Search

Semi-dry flue-gas desulfurization (FGD) processes abate 99% of atmospheric emissions of sulfur dioxide from coal-fired power plants at the expense of producing daily tones of solid FGD residues containing sulfites, sulfates, carbonates and hydroxides of calcium and magnesium, besides fly-ashes. In this work, a fluidized-bed reactor pilot plant was used for experiments of dry-oxidation of FGD residues aiming at converting sulfites into sulfates in order to upgrade such residues for utilization as raw material to the cement industry. A two-dimensional design of experiments on the plane of feed air temperature and reactor time-on-stream was conducted in the pilot plant generating sulfite conversion data and transient reactor temperature profiles. These data were used for estimating the first-order kinetic parameters of sulfite conversion via non-linear regression following the Maximum Likelihood Principle. The optimized Arrhenius factor and Arrhenius activation energy obtained via the Nelder–Mead Flexible Simplex method were, respectively, 0.001 mol/kg.s.bar and 14146.5 J/mol. This kinetic model allows designing large-scale plants for treatment of semi-dry FGD residues in order to beneficiate it for utilization in the cement industry, avoiding the disposal and environmental costs of landfilling such residues.

In this paper, SOX (SO2 and SO3) removal and emission characteristics of wet limestone-gypsum flue gas desulfurization (WFGD) are investigated based on the data collected from 95 ultra-low emission coal-fired power units. The study shows that the overall removal efficiency of single-absorber is above 97.5%, in which the SO3 removal efficiency is between 31% and 70%. When the inner structures are installed into the spray absorber, the correlation between the inlet SO2 concentration and SOX removal efficiency becomes more obvious, however, with a tray absorber, the maximum SO2 removal efficiency of double-absorber reaches 99.74%, in which the SO3 removal efficiency is between 27% and 81%. With a normal spray absorber, the higher inlet concentration, the higher removal efficiency it reaches, while with a tray absorber, the result is opposite. With a single-absorber, there is little correlation between flue gas temperature drop and SO2 removal efficiency. Large temperature drop harms the improvement of overall SO2 removal efficiency but is beneficial to SO3 removal. By the calculation of SOX emission performance model, average emission performances of SO2 and SO3 are acquired, which are about 90–107 mg/(kW·h) and 81–97 mg/(kW·h), respectively.

The correct conduction of the CO2 capture process in coal-fired power plants with the use of monoethanolamine (MEA) requires constant process parameter monitoring and ensuring a specific flue gas chemical composition. One of the most common problems in these types of installations is the progressive corrosion and degradation of the valuable solvent. Despite the established reduction levels of oxygen and impurities entering into irreversible reactions with the absorber, the flue gas composition may change as a daily and annual function of time. The article presents a detailed analysis of the flue gas components that have the greatest influence on carbon dioxide capture installation technical safety, i.e., SOx, NOx, O2, and fly ash. The analysis was based on the results of experiments conducted at the Jaworzno III Tauron Wytwarzanie SA Polish coal power plant. The results show a significant influence of the flue gas desulfurization (FGD) process on MEA oxidative degradation. The amount of oxygen in flue gas during biomass and coal blend co-firing was nearly twice as low compared to pure coal combustion. Differences were also observed in the amounts of gas impurities with relation to the time of year and time of day of power plant operation.

