Post-combustion CO2 Capture System Research Articles

Energy optimization of a non-aqueous solvent CO2 absorption system with pressure swing regeneration

This study focuses on optimizing the energy requirement in the post-combustion CO2 capture system using pressure swing regeneration through a model-based design (MBD). The simulation results highlight the significant impact of CO2 recovery, inlet gas and liquid flow rate, and CO2 concentration in the flue gas on the overall energy demand of the system. Moreover, an investigation into the de-sublimation chamber was undertaken, revealing a relationship between dry ice formation and the heat transfer between the LNG stream and CO2 in the heat exchanger. The parametric analysis study reveals that the sensible heat of the lean solvent is significantly influenced by the CO2 concentration in the liquid, consequently affecting the overall system energy. According to the results, the utilization of cold energy from LNG could save 80 % of the total energy requirement. The optimization results found the best working condition, which consumes energy of 0.190 GJ/ton CO2, 31 % lower than the basic scenario.

Options for net zero emissions hydrogen from Victorian lignite. Part 2: Ammonia production

This the second of a two-part study investigating the feasibility of producing export quantities (770 t/d) of blue hydrogen meeting international emissions standards, by gasification of Victorian lignite plus carbon capture and storage (CCS). Part 1 focussed on the resources, energy requirements, and greenhouse gas emissions associated with the production of gaseous and liquefied hydrogen, while Part 2 focusses on the production of ammonia as an alternative hydrogen carrier for export.In this study, an Aspen Plus simulation of a conventional 1500 t d−1 iron-based catalyst Haber-Bosch ammonia synthesis process is developed and incorporated into the earlier lignite-to-hydrogen process model. Development of the simulation involves (i) estimation of the instantaneous rate kinetics, (ii) calibration against test data for a reactor of known dimensions, (iii) scaling up the bed dimensions to achieve a target production capacity, (iv) selecting an appropriate feed gas composition to optimise performance, (v) adjusting purge gas flowrates to achieve stable operation, and (v) incorporation into the previous lignite-to-hydrogen simulation.This study finds that 178.2 t h−1 liquid ammonia and all electricity required to support the process can be produced from 1050 t h−1 Victorian lignite. Surprisingly, the simulation results show that the electrical power requirement for ammonia synthesis (176.4 MW) is essentially the same as that needed for liquefaction of an equivalent output of hydrogen (175.5 MW). On this basis both options are equally attractive, although ammonia synthesis is at a higher level of technological maturity than large-scale hydrogen liquefaction.This is the first study to quantify the greenhouse gas emissions intensity of ammonia production from lignite, accounting for the full production chain from lignite mining to CO2 sequestration. It is found that ammonia can be produced from Victorian lignite with very low CO2 emission intensity (0.49 kgCO2-e kgNH3−1) equivalent to that of next-generation natural gas reforming with CCS processes. If required, the emission intensity can be reduced to 0.05kgCO2-e kgNH3−1 with a post-combustion CO2 capture system, and then made carbon neutral by co-gasification with ≤1.4% biomass.For comparison, this study also examines the implications of producing the same quantity of green ammonia using renewable energy alone. It is estimated that production of 178.2 t h−1 green ammonia would require 1946 MW renewable energy and associated transmission infrastructure. In Victoria, this could be supplied by a wind farm with a 5.4 GW rated capacity, occupying an area of over 72,000 ha. This is highly unlikely to be a viable option.This analysis indicates that clean hydrogen in the form of ammonia, produced in Victoria by lignite gasification with CCS, can be consistent with global emissions reductions targets over the next few decades. The unique combination of low-cost lignite and high-quality CO2 storage geology means that Victoria is well placed to become a significant exporter of low-emissions ammonia to the world market. Further research is recommended on recovery of energy from the low grade waste heat streams and opportunities for additional electricity generation using the organic Rankine cycle.

