quantitatively compares the thermal performance of the integrated system with CO 2 capture by three different solid sorbents, namely the solid amine Pentaethylenehexamine (PEHA), Na 2 CO 3 and K 2 CO 3. Due to different regeneration temperature, the retrofit schemes of the integrated system differ for three different sorbents. The back-pressure turbines are used to retrieve the surplus energy of the extracted steam for PEHA and Na 2 CO 3 , whereas multi-stage compressors are used to increase the extracted parameters for K 2 CO 3. The thermodynamic and exergy analysis results show that the thermal consumption of regeneration and the regeneration temperature are the two key parameters influencing the efficiency penalty. Efficiency penalty is increased by 1.4% per 1.0 GJ/tCO 2 increment and 0.67% per 10 °C temperature increment of regeneration. Due to a low thermal consumption of regeneration and regeneration temperature, the solid amine sorbent (PEHA) performs the best out of the three solid sorbents with the lowest efficiency penalty of 9.59%. Besides, comparison with monoethanolamine (MEA) based solvent systems (efficiency penalty of 9.66%–13.73%) shows that, the solid amine sorbent (PEHA) exhibits promising competitiveness in terms of energy consumption. [ABSTRACT FROM AUTHOR]

• Water insoluble minerals in Zhundong coal were largely removed by CO 2 -water leaching. • PM release during Zhundong coal combustion was significantly reduced. • Combustion reactivity of Zhundong coal was promoted. • CO 2 -water leaching was a feasible method to inhibit PM formation and release during Zhundong coal combustion. Zhundong coalfield is one of the core coalfields in Xinjiang, China. Due to its high alkali and alkaline earth metal (AAEM) contents, large amounts of PM were released during Zhundong coal combustion, causing serious environmental pollution. In this paper, a novel CO 2 -water leaching method was proposed to suppress the PM formation and release during Zhundong coal combustion. The results showed the CO 2 -water leaching effectively removed water insoluble minerals from coal, such as Na, Ca, Mg, Cl and S, and significantly reduced the PM formation and release during the Zhundong coal combustion, especially for submicron particle formation and release. The releases of PM 1 , PM 2.5 , PM 10 were reduced by 29.09%, 22.68% and 18.48%, respectively. The detailed characterizations showed that the significant removal of the easily vaporized elements in the coal by CO 2 -water leaching, such as Na, Ca, Mg, S and Cl, was an main factor for the suppression of PM formation and release. Besides, after CO 2 -water leaching, the combustion characteristics of Zhundong coal were promoted. Thus, the CO 2 -water leaching was a feasible method to inhibit the formation and release of PM during Zhundong coal combustion. Furthermore, since the flue gas from coal-fired power plant can be used as a source of CO 2 , the CO 2 -water leaching method provided a new way for the efficient utilization of the coal-fired flue gas. [ABSTRACT FROM AUTHOR]

In recent years, coal combustion by-products have attracted much attention because of their large production volume, adverse environmental effects of potentially toxic elements, and as potential sources of critical metals. In order to better evaluate the leaching characteristics of alkaline coal combustion by-products, the Leaching Environment Assessment Framework (LEAF) proposed by the United States Environmental Protection Agency was adopted in this study. Depending upon the properties of the samples, the test methods used in this paper mainly included Methods 1313, 1314, and 1316. The liquid-solid partitioning curves of samples were drawn according to the results of chemical analysis. Samples were collected from the coal-fired Sunzhuang Power Plant, Hebei Province, China. The leaching characteristics of coal combustion by-products are discussed from three aspects: pH values, liquid--solid ratios, and accumulated liquid-solid ratios. According to the trend of the liquid-solid partitioning curves, the modes of occurrence and causes of mobility of trace elements in the coal combustion by-products are discussed. To assess the potential environmental risk of hazardous elements leached from coal combustion by-products, the maximum leaching values of hazardous elements were compared to the upper limit value of the Type III Chinese groundwater quality standard, suggesting that in the eluates of Method 1313, arsenic, selenium, beryllium, thallium, nickel, and lead contents in the eluates of fly ash and bottom ash exceed the recommended upper limit. However, in the eluates of Methods 1314 and 1316, selenium, molybdenum, barium, and nickel exceed the recommended upper limit. [ABSTRACT FROM AUTHOR]