Marginal abatement cost (MAC) plays an essential role in pricing pollutants and guiding environmental policies. Considering the heavy polluting nature of China’s coal power industry, this paper aims at providing companies and policymakers with more comprehensive information on the cost of abatement by estimating the MACs of CO2 and SO2 for coal-fired power plants (CFPPs) in China. This study contributes to the literature by considering an interconnected two-stage production system to investigate. The estimation framework is advanced in combining the electricity production and pollution abatement process of CFPPs into a convex quantile regression (CQR) model. The results show that the averages of MAC for CO2 and SO2 are estimated to be 367.56 Yuan/ton and 662.30 Yuan/ton, respectively, indicating that the reduction of such emissions is still costly. The heterogeneous analysis then indicates that large CFPPs, central-government-owned power plants (CGOPPs), and low-regulated CFPPs tend to possess lower MACs for CO2. Regarding SO2, large and medium-sized power plants show significantly larger MACs than small plants. In addition, the MACs of SO2 for CGOPPs and high-regulated CFPPs are more concentrated at high levels. In the second part, the Tobit regression analysis was used to discuss the determinants of MACs for CO2 and SO2. Factors like carbon emission intensity, load, and operating hours can notably decrease MACs for CO2, while MACs for SO2 tend to be positively affected by the total abatement cost and the abatement rate of the FGD equipment. In addition, the MACs for the large CFPPs, CGOPPs, and high-regulated CFPPs are more likely to be affected by the selected influence factors. Based on these results, we conclude with some policy recommendations.

This paper is effectively a scenario analysis of the energy system of Bosnia and Herzegovina (BiH) from the perspective of the possible future reduction of greenhouse gas (GHG) emissions in the power generation sector, with the aim to become climate neutral by 2050, in compliance with the Green Agenda for the Western Balkan. According to the data from 2016, the share of power generation in the total GHG emissions in BiH was approximately 50%. By using the LEAP (Long-range Energy Alternatives Planning) energy model, two scenarios—the “gradual transition scenario” and the “climate neutral” scenario—have been analyzed for the period 2018–2050, and each scenario included decarbonization measures such as the extensive use of Renewable Energy Sources (RES). Unlike the climate neutral scenario, the gradual transition scenario includes the replacement of certain parts of the old, currently-in-operation Coal-fired Power Plants (CFPPs) with the new CFPP, which is more efficient. In the climate-neutral scenario, that part of the existing CFPPs is replaced by a mix of RESs. The results from the first scenario suggest that the share of CFPPs in electricity generation has gradually decreased from 69.3% to 16.3% in 2050, and CO2 emissions from the power generation sector in 2050 will be 2.2 million tons—roughly 83.5% less than in 2014. According to the second scenario, the emphasis is strongly on the growth and promotion of RESs, which have significantly taken over the roles of major producers of electricity, encouraging the low-carbon development of BiH. Analysis results show that, in 2050, there will be no CO2 emissions from power generation. It can be concluded that specifically designed energy models for the optimization of capacities and CO2 emissions through convergence towards RESs could be an optimistic and promising option for BiH to become climate neutral while meeting increasing energy demands. The results show the required RES capacities needed for achieving climate-neutral power generation by 2050, with the current rate level of power generation. Based on the results, RES investment needs can be estimated. Overall, the results of the scenarios can be used for the strategic planning of the power generation sector in BiH until 2050.

The scale of waste formation from coal-fired generation is significant and tends to grow steadily in the context of the global use of coal for power production. This paper covers the problems and current opportunities for recycling coal fly ash waste from coal generation from the position of a stakeholder approach, namely, identification of the main participants and determination of the effects for economic agents in coal fly ash recycling projects. Based on the method of economic modeling and the empirical assessment of project efficiency, this paper presents alternative patterns of stakeholder interaction in the process of implementing coal fly ash recycling projects, estimates the effects of using coal fly ash, and identifies conflicting interests between stakeholders. It is shown that the reason behind the low interest of the Russian private sector in the processing of coal fly ash is the lack of stimulating market mechanisms for manufacturers and consumers of ash products, the high risks of implementing recycling projects based on clean coal technologies, and low environmental payments for commercial companies.