Thermofluidic characteristics for a novel complementary adsorption-absorption post-combustion partial CO2 capture system

A novel complementary adsorption-absorption post-combustion partial CO2 capture strategy was proposed to decrease the energy penalty by integrating the rotary adsorption wheel with traditional chemical absorption process. The finite volume method is used for modeling the adsorption process, and the absorption process is simulated based on the rate-based model and the double-film theory. The techno-economic analyses of the novel complementary system were performed. In the adsorption part, the CO2 concentration of the flue gas can be effectively improved from 5.0%, 10.0% and 15.0% as much as to 17.3%, 27.0% and 33.7%, respectively. By adjusting the flue gas ducts of the adsorption wheel, the flue gas can be concentrated to a CO2 concentration making the absorption process work economically. The performance of the rotary adsorption wheel influenced by different geometrical and operational parameters were investigated. The energy penalty of the chemical absorption part can be significantly decreased. The major equipment cost was dramatically decreased by 48.6%, and the levelized cost of CO2 capture was decreased by 32.3%, when the CO2 concentration in the flue gas was increased from 5% to 20%. In addition, the acceptable investment of the rotary adsorption wheel has been estimated. The smallest acceptable capital cost of rotary adsorption wheel for coal-fired boiler corresponding to one payback year is 3.72 M$.

DMC-PID cascade control for MEA-based post-combustion CO2 capture process

The capture and recovery of carbon dioxide (CO2), the main source of greenhouse gases, are the principal means to reduce CO2 emissions. The optimization and control of the CO2 capture process plays a vital role in reducing energy costs, with the post-combustion CO2 capture (PCC) device using amine-based solvents considered to be the most feasible strategy to reduce CO2 emissions from coal-fired thermal power plants. In this paper, a DMC-PID cascade strategy is proposed to manipulate the PCC process order to obtain better performance. PID algorithm is used to adjust the flue gas flow to stabilize the flue gas entering absorber, and DMC algorithm is adopted to manipulate and constrain the lean solvent flow optimally order to increase CO2 capture rate. First, the corresponding steady-state model is established in Aspen Plus to get the best operating point parameters. Next, a dynamic model is built in Aspen Plus Dynamics to analyze the dynamic changes between the main variables of the system through dynamic testing, and the transfer function of the system is obtained through experimental data. Finally, three control strategies of DMC-PID, PID-PID and DMC are used to compare the control effect of CO2 capture rate. The results show that the proposed DMC-PID cascade control strategy has better performance, which improves the stability and flexibility of the PCC system, and provides a more feasible and effective operation for the CO2 capture.

Thermodynamic and environmental analyses of a novel closed loop regasification system integrating ORC and CO2 capture in floating storage regasification units

Regasification systems in Floating Storage Regasification Units (FSRUs) that use the steam generated by the boilers as the heat source (closed loop) in the liquefied natural gas (LNG) regasification process are less detrimental to the marine environment than those systems that use seawater (open loop). Their drawback, however, lies in the significant increase in fuel consumption and, thus, CO2 emissions. The present paper performs an energy, exergy and environmental analysis of a novel closed-loop regasification system for FSRUs that integrates an organic Rankine cycle (ORC) and post-combustion CO2 capture system with a 30 wt% aqueous solution of monoethanolamine (MEA). LNG cold energy is utilised for power generation through the ORC as well as in the processes of CO2 capture, compression, drying and liquefaction. The system proposed is able to meet the electrical power demand of the FSRU without the use of dual fuel engines, while CO2 capture efficiency in the boiler flue gases exceeds 90%. Fuel consumption is cut by 18% in this system in comparison with existing closed-loop regasification systems, and exergy efficiency increases by 14%, while CO2 emissions decrease by approximately 75% compared to open-loop systems commonly installed on board.

