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1.
This work focuses on the techno-economic assessment of bituminous coal fired sub- and super-critical pulverised fuel boilers from an oxyfuel based CO2 capture point of view. At the initial stage, two conventional power plants with a nominal power output of above 600 MWe based on the above steam cycles are designed, simulated and optimised. Built upon these technologies, CO2 capture facilities are incorporated within the base plants resulting in a nominal power output of 500 MWe. In this manner, some sensible heat generated in the air separation unit and the CO2 capture train can be redirected to the steam cycle resulting in a higher plant efficiency. The simulation results of conventional sub- and super-critical plants are compared with their CO2 capture counterparts to disclose the effect of sequestration on the overall system performance attributes. This systematic approach allows the investigation of the effects of the CO2 capture on both cycles. In the literature, super-critical plants are often considered for a CO2 capture option. These, however, are not based on a systematic evaluation of these technologies and concentrate mainly on one or two key features. In this work several techno-economic plant attributes such as the fuel consumptions, the utility usages, the plant performance parameters as well as the specific CO2 generation and capture rates are calculated and weighed against each other. Finally, an economic evaluation of the system is conducted along with sensitivity analyses in connection with some key features such as discounted cash flow rates, capital investments and plant efficiencies as well as fuel and operating costs.  相似文献   

2.
This article presents a fleet‐wide model for energy planning that can be used to determine the optimal structure necessary to meet a given CO2 reduction target while maintaining or enhancing power to the grid. The model incorporates power generation as well as CO2 emissions from a fleet of generating stations (hydroelectric, fossil fuel, nuclear, and wind). The model is formulated as a mixed integer program and is used to optimize an existing fleet as well as recommend new additional generating stations, carbon capture and storage, and retrofit actions to meet a CO2 reduction target and electricity demand at a minimum overall cost. The model was applied to the energy supply system operated by Ontario power generation (OPG) for the province of Ontario, Canada. In 2002, OPG operated 79 electricity generating stations; 5 are fueled with coal (with a total of 23 boilers), 1 by natural gas (4 boilers), 3 nuclear, 69 hydroelectric and 1 wind turbine generating a total of 115.8 TWh. No CO2 capture process existed at any OPG power plant; about 36.7 million tonnes of CO2 was emitted in 2002, mainly from fossil fuel power plants. Four electricity demand scenarios were considered over a span of 10 years and for each case the size of new power generation capacity with and without capture was obtained. Six supplemental electricity generating technologies have been allowed for: subcritical pulverized coal‐fired (PC), PC with carbon capture (PC+CCS), integrated gasification combined cycle (IGCC), IGCC with carbon capture (IGCC+CCS), natural gas combined cycle (NGCC), and NGCC with carbon capture (NGCC+CCS). The optimization results showed that fuel balancing alone can contribute to the reduction of CO2 emissions by only 3% and a slight, 1.6%, reduction in the cost of electricity compared to a calculated base case. It was found that a 20% CO2 reduction at current electricity demand could be achieved by implementing fuel balancing and switching 8 out of 23 coal‐fired boilers to natural gas. However, as demand increases, more coal‐fired boilers needed to be switched to natural gas as well as the building of new NGCC and NGCC+CCS for replacing the aging coal‐fired power plants. To achieve a 40% CO2 reduction at 1.0% demand growth rate, four new plants (2 NGCC, 2 NGCC+CCS) as well as carbon capture processes needed to be built. If greater than 60% CO2 reductions are required, NGCC, NGCC+CCS, and IGCC+CCS power plants needed to be put online in addition to carbon capture processes on coal‐fired power plants. The volatility of natural gas prices was found to have a significant impact on the optimal CO2 mitigation strategy and on the cost of electricity generation. Increasing the natural gas prices resulted in early aggressive CO2 mitigation strategies especially at higher growth rate demands. © 2009 American Institute of Chemical Engineers AIChE J, 2009  相似文献   