Global and European ambitions to reduce CO 2 emissions with the aim of mitigating climate change are driving the increasing closure of lignite-fired power plants. The reason for their closure is the extremely poor quality of lignite as an energy source, the combustion of which produces significant amounts of CO2 , and harmful and dangerous compounds, which can significantly endanger human health. The harmfulness of lignite is especially visible in the countries of the Western Balkans. In 2020 alone, coal-fired power plants in these countries emitted 2.5 times more SO 2 than all other coal-fired power plants within the European Union. The highest emissions were recorded in Serbia, whose thermal power plants discharged about 333 tons of SO2 in 2020, which is more than 221 thermal power plants in the European Union. The largest single polluter was the thermal power plant in Ugljevik in Bosnia and Herzegovina, which discharged about 107 tons of SO2 in 2020, which is more than all coal-fired power plants in Germany. An additional problem is that 90% of such plants in the Western Balkans are those older than 30 years (Kunert et al., 2021). Across Europe, it has been decided to abandon coal use by 2030 for those countries that have not yet done so (Figure 1), and only Germany and the Czech Republic have announced a later year of abandonment. Although the countries of the Western Balkans do not follow this trend and do not show determination to reduce its use, this paper presents possible scenarios for abandoning the use of lignite in relation to maintaining the existing situation and continuing its use.

In this paper, an improved system to efficiently utilize the low-temperature waste heat from the flue gas of coal-fired power plants is proposed based on heat cascade theory. The essence of the proposed system is that the waste heat of exhausted flue gas is not only used to preheat air for assisting coal combustion as usual but also to heat up feedwater and for low-pressure steam extraction. Air preheating is performed by both the exhaust flue gas in the boiler island and the low-pressure steam extraction in the turbine island; thereby part of the flue gas heat originally exchanged in the air preheater can be saved and introduced to heat the feedwater and the high-temperature condensed water. Consequently, part of the high-pressure steam is saved for further expansion in the steam turbine, which results in additional net power output. Based on the design data of a typical 1000 MW ultra-supercritical coal-fired power plant in China, an in-depth analysis of the energy-saving characteristics of the improved waste heat utilization system (WHUS) and the conventional WHUS is conducted. When the improved WHUS is adopted in a typical 1000 MW unit, net power output increases by 19.51 MW, exergy efficiency improves to 45.46%, and net annual revenue reaches USD 4.741 million while for the conventional WHUS, these performance parameters are 5.83 MW, 44.80% and USD 1.244 million, respectively. The research described in this paper provides a feasible energy-saving option for coal-fired power plants.

Since the beginning of the 1990s, due to international regulations on air quality, a large number of flue gas desulphurisation (FGD) installations have been constructed in the Polish coal-fired power industry. Thanks to that, SO2 capture in this industry increased to ca. 90%. Since wet lime or fluidized bed boilers were mostly used for FGD purposes, a significant increase in the domestic demand for lime sorbents has been reported. Between 1994 and 2019, it has increased from virtually zero before 1994 to about 3.3–3.4 million tpy (tonnes per year) today. On the basis of official governmental data and completed surveys of the Polish power companies, the paper analyses the process of the implementation of FGD in Poland along with limestone sorbents consumption and FGD gypsum production in the Polish coal-fired power plants. It also presents the current and potential limestone resource base for production of limestone sorbents applied in FGD. Electric energy mix in Poland is expected to be changed radically in the coming 30 years. Share of coal-based electricity is still very high—ca. 80%—and it will remain dominant for at least next decade. With the next coming FGD installations, further moderate increase of limestone sorbents consumption is expected, up to 3.7 million tpy in 2030. After 2030, a significant, quick decrease of share of coal-fired electricity is expected in Poland, down to max. 30% just before 2050. This will result in a gradual decrease in limestone sorbent demand, to max. 1.3 million tpy before 2050 and virtually zero after 2050, which will be followed by collapse of FGD gypsum production.