Time- and temperature-dependence of the anticorrosion effect of sodium sulfide on Q235 steel for post-combustion CO2 capture system

As a heat stable salt, sodium sulfide remains thermally-unregenerable during the regeneration process for post-combustion capture. Therefore, it became important to undertake a full assessment of its potential presence in the system. The paper investigates the mechanism and influence of sodium sulfide on the corrosion behavior of Q235 steel in amine-based post-combustion CO2 capture technology with respect to exposure time and temperature. The inhibitive influence of sulfide in the system was first confirmed by electrochemical techniques, while gravimetry was used to evaluate the effect of time and temperature on the inhibitive actions. SEM/EDX and XPS were used to characterize the corrosion product films on the steel surface. The behavior of sulfide was largely dependent on its concentration as its inhibition ability decreased with increasing concentration, and this is credited to the presence of FeS corrosion film layer. Time-dependent corrosion studies of steel conducted at 50 °C for the solution with 0.05 M and 0.1 M sulfide showed that the inhibition efficiency decreased from 89.1% and 75.0% to 82.4% and 68.6%, respectively, after 7 and 14 days immersion. At 80 °C, the inhibition efficiency of 0.05 M sulfide decreased from 89.1% to 48.9% after 7 days immersion and 82.4% to 46.1% after 14 days immersion. Together with FeS layer, FeCO3, Fe2O3 were also confirmed on the steel surface by XPS measurement. The research provides practical information on the influence of sulfide in the absorber and rich-lean heat exchanger sections of a CO2 capture unit.

Economic Model Predictive Control for Post-Combustion CO2 Capture System Based on MEA

For the post-combustion CO2 capture (PCC) system, the time variability of the economic performance is key to the production process of such an actual industrial process. However, the performance index used by the conventional model predictive control (MPC) does not reflect the economy of the production process, so the economic cost function is used instead of the traditional performance index to measure the economy of the production process. In this paper, a complete dynamic model of the PCC system is constructed in Aspen Plus Dynamics. The effectiveness of the model is verified by dynamic testing; subspace identification is carried out using experimental data, a state-space equation between flue gas flow and lean solvent flow; the CO2 capture rate is obtained; and dynamic models and control algorithm models of accused objects are established in Matlab/Simulink. Under the background of the environmental protection policy, an economic model predictive control (EMPC) strategy is proposed to manipulate the PCC system through seeking the optimal function of the economic performance, and the system is guaranteed to operate under the economic optimal and excellent quality of the MPC control strategy. The simulation results verify the effectiveness of the proposed method.

Post-combustion slipstream CO2-capture test facility at Jiangyou Power Plant, Sichuan, China: performance of a membrane separation module under dynamic power-plant operations

Abstract Membrane-based separation technologies have the potential to lower the cost of post-combustion CO2 capture from power-plant flue gases through reduced energy and capital costs relative to conventional solvent approaches. Studies have shown promise under controlled conditions, but there is a need for data on performance and reliability under field conditions. Coal-fired power plants in China operate in a dynamic manner, with increases and decreases in output causing changes in flue-gas composition. In this paper, we describe the first field test of a membrane-based post-combustion CO2-capture system connected to a dynamically operating power plant in China. We report the performance of a Membrane Technology Research, Inc. (MTR) PolarisTM membrane-based capture system over a range of plant operating loads ranging from 54% to 84% and conducted an operational stability test over a 168-h period during which the power plant was operating at an average load of 55%, but ramped as high as 79% and as low as 55%. Our results confirm the ability of a membrane capture system to operate effectively over a wide range of host-plant operating conditions, but also identity several issues related to plant integration, system control and resilience in the face of host-plant upsets that require attention as membrane separation systems move towards commercial use.

Production of cooling water by Ti3C2Tx MXene interlayered forward osmosis membranes for post-combustion CO2 capture system

Forward osmosis (FO) technology has the potential to replace the trim cooler and to supply cooling water for a post-combustion CO2 capture system. Herein, a high-performance MXene (Ti3C2Tx) interlayered FO membrane was fabricated. Thanks to the ability of MXene to adjust the structures of substrate and polyamide, the MXene interlayered FO (MXene-FO) membrane showed improved permeability and selectivity in a monoethanolamine (MEA) draw solution. The performance of MXene-FO membrane was investigated at different membrane orientations and temperatures with amino acid/salt (AAS) solutions (taurine/KOH and β-alanine/KOH) as draw solutions. Because the osmotic pressures provided by AAS solutions (104.4 ± 0.3 bar for 3 mol/L taurine/KOH and 153.7 ± 0.2 bar for 5 mol/L β-alanine/KOH solutions) are higher than that of 5 mol/L MEA solution (93.0 ± 0.1 bar), the MXene-FO membrane exhibited higher water fluxes in AAS solutions. Besides, the good performance of the MXene-FO membrane was shown with the presence of small specific amino acid fluxes and specific KOH fluxes. To investigate the feasibility of using saline water as the feed solution, 3.5 wt% NaCl solution was applied and the results indicated that the MXene-FO membrane maintained stable water fluxes and small specific solute fluxes. This work demonstrates the potential of nanomaterials interlayered FO membranes for cooling water production in a post-combustion CO2 capture system.

