Coal-fired Power Plant Burning Research Articles

Combustion conditions and feed coals regulating the Fe- and Ti-containing nanoparticles in various coal fly ash.

Quantitative characteristics and sizes of nanoparticles (NPs) in coal fly ash (CFA) produced in coal-fired power plants as a function of coal type and plant design will help reveal the NP emission likelihood and their environmental implications. However, little is known about how combustion conditions and types of coal regulate the NP abundance in CFAs. In this study, based on single particle (SP)-ICP-MS technology, particle number concentrations (PNCs) and sizes of Fe- and Ti-containing NPs in CFAs were determined for samples collected from power plants of different designs and burning different types of coal. The PNCs of Fe- and Ti-containing NPs in all CFAs measured were in the range of 1.3×107 - 3.4×108 and 6.8×106 - 2.2×108 particles/mg, with the average particle sizes of 111nm and 87nm, respectively. The highest Fe-NP PNCs likely relate to the highest contents of Fe and pyrite in the feed coal. In addition, high TOC in CFAs are associated with metal-containing NPs, resulting in elevated abundances of these NPs with relatively large sizes. Moreover, elevated PNCs of NPs were found in CFAs produced by coal-fired power plants burning low-rank coals and with small installed capacity (especially those under 100-MW units). Compared to cyclone filters, ESPs and FFs with higher removal efficiency typically retain more Fe-/Ti- containing NPs with smaller sizes. Based on a structural equation (SE) model, raw coal properties (coal rank and Fe/Ti content), boiler types, and efficiency of particulate emission control devices likely indirectly affect PNCs of Fe- and Ti-containing NPs by influencing TOC contents and their corresponding metal concentrations of CFAs. This study provides the first analytic and comprehensive information concerning the direct and indirect regulating factors on NPs in various CFAs.

Rare earth elements in deposited hard coal fly ash in Poland

Rare Earth Elements (REEs), due to their unique properties, are nowadays a desirable raw material, especially in the development of modern technologies. This paper describes a 4-step research methodology for the task of identifying the potential for REE recovery in landfilled fly ash. A literature analysis was performed on their significance, occurrence in both primary and secondary deposits. Opportunities for REE recovery from coal fly ash in conventional power plants were identified and selected technologies were described. Poland, as a country whose energy sector is to a large extent based on coal, has a potential in this respect. Taking into account studies of the Polish Central Statistical Office (GUS) and forecasts of the Polish energy policy, the article determines the approximate value of REE in the waste stream from coal-fired power plants burning hard coal.

Study on the mercury emission and transformation in an ultra-low emission coal-fired power plant

Mercury emissions from a Chinese ultra-low emission (ULE) coal-fired power plant burning a low chlorine and sulfur bituminous coal was investigated by using the Ontario Hydro method (OHM). A temperature-programmed decomposition desorption (TPDD) instrument, scanning electron microscope (SEM), and X-ray power diffraction spectrometry (XRD) were used to identify the mercury species, apparent morphology, and chemical composition of the coal and combustion by-products. As measured by the OHM, the elemental mercury emitted from the stack is the largest proportion of the total mercury (about 38.95%), almost 13times more than the oxidized mercury. Mercury in bottom ash was found to be only 0.07% of the incoming total mercury. The elemental mercury was found to oxidize across the SCR, with 45.47% converted to oxidized mercury. This increase in mercury oxidation is significant, as it was shown to be removed by the WFGD system. The total mercury removed across all APCDs in order of most to least was WFGD>ESP>WESP. The WESP was shown to further remove mercury, whose removal rate is about 13.63%, resulting in lower mercury stack emissions. For this plant arrangement, the mercury emission factor was calculated to be 1.56g/1012J, less than the mean value of Chinese plants. The mercury content in the gypsum is higher than the limit (0.50mg/kg) while bottom and ESP ash were shown to have no effect on the soil. Further investigation of thermal treatment on mercury in gypsum is needed before definitive conclusions on disposal can be drawn. Concentration of mercury measured in the WFGD and WESP waste water is higher than the limit (0.001mg/L), and more importance should be given on the waste water from WFGD.