CO2 capture and peak shaving are two of the main challenges for coal-fired power plants in China. This paper proposed a calcium looping (CaL) combustion system with cryogenic O2 storage for simultaneous flue gas decarbonization and peak shaving for a 1000 MWe coal-fired power plant. The philosophy of this concept is that: (1) the boiler always operates at maximum continuous rating (MCR) to ensure the highest boiler efficiency; (2) during off-peak times, the excess energy output from coal combustion is used to provide heat for the calciner and produce pure oxygen for energy storage; (3) at peak times, the O2 produced is used to capture CO2 in the flue gas via the CaL process and reduce the CO2 abatement penalty; and (4) any excess O2 is treated as a by-product for commercial utilization. The whole system was simulated in Aspen Plus® which shows that the net electric efficiency of the proposed system without cryogenic O2 storage system is 35.52%LHV (LHV, low heating value), while that of the conventional CaL system is 34.54%LHV. The proposed system can reduce the methane consumption rate by 38.5 t/h when methane is used as fuel in the calciner. Including the cryogenic O2 storage system, the peaking capability of the proposed system can range from 534.6 MWe to 1041 MWe. Correspondingly, the net electric efficiency is improved from 18.98%LHV to 36.97%LHV. Increasing the rate of oxygen production can reduce the minimum net power output to lower than 534.6 MWe. The peaking capability can be regulated by the rate of oxygen production where excess oxygen serves as a byproduct.

For the envisaged large number of commercial-scale carbon capture and storage (CCS) projects that are to be implemented in the near future, a number of issues still need to be resolved, the most prominent being the large capital and operational costs incurred for the CO₂ capture and compression process. An economic assessment of the capture and compression system based on optimal design data is important for CCS deployment. In this paper, the parametric process design approach is used to optimally design coal and natural gas monoethanolamine (MEA)-based post-combustion CO₂ absorption–desorption capture (PCC) and compression plants that can be integrated into large-scale 550 MW coal-fired and 555 MW natural gas combined cycle (NGCC) power plants, respectively, for capturing CO₂ from their flue gases. The study then comparatively assesses the energy performance and economic viabilities of both plants to ascertain their operational feasibilities and relative costs. The parametric processes are presented and discussed. The results indicate that, at 90% CO₂ capture efficiency, for the coal PCC plant, with 13.5 mol.% CO₂ in the inlet flue gas, at an optimum liquid/gas ratio of 2.87 kg/kg and CO₂ lean loading of 0.2082 mol CO₂/mol MEA, the CO₂ avoidance cost is about $72/tCO₂, and, for the NGCC PCC plant, with 4.04 mol.% CO₂ in the inlet flue gas, at an optimum liquid/gas ratio of 0.98 kg/kg and CO₂ lean loading of 0.2307 mol CO₂/mol MEA, the CO₂ avoidance cost is about $94/tCO₂.

Background While there are plenty of studies investigating the market penetration of new technologies, phase-out processes of a predominant technology are rarely analyzed. The present study explores the case of a declining technology, employing the example of coal-fired power plants in Germany. These plants were promoted by governmental decision-makers as well as by the industry for a long time, but meanwhile, the phase-out or at least a cutback of coal-fired power plants is––not only in Germany––considered to be a key strategy for the transformation towards a sustainable society. Methods We investigate potential pathways of the future development of the coal-fired power plant sector in an extended multi-level perspective (MLP) framework that integrates economic, social, political, and technical aspects. Results Taking into account the fact that coal is losing its support from several important stakeholders (e.g., governmental decision-makers, utilities) due to, e.g., changes in the prioritization of political goals, changes in the economic framework, in actor constellations, and in public attitudes, coal-fired power plants tend to be pushed into niches or to disappear completely. Conclusions A reasonable management of the niche technology “coal-fired power plants” could include a protection of space for ensuring a smooth removal of the links between the regime and the technology with respect to, e.g., social and environmental aspects. The phase-out pathways for the coal-fired power plants elaborated on in this paper help to better inform policy-makers to design transformation processes not only for coal-fired power but also for other declining technologies.

Many governments aim to reduce the dependence on coal-fired generation to decrease carbon emissions. At the same time power markets with competition between independently operating power firms have been created which leave the actual decisions concerning electricity production to these firms. This paper analyzes the interaction between climate policies and policies to foster power markets. Using hourly plant-level data on the Dutch power market over 2006-2014, we find that the dispatch of fossil-fuel power plants is strongly influenced by relative fuel prices, despite the existence of several climate policy measures. Coal-fired power plants have become more important in the Dutch market since 2006, not only in share of total production, but also as provider of flexibility. Examining the short-term dispatch decisions and the past volatility in relative fuel prices, the maximum CO2 price which was needed to provide incentives for power producers to dispatch a gas-fired plant instead of a coal-fired plant was 43 euro/ton. We conclude that internalizing the external (CO2) costs by raising the CO2 price is a more appropriate measure than a forced closure of coal-fired power plants to align the principles of a market-based power industry and the wish to implement effective climate-policy measures at relatively low costs.