Risk Assessment of a Post-Combustion and Amine-Based CO2 Capture Ready Process

CO2 Capture Ready Process, as a part of Carbon Capture and Storage (CCS) technology, is a response to international political pressure and the priority of the European Commission to reduce anthropogenic CO2 emissions since it is connected with concerns regarding global warming. This is currently considered as an option for lessing CO2 emissions into the atmosphere. Many laboratory experiments, as well as pilot projects, have been carried out using different capture systems, but until now no experience from the one-to-one size operational installation has been gained. The energy industry must meet several challenges associated with the start-up of the new full-scale project. This paper investigates the problems that can occur while linking a new technology like the CO2 Capture Ready Process to a working fossil fuel power plant. A Hazard and Operability study (HAZOP) has been used, as it is a structured and systematic examination of a planned or existing process or operation, in order to identify and evaluate problems that may represent risks to personnel or equipment. A case study of a post-combustion CO2 capture system with an aqueous monoethanolamine as a solvent is presented, as it is the most likely system to be used in Polish power plants. Basic problems in the analysis as well as the parameters that should be considered to determine vulnerabilities of the process were successfully identified. Gaining experience about the installation’s behaviour while connected to the existing equipment of any power plant is critical for future CCS projects.

Treatment of Flue Gas in a CO2 Capture Pilot Plant for a Commercial CFB Boiler

The problem of reducing carbon dioxide emissions from flue gas, particularly from flue gas originating from coal-firing CFB systems, is currently an important challenge. Many centers around the world have tested post-combustion CO2 capture systems. One of these systems, operated using DR-VPSA adsorption technology (dual-reflux vacuum pressure swing adsorption), was tested under the Strategic Project in Poland. The flue gas in this study originated from a supercritical CFB boiler (460 MWe). An important problem involved in capturing CO2 from flue gas is the occurrence of SO2 and NOx. These substances have a negative effect on the CO2 adsorption process. In this study, commercial impregnated activated carbon was used to remove SO2 and NOx from CFB flue gas in the pre-treatment section during the tests of a pilot CO2 capture unit in a large-scale CFB boiler at the Lagisza Power Plant (Poland). The spent activated carbon was analyzed using several different methods (N2 adsorption–desorption isotherms, SEM-EDX, XRD, FTIR, and TG) to evaluate the efficiency of the operation and life span of the adsorbent used in the SO2 and NOx removal unit. The results demonstrate that using commercial impregnated activated carbon in the pre-treatment section ensures sufficient flue gas purification and the removal of sulfur oxides but remains insufficient for nitrogen oxides.

Engineering Design of a Full Scale Membrane Post-Combustion CO2 Capture System Retrofit for Duke Energy’s East Bend Station

This paper provides details of a recently completed U.S. Department of Energy funded study for a membrane-based, post-combustion CO2 capture (PCC) system retrofit to an existing U.S. coal power plant. The Electric Power Research Institute Inc. teamed with a technology supplier and engineering consultants to develop an initial engineering design and cost estimate for a membrane-based, PCC system for Duke Energy’s existing East Bend Station (EBS). A comprehensive overview of the proposed plant design will be presented, including the estimated costs associated with retrofitting the existing EBS coal-fired power plant with MTR’s second-generation Polaris™ membrane technology for CO2 removal from flue gas.