3.
The techno-economic evaluation of four novel integrated gasification combined cycle (IGCC) power plants fuelled with low rank lignite coal with CO2 capture facility has been investigated using ECLIPSE process simulator. The performance of the proposed plants was compared with two conventional IGCC plants with and without CO2 capture. The proposed plants include an advanced CO2 capturing process based on the Absorption Enhanced Reforming (AER) reaction and the regeneration of sorbent materials avoiding the need for sulphur removal component, shift reactor and/or a high temperature gas cleaning process. The results show that the proposed CO2 capture plants efficiencies were 18.5–21% higher than the conventional IGCC CO2 capture plant. For the proposed plants, the CO2 capture efficiencies were found to be within 95.8–97%. The CO2 capture efficiency for the conventional IGCC plant was 87.7%. The specific investment costs for the proposed plants were between 1207 and 1479 €/kWe and 1620 €/kWe and 1134 €/kWe for the conventional plants with and without CO2 capture respectively. Overall the proposed IGCC plants are cleaner, more efficient and produce electricity at cheaper price than the conventional IGCC process.  相似文献   

4.
《分离科学与技术》2012,47(13):1952-1963
In this study three configurations, viz. conventional MEA, interstage absorber, and interstage absorber with two stripper configuration have been techno-economically evaluated for the optimized result by carrying out simulations using ASPEN PLUS. An economic model defined for carbon capture using 30 wt% MEA to reduce CO2 in flue gas to 0.5 mol% of 550 MWe coal fired power plant resulted in increase in COE of power plant by 20.6, 17.4, and 15.6 percents for the three configurations, respectively. The CO2-avoided cost for the three configurations are 65.94, 64.05, and 63.09 ($ /tonne of CO2 avoided), respectively.  相似文献   

5.
A.J. Minchener  J.T. McMullan 《Fuel》2007,86(14):2124-2133
The future use of coal will require strict environmental compliance with an increasing need to minimise emissions of CO2, particularly from power plants. A pan-European approach is being established to ensure that EU industry can have available, by 2020, fossil fuel power plants that are either capable of capturing almost all their CO2 emissions in an economically viable manner, or are designed to include CO2 capture systems (“capture-ready”). The overall aim is to provide a significant impetus to research, development, demonstration and deployment activities such that coal and other fossil fuels can be used in a sustainable manner.  相似文献   

6.
Australia's Commonwealth Scientific and Industrial Research Organization (CSIRO) and Delta Electricity have developed, commissioned and operated an A$7 million aqueous NH3 based post-combustion capture (PCC) pilot plant at the Munmorah black coal fired power station in Australia. The results from the pilot plant trials will be used to address the gap in know-how on application of aqueous NH3 for post-combustion capture of CO2 and other pollutants in the flue gas and explore the potential of the NH3 process for application in the Australia power sector. This paper is one of a series of publications to report and discuss the experimental results obtained from the pilot plant trials and primarily focuses on the absorption section.The pilot plant trials have confirmed the technical feasibility of the NH3 based capture process. CO2 removal efficiency of more than 85% can be achieved even with low NH3 content of up to 6 wt%. The NH3 process is effective for SO2 but not for NO in the flue gas. More than 95% of SO2 in the flue gas is removed in the pre-treatment column using NH3. The mass transfer coefficients for CO2 in the absorber as functions of CO2 loading and NH3 concentration have been obtained based on pilot plant data.  相似文献   

7.
In the work presented in this paper, an alternative process concept that can be applied as retrofitting option in coal-fired power plants for CO2 capture is examined. The proposed concept is based on the combination of two fundamental CO2 capture technologies, the partial oxyfuel mode in the furnace and the post-combustion solvent scrubbing. A 330 MWel Greek lignite-fired power plant and a typical 600 MWel hard coal plant have been examined for the process simulations. In a retrofit application of the ECO-Scrub technology, the existing power plant modifications are dominated by techno-economic restrictions regarding the boiler and the steam turbine islands. Heat integration from processes (air separation, CO2 compression and purification and the flue gas treatment) can result in reduced energy and efficiency penalties. In the context of this work, heat integration options are illustrated and main results from thermodynamic simulations dealing with the most important features of the power plant with CO2 capture are presented for both reference and retrofit case, providing a comparative view on the power plant net efficiency and energy consumptions for CO2 capture. The operational characteristics as well as the main figures and diagrams of the plant’s heat balances are included.  相似文献   