For the envisaged large number of commercial-scale carbon capture and storage (CCS) projects that are to be implemented in the near future, a number of issues still need to be resolved, the most prominent being the large capital and operational costs incurred for the CO2 capture and compression process. An economic assessment of the capture and compression system based on optimal design data is important for CCS deployment. In this paper, the parametric process design approach is used to optimally design coal and natural gas monoethanolamine (MEA)-based post-combustion CO2 absorption&ndash, desorption capture (PCC) and compression plants that can be integrated into large-scale 550 MW coal-fired and 555 MW natural gas combined cycle (NGCC) power plants, respectively, for capturing CO2 from their flue gases. The study then comparatively assesses the energy performance and economic viabilities of both plants to ascertain their operational feasibilities and relative costs. The parametric processes are presented and discussed. The results indicate that, at 90% CO2 capture efficiency, for the coal PCC plant, with 13.5 mol.% CO2 in the inlet flue gas, at an optimum liquid/gas ratio of 2.87 kg/kg and CO2 lean loading of 0.2082 mol CO2/mol MEA, the CO2 avoidance cost is about $72/tCO2, and, for the NGCC PCC plant, with 4.04 mol.% CO2 in the inlet flue gas, at an optimum liquid/gas ratio of 0.98 kg/kg and CO2 lean loading of 0.2307 mol CO2/mol MEA, the CO2 avoidance cost is about $94/tCO2.

© 2017 Elsevier B.V. China's economy has entered a “new normal,” characterized by slower economic growth and widespread overcapacity in its industrial sectors. Nevertheless, construction of power plants, especially coal-fired plants, continues at a rapid pace. Our analysis examines the extent of overcapacity in China's regional electricity grids. We show that already in 2014, the average reserve margin across China's regional grids was roughly 28%, almost twice as high as a standard planning reserve margin in the U.S. In addition, we find large variations in reserve margins across regional power grids in China, with the highest reserve margin (64%) in the Northeastern grid. This paper examines future reserve margins across regions in China under three growth scenarios. The results suggest that the majority of China will not need new baseload coal power (at least for reliability purposes) before 2020, and potentially not until 2025, under the low- and mid-growth scenarios. Under the high-growth scenario, China's central and eastern regions will need to import more power or built new capacity by 2020. As China's energy sector enters this new normal, our results highlight the growing importance of establishing mechanisms — planning processes and markets — that coordinate generation and transmission investments across grid regions, and that align the country's energy sector investments with its longer-term air quality and climate goals.

China’s economy has entered a “new normal,” characterized by slower economic growth and widespread overcapacity in its industrial sectors. Nevertheless, construction of power plants, especially coal-fired plants, continues at a rapid pace. Our analysis examines the extent of overcapacity in China’s regional electricity grids. We show that already in 2014, the average reserve margin across China’s regional grids was roughly 28%, almost twice as high as a standard planning reserve margin in the U.S. In addition, we find large variations in reserve margins across regional power grids in China, with the highest reserve margin (64%) in the Northeastern grid. This paper examines future reserve margins across regions in China under three growth scenarios. The results suggest that the majority of China will not need new baseload coal power (at least for reliability purposes) before 2020, and potentially not until 2025, under the low- and mid-growth scenarios. Under the high-growth scenario, China’s central and eastern regions will need to import more power or built new capacity by 2020. As China’s energy sector enters this new normal, our results highlight the growing importance of establishing mechanisms — planning processes and markets — that coordinate generation and transmission investments across grid regions, and that align the country’s energy sector investments with its longer-term air quality and climate goals.