Rotary Adsorption: Selective Recycling of CO2 in Combined Cycle Gas Turbine Power Plants

A conceptual design assessment shows that the use of structured adsorbents in a regenerative adsorption wheel is technically feasible for the application of selective exhaust gas recirculation (SEGR) in combined cycle gas turbine (CCGT) power plants. As the adsorber rotates, CO2 is selectively transferred from a flue gas stream to an ambient air stream fed to the gas turbine compressor, increasing the CO2 concentration and reducing the flow rate of the fraction of the flue gases treated in a post-combustion CO2 capture system. It imposes an estimated pressure drop of 0.25 kPa, unlike a pressure drop of 10 kPa reported for selective CO2 membrane systems, preventing a significant derating of the gas turbine. An equilibrium model of a rotary adsorber with commercially available activated carbon evaluates the inventory of the adsorbent and sizes the wheel rotor. Two rotary wheels of 24 m diameter and 2 m length are required per gas turbine—heat recovery steam generator train to achieve an overall CO2 capture level of 90% in a CCGT power plant (ca. 820 MWe) with SEGR “in parallel” to the capture plant. Two to five rotary wheels are required for a configuration with SEGR “in series” to the capture plant. A reduction of 50% in the mass of the adsorbent would be possible with Zeolite 13X instead of activated carbon, yet the hydrophilicity of zeolites are detrimental to the capacity and upstream dehydration of the flue gases is required. A parametric analysis of the equilibrium properties provides guidelines for adsorbent development. It suggests the importance of balancing the affinity for CO2 to allow the regeneration of the adsorbent with air at near ambient pressure and temperature, to minimise the inventory of the adsorbent within practical limits. An adsorbent with a saturation capacity of 8 mol/kg, a heat of adsorption from 24 to 28 kJ/mol CO2 and a pre-exponential factor of the equilibrium constant from 2 × 10–6 to 9 × 10–6 kPa−1 would result in an inventory below 200 kg, i.e., approximately the limit for the use of a single rotary wheel system.

Process simulation, optimization and assessment of post-combustion carbon dioxide capture with piperazine-activated blended absorbents

High efficiency, large capacity, and low energy consumption have become an important challenge in performances of post-combustion carbon dioxide (CO2) capture and regeneration. Blended absorbents have shown great potential but their process simulation, modeling, and optimization have not been known definitively. This work developed the blended aqueous absorbents based on piperazine (PZ) activators: PZ-activated methyldiethanolamine (MDEA), potassium carbonate solution (K2CO3), and aqueous ammonia (NH3.H2O) to improve their techno-economic performances. The whole process simulation was conducted using a validated rate-based model under given a CO2 capture efficiency of 85%. In this process, the key factors including the molar concentration of the absorbent, PZ molar ratio, CO2 load of lean liquid, lean-liquid temperature, flue-gas temperature, and rich-liquid temperature, were employed for the design of experiment using response surface methodology. A series of nonlinear regression equations were developed using the flow rate of absorbents, the reboiler heat duty (in the units of gigajoules per ton of CO2), and the cooling-water flow rate as the multi-objective function. Subsequently, the optimal Pareto solution set and compromise solutions were determined using the multi-objective genetic algorithm and finally, their performances were assessed using the fuzzy close-degree algorithm. It was found that the optimal operating parameters can be determined effectively according to the proposed approach. For each PZ-activated blended absorbents, the trade-off effect exists between absorbent flow rate, reboiler heat duty, and cooling water consumption. The absorbents having optimal techno-economic performance were recommended to be PZ-activated MDEA, followed by PZ-activated K2CO3 and PZ-activated NH3.H2O when considering the regeneration energy consumption. The results may provide a positive reference for process design and optimization of the industrial post-combustion CO2 capture system.