8.
In order to reduce the CO2 emission from the coal-fired power plants, O2/CO2 recycle combustion (Oxy-combustion) technique has been proposed through combining a conventional combustion process with a cryogenic air separation process. The technique is capable of enriching CO2 concentration and then allowing CO2 sequestration in an efficient and energy-saving way. Taking into account the CO2 taxation and CO2 sale, the paper evaluates the economic feasibility of Oxy-combustion plants retrofitted from two typical existing conventional coal-fired power plants (with capacities of 2 × 300 MW and 2 × 600 MW, respectively) with Chinese data. The cost of electricity (COE) and the CO2 avoidance cost (CAC) are also considered in the evaluation. The COE of the retrofitted Oxy-combustion plant is nearly the same as that of the corresponding conventional plant if the unit price of CO2 sale reaches 17-22 $/t (different cases). The CAC of the retrofitted 2 × 300 MW Oxy-combustion plant is 1-3 $/t bigger than that of the retrofitted 2 × 600 MW Oxy-combustion plant. Supercritical plants are more economical and appropriate for Oxy-combustion retrofit. The result indicates that Oxy-combustion technique is not only feasible for CO2 emission control based on existing power plants but is also cost-effective.  相似文献   

9.
Using a manometric experimental setup, high-pressure sorption measurements with CH4 and CO2 were performed on three Chinese coal samples of different rank (VRr = 0.53%, 1.20%, and 3.86%). The experiments were conducted at 35, 45, and 55 °C with pressures up to 25 MPa on the 0.354-1 mm particle fraction in the dry state. The objective of this study was to explore the accuracy and reproducibility of the manometric method in the pressure and temperature range relevant for potential coalbed methane (CBM) and CO2-enhanced CBM (CO2-ECBM) activities (P > 8 MPa, T > 35 °C). Maximum experimental errors were estimated using the Gauss error propagation theorem, and reproducibility tests of the high-pressure sorption measurements for CH4 and CO2 were performed. Further, the experimental data presented here was used to explicitly study the CO2 sorption behaviour of Chinese coal samples in the elevated pressure range (up to 25 MPa) and the effects of temperature on supercritical CO2 sorption isotherms.The experiments provided characteristic excess sorption isotherms which, in the case of CO2 exhibit a maximum around the critical pressure and then decline and level out towards a constant value. The results of these manometric tests are consistent with those of previous gravimetric sorption studies and corroborate a crossover of the 35, 45, and 55 °C CO2 excess sorption isotherms in the high-pressure range. The measurement range could be extended, however, to significantly higher pressures. The excess sorption isotherms tend to converge, indicating that the temperature dependence of CO2 excess sorption on coals at high-pressures (>20 MPa) becomes marginal. Further, all CO2 high-pressure isotherms measured in this study were approximated by a three-parameter excess sorption function with special consideration of the density ratio of the “free” phase and the sorbed phase. This function provided a good representation of the experimental data.The maximum excess sorption capacity of the three coal samples for methane ranged from 0.8 to 1.6 mmol/g (dry, ash-free) and increased from medium volatile bituminous to subbituminous to anthracite. The medium volatile bituminous coal also exhibited the lowest overall excess sorption capacity for CO2. However, the subbituminous coal was found to have the highest CO2 sorption capacity of the three samples. The mass fraction of adsorbed substance as a function of time recorded during the first pressure step was used to analyze the kinetics of CH4 and CO2 sorption on the coal samples. CO2 sorption proceeds more rapidly than CH4 sorption on the anthracite and the medium volatile bituminous coal. For the subbituminous coal, methane sorption is initially faster, but during the final stage of the measurement CO2 sorption approaches the equilibrium value more rapidly than methane.  相似文献   

10.
CO2 capture systems based on the carbonation/calcination loop have gained rapid interest due to promising carbonator CO2 capture efficiency, low sorbent cost and no flue gases treatment is required before entering the system. These features together result in a competitively low cost CO2 capture system. Among the key variables that influence the performance of these systems and their integration with power plants, the carbonation conversion of the sorbent and the heat requirement at calciner are the most relevant. Both variables are mainly influenced by CaO/CO2 ratio and make-up flow of solids. New sorbents are under development to reduce the decay of their carbonation conversion with cycles. The aim of this study is to assess the competitiveness of new limestones with enhanced sorption behaviour applied to carbonation/calcination cycle integrated with a power plant, compared to raw limestone. The existence of an upper limit for the maximum average capture capacity of CaO has been considered. Above this limit, improving sorbent capture capacity does not lead to the corresponding increase in capture efficiency and, thus, reduction of CO2 avoided cost is not observed. Simulations calculate the maximum price for enhanced sorbents to achieve a reduction in CO2 removal cost under different process conditions (solid circulation and make-up flow). The present study may be used as an assessment tool of new sorbents to understand what prices would be competitive compare with raw limestone in the CO2 looping capture systems.  相似文献   