This paper provides a preliminary assessment on how CCS-Ready technology can contribute to reduce CO2 emissions from new fossil fuels coal fired power plants and to describe what is its current status in the region of Western Macedonia in Northwestern Greece. The development of the new Unit V of Ptolemais plant is discussed in order to decide if the investment costs of retrofitting at some later point in time depend on the initial design phase of the coal fired power plant and can be reduced by a CCS-Ready installation. Another critical item is whether it is preferable to install CCS Ready technology right away or to wait when the full privatization of the Greek Public Power Corporation will proceed. This study analyses the Greek prospects to store significant quantities of CO2 emissions from the local coal fired power plants in the Prinos depleted offshore oil-field deep saline aquifers

This paper estimates indirect benefits of improved air quality induced by hydraulic fracturing, or "fracking". The recent increase in natural gas supply led to displacement of coal-fired electricity by cleaner natural gas-fired generation. Using detailed spatial panel data comprising the near universe of US power plants, we find that coal generation decreased by 28%. Further, fracking decreased local air pollution by an average of 4%. We show that benefits vary geographically; air pollution levels decreased by 35% in the most affected region. Back of the envelope calculations imply accumulated health benefits of roughly $17 billion annually.

The coal-fired power plants have a common characteristic for high consumption of coal and water resource. It is significantly valuable that how to realize this technique of deep condensation of water vapor from flue gases after desulfurizer for power plants of water shortage areas. In this paper, the effect of different factors on the overall heat transfer coefficient for fluoroplastic heat exchanger (FHE) is investigated by using the theoretical and experimental method. Based on the lab-scale research, the pilot scale tests for FHE are performed in a 600MW lignite-fired power plant of Inner Mongolia. And then the engineering application of FHE has been realized in a 630 MW coal-fired power plant of Changzhou. The results show that the overall heat transfer coefficient for FHE is calculated using this method considering the convection, conduction and condensation heat transfer, which is agreed well with one obtained by experimental measurements. The heat transfer coefficient for heat exchangers is increased with the thermal conductivity of pipe materials less than 15W/(m·K). But when the pipe material with heat conductivity is greater than 15W/(m·K), enhancing the flue gas velocity is a better approach to increase the heat transfer coefficient. The fluoroplastics are selected as the materials for the heat exchangers, due to the high overall heat transfer coefficient of 190W/(m2·K), good corrosion resistance and abrasion resistance. For the pilot scale tests in a 600MW power plant, it is found that the recovery efficiency of water by installing FHE is gradually increased with an increase in cooling water velocity and a decrease in flue gas velocity. The optimized recovery water region where the flue gas velocity was less than 4.5m/s and the cooling water velocity was larger than 0.22m/s, the recovery efficiency of water was higher than 70%. The recovering yield of water from flue gases obtained by condensation was nearly equivalent for supplemental water from desulfuration system. The recovery water after treatment is well recommended as the supplemental water for desulfurizer, to realize the zero water consumption for desulfuration system in power plants. Based on the results for lab-and pilot-scale tests, the large FHE device has been put into operation in a 630MW coalfired power plant, the recovery efficiency of water is higher than 90% under different power loads.

This paper presents the result of research on the cost-effectiveness of emission reduction in the selected coal-fired power plants (CFPPs) in Indonesia. The background of this research is the trend of more stringent environmental regulation regarding air emission from coal-fired power plants (CFPPs) in Indonesia. One consequence of stringent air emission regulation is the increase of air pollution control costs. This research provides recommendations for PLN, the state electricity company in Indonesia regarding the cost-effectiveness of reducing air emission from CFPPs in order to comply with an upcoming stringent environmental regulation. Four CFPPs were selected as research units of which two units represent large-scale CFPPs while the other two units represent small-scale CFPPs. A cost-engineering model i.e. CUEcost model is employed to estimate the abatement costs. Pollution control technologies were considered with respect to time, allocation across various scales of production unit and with respect to technological progress.