Performance analysis of solar-assisted CO2 adsorption capture system based on dynamic simulation

Carbon Capture, Utilization and Storage (CCUS) is regarded as one of the most economical solutions to achieve reasonable emission reductions for small and medium-sized point sources in the IEA Clean Technology Scenario (CTS). In order to reduced dependency of fossil energy, the solar-assisted post-combustion CO2 capture system are proposed and studied in past decade. Nevertheless, the most of existing feasibility studies on solar-assisted CO2 capture system are steady-state analysis under certain fixed working conditions, which tend to ignore the impact of fluctuations in weather conditions and even lead to a misguiding on feasibility study. Hence, the dynamic simulation model is necessary as it could provide more detailed information and close to the actual situation. This study presents a design of a solar-assisted 5-step temperature-vacuum swing adsorption CO2 capture (SOL-TVSA) system for an industrial emission source. Verified by experiments of core unit, a dynamic simulation system is established and the influences of cyclic parameters on dynamic performance are evaluated. Results show that when vacuum pressure is lower than 6 kPa and desorption temperature exceeds 70 °C, the recovery rate and purity of TVSA system can exceed 95% and 85% respectively. When the volume-area ratio is below 0.3, the annual amount of CO2 captured by SOL-TVSA system could exceed 2.11 ton and solar fraction can exceed 38.81%. The maximum values of coefficient of performance and exergy efficiency can reach 2.20 and 9.81% respectively.

Integration of solar thermal energy to improve NGCC with CO2 capture plant performance

A large percentage of CO2 emissions are due to the combustion of fossil fuels for electricity generation. While a transition away from coal towards natural gas will reduce CO2 emissions, an even greater reduction in CO2 emissions can be achieved by retrofitting natural gas combined cycle (NGCC) plants with post-combustion CO2 capture (PCC) systems. A typical NGCC plant equipped with PCC was modeled in Aspen Plus and validated against similar models generated by the National Energy Technology Laboratory (NETL), and then adjusted to match the conditions of a plant located at Poza Rica, Mexico. After validation of the NGCC plant model with PCC, heat integration options were considered where heat from the flue gas cooler, CO2 dryer, and CO2 compressor intercoolers was used for heating of feedwater or low pressure (LP) steam in the steam cycle. The model was further modified to include solar-assisted carbon capture (SACC), to offset the detrimental impact of the PCC system on plant operations. The use of parabolic trough solar thermal collectors for heating of the stripper reboiler in the PCC system was considered in the Aspen Plus modeling. It was found that by using solar thermal energy for PCC reboiler heating, the LP steam extraction used to supply heat to the carbon capture reboiler element could be reduced in flow rate or eliminated depending on the quantity of solar thermal energy available. Modeling showed that if 100 % of the reboiler duty could be supplied via solar thermal energy, net plant power would increase significantly relative to the case without solar thermal collectors. The availability of the solar resource was also predicted for the target location in Mexico using the System Advisor Model (SAM) developed by the National Renewable Energy Laboratory (NREL). By coupling the modeling results from SAM with those produced by Aspen Plus, annual plant energy production for an NGCC plant with PCC and using solar thermal energy for reboiler heating was found. A final case was modeled in both Aspen and SAM, where solar thermal energy was used for LP steam heating. While this case has marginally better performance than the case where solar thermal heat was applied to the reboiler, the added complexity of this system outweighs the slight increase in net annual power generation. This modeling effort demonstrated that solar thermal heating of the stripper reboiler in an NGCC plant with PCC could meaningfully offset the detrimental impact of carbon capture on plant efficiency and power generation loss, offering an attractive renewable energy option to NGCC carbon mitigation.

Process analysis overview of ionic liquids on CO2 chemical capture

A process analysis overview of the ionic liquids (ILs) performance as chemical absorbents in post-combustion, biogas and pre-combustion CO2 capture systems was carried out. Six representative ILs, among them carboxylate, aminoacid and aprotic heterocyclic anion-based ILs -with remarkably different CO2 absorption thermodynamics and kinetics- were selected. COSMO-based/Aspen Plus methodology, supported with available experimental data, was successfully applied to design the absorption and regeneration stages in commercial packed columns to reach a 90% CO2 recovery at different CO2 partial pressures and given operating conditions, for comparison purposes. The IL performance in CO2 capture process was evaluated by means of solvent need, energy consume and column size. The CO2-IL reaction enthalpy and IL viscosity were identified as key properties to guide solvent selection. For the considered ILs, increasing the reaction exothermicity means lower solvent, energy and equipment requirements as liquid viscosity descends, overcoming mass transfer limitations at adiabatic conditions. The CO2 capture process efficiency was successfully related to the thermodynamic gap capacity given by CO2-IL isotherms at the absorption/regeneration operating conditions. AHA-IL family is aimed as a promising alternative to industrial CO2 chemical absorbent benchmark (aqueous amine solution) due to their advantageous key properties: moderate viscosity and adequate compromise between high CO2 solubility and reaction enthalpy. Current results indicated the technical viability of ILs-based CO2 capture processes compared to available technologies, but further analysis (i.e cost estimations, environmental impacts and life cycle assessment) are required to ensure the sustainability of a new process.