Improvement of the Activity of γ-Fe2O3 for the Selective Catalytic Reduction of NO with NH3 at High Temperatures: NO Reduction versus NH3 Oxidization

Lignite is widely used as the fuel for coal-fired power plants, and its flue gas temperature is about 50–100 °C higher than others. V2O5–WO3/TiO2 is extremely restricted in the selective catalytic reduction (SCR) of NO from the coal-fired power plants burning lignite due to the drop of NOx conversion, low N2 selectivity, and volatility of vanadium pentoxide at high temperatures. Therefore, a more environmental-friendly SCR catalyst with excellent SCR activity and better N2 selectivity at 350–450 °C should be developed for this application. In this work, sulfated Fe–Ti spinel catalyst was developed for the SCR of NO from the coal-fired power plants burning lignite. The drop of NOx conversion at high temperatures was mainly related to the simultaneous occurrence of the catalytic oxidization of NH3 to NO during the SCR reaction. Ti was incorporated into γ-Fe2O3 to decease the oxidization ability of Fe3+ on the surface, and the sites for −NH2 adsorption and the active components for −NH2 oxidization were separated after the sulfation to decrease the probability of the collision between −NH2 adsorbed and Fe3+ on the surface. They both inhibited the catalytic oxidization of NH3 to NO over γ-Fe2O3. However, the SCR reaction over γ-Fe2O3 was simultaneously restrained after the incorporation Ti and the sulfation. Therefore, NOx conversion over γ-Fe2O3 at high temperatures depended on the ratio of NH3 conversion through the catalytic oxidization of NH3 to NO to that through the SCR reaction. This ratio decreased after the incorporation of Ti, and it further decreased after the sulfation, resulting in an obvious promotion of NOx conversion at high temperatures. Therefore, sulfated Fe–Ti spinel showed excellent SCR activity, N2 selectivity, and H2O+SO2 durability at 300–450 °C, which was suitable for the application in the coal-fired power plants burning lignite.

HEN optimization for efficient retrofitting of coal-fired power plants with post-combustion carbon capture

This study aims at reducing the energy penalty burdened by integration of pulverized coal-fired power plants with solvent-based post-combustion carbon capture (PCC) processes via heat exchanger network (HEN) optimization. The base case used is a 300 MWe coal-fired power plant burning pulverized black coal and emitting 256 tonnes/h of CO 2. Integration of the base case with PCC showed that achieving 90% CO 2 capture with purity of 99% using 30 wt% monoethanolamine (MEA) solvent admits an energy penalty of 19.4% to the overall plant output. Pinch analysis showed that a reduction in the mentioned energy penalty down to 15.9% can be achieved via integration.

유연탄 발전소에서의 PM 및 PM2.5 배출특성

Particles emitted from three coal-fired power plants burning bituminous and sub-bituminous coals were examined for PM and size fractions PM¤2.5 and PM2.5. The ratio of PM2.5/PM was ranged from 10 to 62%, and PM emission increased with the amount of coal feed, which was 7.23~15.66 kg/h. The emission range of PM2.5 from three power plants was 1.24~4.48 kg/h (dry), which was function of the mixed rate of viscous sub-bituminous coal in feed. Of course such effect should be examined by further tests in details. Based on the consumed coal and thermal load, the emission factors averaged were shown as 59.03 g-PM/ton-coal, 14.79 g-PM2.5/ton-coal and 22.51 g-PM/MWh, 5.54 g-PM2.5/MWh, respectively.