11.
C.J. Liu  G.X. Wang  S.X. Sang 《Fuel》2010,89(10):2665-2672
Pore structure changing of coal during the CO2 geo-sequestration is one of the key issues that affect the sequestration process significantly. To address this problem, the CO2 sequestration process in an anthracite coal was replicated using a supercritical CO2 (ScCO2) reactor. Different coal grain sizes were exposed to ScCO2 and water at around 40 °C and 9.8 MPa for 72 h. Helium pycnometer and mercury porosimetry provide the density, pore size distribution and porosity of the coal before and after the ScCO2 treatment. The results show that after exposure to the ScCO2-H2O reaction, part of the carbonate minerals were dissolved and flushed away by water which made the true density increased as well as total pore volume and porosity most importantly in the micro-pore range. Hysteresis between mercury intrusion and extrusion was observed. Ink bottle shaped pores can be either damaged or created compared with the ScCO2 treated coal samples. This suggests that the ScCO2 treatment most likely increase the volumes of pores in anthracite coal, which also contributed to the increase in porosity of the treated samples. Therefore the CO2 sequestration into coal appears to have the potential to increase significantly the anthracite microporosity which is very advantageous for CO2 storage.  相似文献   

12.
It is thought that the CO2 emissions from coal-fired power plants contribute greatly to the total anthropogenic CO2 emissions. Ammonia solvent can be used to absorb the CO2, called ammonia scrubbing. However, as has been pointed out, the production of ammonia would emit CO2; therefore, the effectiveness of ammonia scrubbing is doubted. The paper focuses on the problem. Two systems are defined in the paper. System I is CO2 absorption by ammonia scrubbing, and system II is industrial production of ammonium bicarbonate. The total CO2 emissions of the two systems are calculated by means of life cycle assessment. The paper shows that the total CO2 emissions of ammonia scrubbing are less than that of the industrial production of fertilizer ammonium bicarbonate. It can be concluded that ammonia scrubbing is an effective way to reduce the anthropogenic CO2 emissions. This work was presented at the 6 th Korea-China Workshop on Clean Energy Technology held at Busan, Korea, July 4–7, 2006.  相似文献   

13.
The 2007 IEA's World Energy Outlook report predicts that the world's energy needs will grow by 55% between 2005 and 2030, with fossil fuels accounting for 84% of this massive projected increase in energy demand. An undesired side effect of burning fossil fuels is carbon dioxide (CO2) emission which is now widely believed to be responsible for the problem of global warming. Various strategies are being considered for addressing the increase in demand for energy and at the same time developing technologies to make energy greener by reducing CO2 emissions.One of these strategies is to ‘capture’ produced CO2 instead of releasing it into the atmosphere. Capturing CO2 and its injection in oil reservoirs can lead to improved oil recovery as well as CO2 retention and storage in these reservoirs. The technology is referred to as CCS (carbon capture and storage). Large point sources of CO2 (e.g., coal-fired power plants) are particularly good candidates for capturing large volumes of CO2. However, CO2 capture from power plants is currently very expensive. In addition to high costs of CO2 capture, the very low pressure of the flue gas (1 atm) and its low CO2 content (typically 10-15%) contribute to the high cost of CO2 capture from power plants and the subsequent compression. This makes conventional CO2 flooding (which requires very large volumes of CO2) uneconomical in many oil reservoirs around the world which would otherwise be suitable candidates for CO2 injection. Alternative strategies are therefore needed to utilize smaller sources of CO2 that are usually available around oil and gas fields and can be captured at lower costs (due to their higher pressure and higher CO2 concentration).We investigate the potential of carbonated (CO2-enriched) water injection (CWI) as an injection strategy for improving recovery from oil reservoirs with the added benefit of safe storage of CO2. The performance of CWI was investigated by conducting high-pressure flow visualization as well as coreflood experiments at reservoir conditions. The results show that CWI significantly improves oil recovery from water flooded porous media. A relatively large fraction of the injected CO2 was retained (stored) in the porous medium in the form of dissolved CO2 in water and oil. The results clearly demonstrate the huge potential of CWI as a productive way of utilizing CO2 for improving oil recovery and safe storage of potentially large cumulative quantities of CO2.  相似文献   