Modeling and performance analysis of subcritical and supercritical coal-fired power plants with biomass co-firing and CO2 capture

Coal-fired power plants are the largest source of carbon dioxide (CO2) emissions into the atmosphere, and these emissions can be effectively reduced by improving the efficiency of the plants, co-firing sustainably grown biomass and applying carbon capture and storage technologies. In this study, the energy and environmental performances of both subcritical (SubC) and supercritical (SC) pulverized coal-fired power plants with biomass co-firing and integrated with an advanced amine-based postcombustion CO2 capture system were evaluated and compared. The impact of biomass (hybrid poplar) addition was investigated at different co-firing ratios varying up to 30% on a heat input basis. All plant configurations were modeled and simulated with Aspen Plus process simulation software. The results show that the use of a SC steam cycle has a positive impact on the energy and environmental performance of the investigated plants, improving the efficiency by 2.4% points and reducing the total fuel consumption and CO2 emissions by 6% in comparison to those of the SubC cases. Biomass co-firing has a negative impact on the energy performance of plants while significantly reducing fossil-based carbon emissions. The reduction of net CO2 emissions is almost proportional to the biomass percentage in the feed. At 30% biomass co-firing, the net plant efficiency is reduced by approx. 1% point, while the net CO2 emissions are 28% lower than those in coal-fired only plants. The introduction of CO2 capture has a major impact both on the emissions generated and on the energy efficiency. Depending on the plant type and co-firing ratio used, the net plant efficiencies are 8.7–9.3% points lower than those of non-capture cases. The net CO2 emissions achieve negative values when carbon is captured from the biomass co-firing plants.

Solvent-based post-combustion CO2 capture for power plants: A critical review and perspective on dynamic modelling, system identification, process control and flexible operation

Solvent-based post-combustion CO2 capture (PCC) appears to be the most effective choice to overcome the CO2 emission issue of fossil fuel fired power plants. To make the PCC better suited for power plants, growing interest has been directed to the flexible operation of PCC in the past ten years. The flexible operation requires the PCC system to adapt to the strong flue gas flow rate change and to adjust the carbon capture level rapidly in wide operating range. In-depth study of the dynamic characteristics of the PCC process and developing a suitable control approach are the keys to meet this challenge. This paper provides a critical review for the dynamic research of the solvent–based PCC process including first-principle modelling, data-driven system/process identification and the control design studies, with their main features being listed and discussed. The existent studies have been classified according to the approaches used and their advantages and limitations have been summarized. Potential future research opportunities for the flexible operation of solvent-based PCC are also given in this review.

Integration of Power Plants with Different Capacities with Aqueous Ammonia-Based CO2 Capture

Integration of coal-fired power plants with NH3-based CO2 capture is a promising technology for CO2 capture. However, the output and efficiency of the original coal-fired power plant are reduced because the integration requires energy. This work studied three typical coal-fired power plants with the capacities of 330, 660, and 1000 MW and turbine levels of N330-16.67/538/538, N660-24.2/566/566, and N1000-25/600/600, respectively. The integration of these coal-fired power plants with the same NH3-based postcombustion CO2 capture system was established. Heat consumption, energy penalty, and other evaluation indicators were obtained through an Ebsilon simulation. Among the three coal-fired power plants, the thermal efficiency of 1000 MW is the highest, whereas that of 330 MW is the lowest. The energy penalty of the 660 MW coal-fired power plant is the highest, whereas that of 330 MW is the lowest. To fully analyze the integration performance of power plants with different capacities, comprehensive evaluation...