Novel Mercury Oxidant and Sorbent for Mercury Emissions Control from Coal-fired Power Plants

The authors have successfully developed novel efficient and cost-effective sorbent and oxidant for removing mercury from power plant flue gases. These sorbent and oxidant offer great promise for controlling mercury emissions from coal-fired power plants burning a wide range of coals including bituminous, sub-bituminous, and lignite coals. A preliminary analysis from the bench-scale test results shows that this new sorbent will be thermally more stable and cost-effective in comparison with any promoted mercury sorbents currently available in the marketplace. In addition to the sorbent, an excellent elemental mercury (Hg(0)) oxidant has also been developed, and will enable coal-fired power plants equipped with wet scrubbers to simultaneously control their mercury emissions as well as their sulfur oxides emissions. This will work by converting all elemental mercury to an oxidized form which will be removed by the wet scrubber. This will result in significant cost savings for mercury emissions control to the atmosphere, and will help in keeping electric costs low. The sorbent and oxidant will benefit from the utilization of a waste stream from the printed circuit board (PCB) industry, and would thus be environmentally beneficial to both of the utility and electronics industries. The sorbent also demonstrated thermal stability up to 350°C, suggesting a possibility of an application in pulverized coal-fired power plants equipped with hot-side electrostatic precipitators and coal gasification plants.

Comparison of calculated mercury emissions from three Alberta power plants over a 33 week period – Influence of geological environment

Feed coals and fly ashes from two coal-fired power plants burning Alberta subbituminous coal were analyzed for C, Cl, Hg, and S and calorific values (for feed coal only), every week for a period of 33 weeks. The feed coals used in this study were deposited in brackish water and are compared to the coals deposited in a freshwater environment. The Hg and char (unburnt carbon) content of the fly ash was monitored to determine the variation of Hg and its possible relationship to the char types in the fly ash. The feed coals have Hg content of 0.026–0.089 mg/kg and their fly ash contains 0.02–0.243 mg/kg of Hg. The C content of the fly ashes ranges from 0.15% to 0.51%. The carbon/char was separated from the fly ash using HF and HCl. Reactive vitrinitic (formed from woody part of plants) and less reactive inertinitic (natural char) chars were separated by density separations of various specific gravities using ZnBr 2. The char is mostly reactive vitrinitic (67–80 vol.%). Both stations have similar range of C content for their respective fly ashes. However, station 2 shows a much wider range of Hg in fly ash compared to station 1. In general, the fly ash from coal deposited under brackish water environment (stations 1 and 2) appears to have same or higher Hg content for lower C content compared to the fly ash from coal deposited under fresh water environment. The calculated emitted Hg for the period of 33 weeks for station 1 is estimated to be 64–90% of the total input of Hg with an average of 74%. The calculated emitted Hg shows a more complex pattern for station 2 and falls into two groups; with group (a) showing higher enrichment index for both Hg and S. The calculated emitted Hg for this group is 43–74% with an average of 57%, indicative of more Hg being captured by fly ash, possibly due to interaction between Hg and S. In the second group (b) the emitted Hg is calculated to be 74–95% with an average of 85%. The relative enrichment of both Hg and S in group (b) is low compared to group (a), indicative of possible slight paleo-weathering of the feed coal. The present study indicates that geological parameters such as paleo weathering and also depositional environment of the feed coal may influence the Hg content of fly ash.

Morphology and chemistry of fine particles emitted from a Canadian coal-fired power plant

Particles emitted from coal-fired power plants burning subbituminous coal from Alberta, Canada were examined for total particulates (PM) and size fractions PM >10, PM 10, and PM 2.5. The sampling was carried out following EPA Method 201A. Three tests were performed at each station. The emitted particles were examined using SEM/EDX and gravimetric method for the determination of their sizes. The elemental composition of particles was determined using INAA and ICP-MS. The particles emitted from the stack are classified based on their morphologies and chemistries to the following: unburnt carbon, feed-coal minerals such as quartz, and by-products of the dissociation, fractionation, and contamination by minerals in coal. The emitted particles are mostly spherical and their matrices are composed of aluminosilicate minerals containing calcium. The PM >10 fraction contains small plerospheres, fragments of char, and angular quartz and feldspar particles. The PM 10 fraction contains solid spheres and cenospheres, gypsum needles, and particles of char. The PM 2.5 particle size fraction is mostly composed of solid spherical aluminosilicates with some surface enrichment of elements such as Ba, Ca, and Fe. The composition of emitted particles is ferrocalsialic. Most elements in the particle size fractions are Class I or II, such as Al, Ca, and Fe. Cd, Cu, Mo, and Ti were only detected in PM 2.5 fraction.