This paper presents the result of research on the cost-effectiveness of emission reduction in the selected coal-fired power plants (CFPPs) in Indonesia. The background of this research is the trend of more stringent environmental regulation regarding air emission from coal-fired power plants (CFPPs) in Indonesia. One consequence of stringent air emission regulation is the increase of air pollution control costs. This research provides recommendations for PLN, the state electricity company in Indonesia regarding the cost-effectiveness of reducing air emission from CFPPs in order to comply with an upcoming stringent environmental regulation. Four CFPPs were selected as research units of which two units represent large-scale CFPPs while the other two units represent small-scale CFPPs. A cost-engineering model i.e. CUEcost model is employed to estimate the abatement costs. Pollution control technologies were considered with respect to time, allocation across various scales of production unit and with respect to technological progress.

Short-term leaching test results of alkaline fly ash from Yenikoy coal-fired power plant were reported in this paper. ASTM D-3987-85 and TCLP-1311 test methods were applied to determine leaching behavior of selected elements namely, Fe, Ca, Cu, Co, Cd, Mn, Ni, Pb Zn, and Cr (VI) at different particle size fractions and test conditions. Chemical, mineralogical and morphological characterizations of ash samples were also performed using chemical. XRD and SEM-EDS analysis methods. The results showed that CaO dominates in the Yenikoy fly ash sample which directly affects the mobility of trace elements by determining the pH of the leaching medium. Higher mobility values of Cd. Co Cu, Pb, Ni and Zn elements were observed for TCLP-1311 procedure. The concentration of these elements in leachates showed a tendency to increase by decreasing particle size. Overall results suggested that the amount of the selected elements in the final leachates of both tests was lower than the limit values of landfill regulations except Cr (VI). (C) 2012 Elsevier B.V. All rights reserved.

This review deals with the analysis of mercury present in different types of solid, liquid and gaseous samples involved in the coal combustion process, focusing on the specific characteristics of each type of sample and the problems typically associated with these products. The main aim of the paper is to describe the methods that, at the current stage of development, are preferable in each case (i.e. the most frequently used in most laboratories and the standard methods). The advantages and disadvantages of each method are discussed with reference to the quality of the results and the uncertainties involved in the evaluation of mercury behavior during coal combustion processes., The work was performed thanks to several financial sources. The project CTM2004-04252-CO2-02/TECHNO from the Spanish National Research Plan, the support of CSIC (Spanish Nacional Research Council) for providing M. Antonia López-Antón with a postdoctoral position, and the help of the Asturias Research Programme for funding both a doctoral fellowship for Raquel Ochoa-González and the project PC10-20.

In order to achieve high performance and efficiency of coal-fired power plants, it is highly important to control the coal flow into the furnace in the power plant. This means suppression of disturbances and force the coal mill to deliver the required coal flow, as well as monitor the coal mill in order to detect faults in the coal mill when they emerge. This paper deals with the second objective. Based on a simple dynamic model of the energy balance a residual is formed for the coal mill. An optimal unknown input observer is designed to estimate this residual. The estimated residual is following tested on measured data of a fault in a coal mill, it can hereby be concluded that this residual is very useful for detecting faults in the coal mill.

For coal-fired power plants information of the moisture content in the coal is important to determine and control the dynamical behavior of the power plants. E.g. a high moisture content in the coal can result in a decreased maximum load gradient of the plant. In this paper a method for estimating the moisture content of the coal is proposed based on a simple dynamic energy model of a coal mill, which pulverizes and dries the coal before it is burned in the boiler. An optimal unknown input observer is designed to estimate the moisture content based on an energy balance model. The designed moisture estimator is verified on a couple of sets of measurement data, from which it is concluded that the designed estimator estimates the real coal moisture content.

This paper compares a selection of methods for detecting oscillations in control loops. The methods are tested on measurement data from a coal-fired power plant, where some oscillations are occurring. Emphasis is put on being able to detect oscillations without having a system model and without using process knowledge. The tested methods show potential for detecting the oscillations, however, transient components in the signals cause false detections as well, motivating usage of models in order to remove the expected signals behavior.