14.
Australian power generators produce approximately 170 TWh per annum of electricity using black and brown coals that accounts for 170 Mtonne of CO2 emissions per annum or over 40% of anthropogenic CO2 emissions in Australia. This paper describes the results of a techno-economic evaluation of liquid absorption based post-combustion capture (PCC) processes for both existing and new pulverised coal-fired power stations in Australia. The overall process designs incorporate both the case with continuous capture and the case with the flexibility to switch a CO2 capture plant on or off depending upon the demand and market price for electricity, and addresses the impact of the presently limited emission controls on the process cost. The techno-economic evaluation includes both air and water cooled power and CO2 capture plants, resulting in cost of power generation for the situations without and with PCC. Whilst existing power plants in Australia are all water cooled sub-critical designs, the new power plants are deemed to range from supercritical single reheat to ultra-supercritical double reheat designs, with a preference for air-cooling. The process evaluation also includes a detailed sensitivity analysis of the thermodynamic properties of liquid absorbent for CO2 on the overall costs. The results show that for a meaningful decrease in the efficiency and cost penalties associated with the post combustion CO2 capture, a novel liquid sorbent will need to have heat of absorption/desorption, sensible heat and heat of vaporisation around 50% less in comparison with 30% (w/w) aqueous MEA solvent. It also shows that the impact of the capital costs of PCC processes is quite large on the added cost of generation. The results can be used to prioritise PCC research in an Australian context.  相似文献   

15.
Chemical-Looping Combustion (CLC) is an emerging technology for CO2 capture because separation of this gas from the other flue gas components is inherent to the process and thus no energy is expended for the separation. For its use with coal as fuel in power plants, a process integrated by coal gasification and CLC would have important advantages for CO2 capture. This paper presents the combustion results obtained with a Cu-based oxygen carrier in a continuous operation CLC plant (500 Wth) using syngas as fuel. For comparison purposes pure H2 and CO were also used. Tests were performed at two temperatures (1073 and 1153 K), different solid circulation rates and power inputs. Full syngas combustion was reached at 1073 K working at f higher than 1.5. The syngas composition had small effect on the combustion efficiency. This result seems to indicate that the water gas shift reaction acts as an intermediate step in the global combustion reaction of the syngas. The results obtained after 40 h of operation showed that the copper-based oxygen carrier prepared by impregnation could be used in a CLC plant for syngas combustion without operational problems such as carbon deposition, attrition, or agglomeration.  相似文献   

16.
We have recently proposed a compressible lattice model for CO2 + polymer systems in which CO2 forms complexes with one or more functional groups in the polymer. Furthermore, we have shown that this model is able to simultaneously correlate phase equilibria, sorption behavior, and glass transition temperatures in such systems. In the present work, we extend the model to ternary CO2 + cosolvent + polymer systems and demonstrate that cloud point behavior in CO2 + dimethyl ether + poly (?-caprolactone), CO2 + dimethyl ether + poly (isopropyl acrylate), and CO2 + dimethyl ether + poly (isodecyl acrylate) systems can be predicted using parameters obtained from binary data. Our results also suggest that dimethyl ether may form weak complexes with poly (?-caprolactone), poly (isopropyl acrylate), and poly (isodecyl acrylate).  相似文献   

17.
In the last decade the reduction of CO2 emissions from fossil fuels became a worldwide topic. Co-gasification of coal and wood provides an opportunity to combine the advantages of the well-researched usage of fossil fuels such as coal with CO2-neutral biomass. Gasification itself is a technology with many advantages. The producer gas can be used in many ways; for electric power generation in a gas engine or gas turbine, for Fischer-Tropsch synthesis of liquid fuels and also for production of gaseous products such as synthetic natural gas (bio SNG). Moreover, the use of the producer gas in fuel cells is under investigation. The mixture of coal and wood leads to the opportunity to choose the gas composition as best befits the desired process. Within this study the focus of investigation was of gasification of coal and wood in various ratios and the resulting changes in producer gas composition. Co-gasification of coal and wood leads to linear producer gas composition changes with linear changing load ratios (coal/wood). Hydrogen concentrations rise with increasing coal ratio, while CO concentrations decrease. Due to the lower sulfur and nitrogen content of wood, levels of the impurities NH3 and H2S in the producer gas fall with decreasing coal ratio. It is also shown that the majority of sulfur is released in the gasification zone and, therefore, no further cleaning of the flue gas is necessary. All mixture ratios, from 100 energy% to 0 energy% coal, performed well in the 100 kW dual fluidized bed gasifier. Although the gasifier was originally designed for wood, an addition of coal as fuel in industrial sized plants based on the same technology should pose no problems.  相似文献   