The rates of emissions of fine particles from some Canadian coal-fired power plants

Particles emitted from three coal-fired power plants burning subbituminous coals from Alberta, Canada were examined for total particulate matter (PM) and size fractions PM >10, PM 10, and PM 2.5. The sampling was carried out following EPA Method 201A, which requires a 6 inch port. Three tests were performed at each station. The rates of emitted particulates from the three power plants are 9.9–53.4 mg/m 3 (dry), 30–90 kg/hr (dry), and 0.039–0.118 kg/MWh, respectively. The emission rates of the various particle sizes for these three power plants are 8.7–39.5 kg/hr of PM >10, 10.7–40.8 kg/hr of PM 10, and 9.65–10.7 kg/hr of PM 2.5. The present results indicate that 29–44% of emitted particles are PM >10. The total emissions of particulates from two power plants are below the Canadian Guideline for emission from a coal-fired power plant (0.095 kg/MWh), while the third power plant is slightly higher than the Guideline (0.118 kg/MWh). The malfunctioning of control technology may result in unrealistic and wide variation in the measured rates of emitted particles.

A Simple Two-Reactor Method for Predicting Distribution of Trace Elements in Combustion Systems

Utilization of fossil fuels in energy production results in emissions of pollutants. Development in combustion technology has, however, during recent years focused on decreasing emissions of particulates, sulfur, and nitrogen oxides. In addition, combustion also includes a potential risk for emission of trace metals. Due to the fact that many trace elements have been identified as having a negative effect on human health and the natural environment, they have received special attention from a regulatory point of view. This paper describes a simple method for predicting the fate of eight trace elements (As, Cd, Hg, Ni, Pb, Se, V, and Zn) in combustion processes. Using the fuel composition and power plant operating conditions, the trace element concentrations in various ashes and the flue gas are determined. The method, which is based on a global equilibrium approach, describes the overall behavior of the eight trace elements successfully. Distribution/partitioning of the trace elements between the bottom ash, fly ash, and the flue gases is described and compared to measured data from a full-scale coal-fired power plant burning bituminous coal. The outcome from the prediction is actual concentrations of trace elements in main power plant streams.

An evaluation of autotrophic microbes for the removal of carbon dioxide from combustion gas streams

Carbon dioxide is a greenhouse gas that is believed to be a major contributor to global warming. Studies have shown that significant amounts of CO 2 are released into the atmosphere as a result of fossil fuels combustion. Therefore, considerable interest exists in effective and economical technologies for the removal of CO 2 from fossil fuel combustion gas streams. This work evaluated the use of autotrophic microbes for the removal of CO 2 from coal fired power plant combustion gas streams. The CO 2 removal rates of the following autotrophic microbes were determined: Chlorella pyrenoidosa, Euglena gracilis, Thiobacillus ferrooxidans, Aphanocapsa delicatissima, Isochrysis galbana, Phaodactylum tricornutum, Navicula tripunctata schizonemoids, Gomphonema parvulum, Surirella ovata ovata, and four algal consortia. Of those tested, Chlorella pyrenoidosa exhibited the highest removal rate with 2.6 g CO 2 per day per g dry weight of biomass being removed under optimized conditions. Extrapolation of these data indicated that to remove CO 2 from the combustion gases of a coal fired power plant burning 2.4 × 10 4 metric tons of coal per day would require a bioreactor 386 km 2 × 1 m deep and would result in the production of 2.13 × 10 5 metric tons (wet weight) of biomass per day. Based on these calculations, it was concluded that autotrophic CO 2 removal would not be feasible at most locations, and as a result, alternate technologies for CO 2 removal should be explored.