For coal-fired power plants information of the moisture content in the coal is important to determine and control the dynamical behavior of the power plants. E.g. a high moisture content in the coal can result in a decreased maximum load gradient of the plant. In this paper a method for estimating the moisture content of the coal is proposed based on a simple dynamic energy model of a coal mill, which pulverizes and dries the coal before it is burned in the boiler. An optimal unknown input observer is designed to estimate the moisture content based on an energy balance model. The designed moisture estimator is verified on a couple sets of measurement data, from which it is concluded that the designed estimator estimates the real coal moisture content.

To fulfill the energy demand now and in the next decades, coal-fired power plants will be an essential part of the portfolio of power plants that supply electricity cheaply and in a reliable way. The specific CO2 emissions of these plants can be reduced by increasing the efficiency. For that reason KEMA did optimize the steam water cycle of ultra super critical (USC) coal-fired power plants within the EOS program. The improvements are based on the application of the so-called Master Cycle, and on the application of higher steam temperatures. In the Master Cycle cold reheat steam is used in an extra turbine and with steam extraction of this turbine feed water preheating is realized with reduced exergy losses. The turbine is called a tuning turbine reflecting the improved possibilities to tune and optimize the steam cycle with the new coupling where the regenerative heater train and the re-heaters have been decoupled. The Master Cycle is proposed by Dong Energy . The first approach deals with the USC technology with a steam temperature of 600 °C and reheat temperatures of 620 °C. This technology is available at the moment and is applied in new built coal-fired power plants. The second approach deals with the USC technology with a steam temperature of 700 °C and reheat temperature of 720 °C. The expectation is that this technology can be applied around 2025 with the same availability as the USC units with 600 °C. The thermodynamic analyzes are carried out with KEMA’s flow sheeting package SPENCE®. In all considered cases the thermal input was 2400 MWth. In case of the application of the Master Cycle a second reheat is introduced. Results will be discussed and presented in tables, t-s diagrams and h-p diagrams. Improvement of efficiency of coal fired power station technology can reduce the amount of CO2 emitted significantly. This paper shows that with current available technology and improvements an additional emission reduction of almost 10% can be realised by applying the USC 700 + MC. Compared to the world wide average an emission reduction of 66% can be achieved without CCS. In the continuation of the analysis post combustion technology will be integrated in the concept to analyze possible additional benefits of the master cycle with respect to steam supply for the regeneration of the solvents.

This paper presents the result of research on the cost-effectiveness of emission reduction in the selected coal-fired power plants (CFPPs) in Indonesia. The background of this research is the trend of more stringent environmental regulation regarding air emission from coal-fired power plants (CFPPs) in Indonesia. One consequence of stringent air emission regulation is the increase of air pollution control costs. This research provides recommendations for PLN, the state electricity company in Indonesia regarding the cost-effectiveness of reducing air emission from CFPPs in order to comply with an upcoming stringent environmental regulation. Four CFPPs were selected as research units of which two units represent large-scale CFPPs while the other two units represent small-scale CFPPs. A cost-engineering model i.e. CUEcost model is employed to estimate the abatement costs. Pollution control technologies were considered with respect to time, allocation across various scales of production unit and with respect to technological progress.

Emissions trading programs are designed to keep compliance costs low but studies on actual savings are limited. This paper is the first to conduct a comprehensive analysis of the cost savings from the Acid Rain Program (ARP), the largest emissions trading program implemented in the U.S.. I estimate a discrete choice model of coal procurement and scrubber installation to recover structural parameters of compliance cost functions at the generating unit level. Using the model, I predict compliance choices under a uniform emission standard that yields the same aggregate emissions as the ARP. I estimate cost savings under the ARP to be about 130-330 million (1995 USD) per year. The numbers are much smaller than in previous literature (Carlson et al., 2000; Ellerman et al., 2000). I propose that lower transport costs reduced cost heterogeneity across generating units, and that improvements in scrubbing technology and state policies may have also contributed to a decrease in cost savings.