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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 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.

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&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.

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 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.

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.