18.
An augmented measurement uncertainty approach for CO2 emissions from coal-fired power plants with a focus on the often forgotten contributions from sampling errors occurring over the entire fuel-to-emission pathway is presented. Current methods for CO2 emission determination are evaluated in detail, from which a general matrix scheme is developed that includes all factors and stages needed for total CO2 determination, which is applied to the monitoring plan of a representative medium-sized coal-fired power plant. In particular sampling involved significant potential errors, as identified and assessed by the Theory of Sampling (TOS), which also shows how these can be eliminated and/or minimised. Since coal-related CO2 emission calculations not only require analytical results of the carbon content of coal itself but also of the by-products fly ash and bottom ash, sampling procedures of these three materials were also given full attention. A systematic error (bias) is present in the current sampling approach, which increases the present uncertainty estimate unnecessarily. For both primary sampling and analytical sample extraction steps, random variations, which hitherto only have been considered to a minor extent, have now also been fully quantified and included in the overall uncertainty. Elimination of all identified sampling errors lead to modified CO2 determination procedures, which indicate that the actual CO2 emission is approximately 20,000 t higher than the present estimate. Based on extensive empirical sampling experiments, a fully comprehensive uncertainty estimate procedure has been devised. Even though uncertainties increased (indeed one particular factor is substantially higher, the so-called “emission factor”), the revised CO2 emission budget for the case plant complies with the official pre-determined uncertainty levels maxima in the EU guidelines.  相似文献   

19.
Jinsheng Wang  Edward J. Anthony 《Fuel》2004,83(10):1341-1348
Petroleum coke is a challenging fuel in terms of its low volatile content, high sulfur and nitrogen content, which give rise to undesirable emission characteristics. However, the low price and increased production of petroleum coke from high-sulfur feedstocks give a powerful economic stimulus to use it for power generation. In this study two strategies are explored for the clean combustion of petroleum coke by in situ removal of CO2 and sulfur or in the longer term for hydrogen production with CO2 recovery. CaO sorbent is used to absorb CO2 and SO2 in fluidized combustor or steam gas reformer, and is regenerated in a calciner. In the calciner, petroleum coke is fired with pure oxygen to provide the heat for regenerating the sorbent and give a CO2 stream for subsequent utilization or sequestration. The SO2 is retained in solid CaSO4 and would not be emitted to the atmosphere. The high carbon content and low moisture content of petroleum coke ensure high purity of the CO2 stream. The low ash content is also important since it reduces the possibility of ash fusion in the calciner. It also reduces the heat loss and the requirement for ash disposal, and hence contributes to high overall efficiency. Simulation results show that high efficiency can be achieved with incorporation of the proposed scheme for power generation, even after the penalty of CO2 recovery. Thus, there is a potential for the abundant available and low cost, but environmentally challenging petroleum coke to become a fuel for clean combustion and power generation.  相似文献   

20.
Global concentration of CO2 in the atmosphere is increasing rapidly. CO2 emissions have an impact on global climate change. Effective CO2 emission abatement strategies such as Carbon Capture and Storage (CCS) are required to combat this trend. There are three major approaches for CCS: post-combustion capture, pre-combustion capture and oxyfuel process. Post-combustion capture offers some advantages as existing combustion technologies can still be used without radical changes on them. This makes post-combustion capture easier to implement as a retrofit option (to existing power plants) compared to the other two approaches. Therefore, post-combustion capture is probably the first technology that will be deployed. This paper aims to provide a state-of-the-art assessment of the research work carried out so far in post-combustion capture with chemical absorption. The technology will be introduced first, followed by required preparation of flue gas from power plants to use this technology. The important research programmes worldwide and the experimental studies based on pilot plants will be reviewed. This is followed by an overview of various studies based on modelling and simulation. Then the focus is turned to review development of different solvents and process intensification. Based on these, we try to predict challenges and potential new developments from different aspects such as new solvents, pilot plants, process heat integration (to improve efficiency), modelling and simulation, process intensification and government policy impact.  相似文献   

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