Techno-economic evaluations of post-combustion CO2 capture from sub- and super-critical circulated fluidised bed combustion (CFBC) power plants

Cormoş, Ana-Maria; Cormoş, Călin-Cristian

doi:10.1016/j.applthermaleng.2017.08.009

Cited by 44 publications

(13 citation statements)

References 24 publications

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“…For Cases 1 and 2, the ROIs were 6.7 and 6.1%/y, respectively, and the PBPs were 12.4 and 13.4 y, respectively. The LCOEs (60‐61 $/MWh) of the power plants considered in this study were lower than that (75 $/MWh) reported by Cormos et al 24 for a 700 MW e European power plant, as the TPC obtained in this study ($90 million/y) was lower than that ($120 million/y) of Cormos et al, which was proportionally converted from 700 to 500 MW e . The CCC (24‐25 $/t) obtained in this study was similar to that (24 $/t) of Cormos et al 24 The economic parameters for Case 3 fall between those for Cases 1 and 2.…”

Section: Resultscontrasting

confidence: 78%

Effects of flue gas recirculation on energy, exergy, environment, and economics in oxy‐coal circulating fluidized‐bed power plants with CO₂ capture

Kim

Lim

Lee

et al. 2020

Intl J of Energy Research

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Summary CO2 capture and storage(CCS) are required for coal‐fired power plants, which are major sources of anthropogenic CO2 emission. In this study, energy, exergy, environment, and economic (4E) analyses were performed for a 500‐MWe oxy‐coal ultra‐supercritical circulating fluidized‐bed (CFB) power plant with CO2 capture. The effect of the location of flue‐gas recirculation (FGR) on the 4E values was investigated for wet FGR (wFGR) at 170°C, dry FGR (dFGR) at 68°C, and 80% wet and 20% dry FGR (wdFGR). The net electricity efficiencies of the wFGR and dFGR power plants were 37% and 36%, respectively. The exergy loss was the largest in the combustor and boiler area, where process improvement was possible. The levelized cost of electricity was approximately 60 $/MWh. The return on investment was 6.7% and 6.1%/y for the wFGR and dFGR plants, respectively. The CO2 emission rate decreased by 90% (from 690 to 76 kg‐CO2/MWh) in the oxy‐coal power plants with CO2 capture. Relative to the wFGR, the dFGR was advantageous for preventing material corrosion because of the lower sulfur content in the FGR stream. For the wdFGR power plant, the process performance was intermediate, that is, between that of the wFGR plant and that of the dFGR plant. The study provided an effective tool for identifying the technological and economic effects of the FGR location for the oxy‐coal power plant with CCS via 4E analyses.

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Section: Resultscontrasting

confidence: 78%

Effects of flue gas recirculation on energy, exergy, environment, and economics in oxy‐coal circulating fluidized‐bed power plants with CO₂ capture

Kim

Lim

Lee

et al. 2020

Intl J of Energy Research

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“…Importantly, such results imply that although the use of AMP as a solvent in chemical solvent scrubbing can significantly reduce the efficiency penalty associated with CO 2 capture from NGCCs, it may not be the most economically-feasible option if the make-up rate is above 0.03%. Thus, this make-up rate of 0.03% is below the expected value for amine scrubbing [56]. It needs to be stressed, therefore, that development of novel CO 2 capture materials needs to be substantiated from both thermodynamic and economic standpoints.…”

Section: 3variation Of Make-up Flowratementioning

confidence: 94%

“…Therefore, feeding fresh solvent is needed in the system to make up for the losses. The case without makeup is presented in Section 7.2 (Table 11), while the solvent make-up rate is expressed as a percentage of total solvent flowrate in the PCC [56], as shown in Fig. 13.…”

Section: 3variation Of Make-up Flowratementioning

confidence: 99%

Techno-economic evaluation of the 2-amino-2-methyl-1-propanol (AMP) process for CO2 capture from natural gas combined cycle power plant

Osagie

Biliyok

Lorenzo

et al. 2018

International Journal of Greenhouse Gas Control

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It is widely accepted that emissions of CO 2 , which is a major greenhouse gas, are the primary cause of climate change. This has led to the development of carbon capture and storage (CCS) technologies in which CO 2 is captured from large-scale point sources such as power plants. However, retrofits of carbon capture plants result in high efficiency penalties, which have been reported to fall in the range of 7-12% points in the case of post-combustion capture from natural gas-fired power plants. Therefore, a reduction of these efficiency losses is a high priority in order to deploy CCS at a large scale. At the moment, chemical solvent scrubbing using amines, such as monoethanolamine (MEA), is considered as the most mature option for CO 2 capture from fossil fuel-fired power plants. However, due to high heat requirements for solvent regeneration, and thus high associated efficiency penalties, the use of alternative solvents has been considered to reduce the energy demand. In this study, a techno-economic assessment of the post-combustion CO 2 capture process using 2-amino-2methyl-1-propanol (AMP) for decarbonisation of a natural gas combined cycle (NGCC) power plant was performed. The thermodynamic assessment revealed that the AMP-based process resulted in 25.6% lower reboiler duty compared to that of the MEA-based process. This was primarily because the AMP solvent can be regenerated at a higher temperature (140°C) and pressure (3.5 bar) compared to that of MEA (120°C and 1.8 bar). Furthermore, the efficiency penalty due to the retrofit of the AMP-based process with the natural gas combined cycle power plant was estimated to be 7.1% points, compared to 9.1% points in the case of integration with the MEA-based process. Regardless of the superior thermodynamic performance, the economic performance of the AMP-based process was shown to be better than that of the MEA-based process only for make-up rates below 0.03%. Therefore, use of AMP as a solvent in chemical solvent scrubbing may not be the most feasible option from the economic standpoint, even though it can significantly reduce the efficiency penalty associated with CO 2 capture from NGCCs.

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“…Once the value of the electricity sale to reach the equilibrium point is known and accounting for the payback time, the minimum income is established to make the project economically feasible [52]. This income will come from the use of CO 2 and the savings of verified carbon emissions which are calculated through Equations ( 22) and ( 23 Figure 8 present the cash flow projection under the second scenario, as well as the values of Net Present Value (NPV) and Internal Rate of Return (IRR) of the project considering a minimum price of generated electricity of 135.84 €/MWh.…”

Section: Equilibrium Pointmentioning

confidence: 99%

Evaluation of Synergies of a Biomass Power Plant and a Biogas Station with a Carbon Capture System

2021

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The global carbon emissions from the tertiary sector have increased during the last years, becoming a target sector for carbon capture technologies. This study analyzes the potential application of a carbon capture system (CCS) to the usage of biogas from a livestock waste treatment plant (LWTP) and solid biomass. The proposed BECCS system fulfils the requirement of energy demands of the LWTP and generates electricity. The CCS is sized to consume the biogas produced and the selected operation parameters ensure a high capture efficiency. The BECCS is completed by a Rankine cycle fed by solid biomass and waste heat from the capture process is sized and implemented to produce electricity and steam. The proposed concept handles 1534 kW of solid biomass and 1398 kW of biogas to produce 746.20 kWe and cover the heat demand of a LWTP, 597 kWth. The avoided CO2 emissions sum up to 1620 ton CO2/year. The economic calculations show the limitation of this concept deployment under current prices of electricity and CO2 allowances. Results show the potential feasibility under future scenarios with 5 to 6 payback periods whenever public policies support the use of CCS and EU ETS evolves towards higher prices of carbon allowances.

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Techno-economic evaluations of post-combustion CO2 capture from sub- and super-critical circulated fluidised bed combustion (CFBC) power plants

Cited by 44 publications

References 24 publications

Effects of flue gas recirculation on energy, exergy, environment, and economics in oxy‐coal circulating fluidized‐bed power plants with CO₂ capture

Effects of flue gas recirculation on energy, exergy, environment, and economics in oxy‐coal circulating fluidized‐bed power plants with CO₂ capture

Techno-economic evaluation of the 2-amino-2-methyl-1-propanol (AMP) process for CO2 capture from natural gas combined cycle power plant

Evaluation of Synergies of a Biomass Power Plant and a Biogas Station with a Carbon Capture System

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Techno-economic evaluations of post-combustion CO2 capture from sub- and super-critical circulated fluidised bed combustion (CFBC) power plants

Cited by 44 publications

References 24 publications

Effects of flue gas recirculation on energy, exergy, environment, and economics in oxy‐coal circulating fluidized‐bed power plants with CO2 capture

Effects of flue gas recirculation on energy, exergy, environment, and economics in oxy‐coal circulating fluidized‐bed power plants with CO2 capture

Techno-economic evaluation of the 2-amino-2-methyl-1-propanol (AMP) process for CO2 capture from natural gas combined cycle power plant

Evaluation of Synergies of a Biomass Power Plant and a Biogas Station with a Carbon Capture System

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Product

Resources

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Effects of flue gas recirculation on energy, exergy, environment, and economics in oxy‐coal circulating fluidized‐bed power plants with CO₂ capture

Effects of flue gas recirculation on energy, exergy, environment, and economics in oxy‐coal circulating fluidized‐bed power plants with CO₂ capture