Purification of oxyfuel-derived CO2

Oxyfuel combustion in a pulverised fuel coal-fired power station produces a raw CO₂ product containing contaminants such as water vapour plus oxygen, nitrogen and argon derived from the excess oxygen for combustion, impurities in the oxygen used, and any air leakage into the system. There are also acid gases present, such as SO₃, SO₂, HCl and NO_x produced as byproducts of combustion. At GHGT8 (White and Allam, 2006) we presented reactions that gave a path-way for SO₂ to be removed as H₂SO₄ and NO and NO₂ to be removed as HNO₃. In this paper we present initial results from the OxyCoal-UK project in which these reactions are being studied experimentally to provide the important reaction kinetic information that is so far missing from the literature. This experimental work is being carried out at Imperial College London with synthetic flue gas and then using actual flue gas via a sidestream at Doosan Babcock's 160 kW coal-fired oxyfuel rig. The results produced support the theory that SO_x and NO_x components can be removed during compression of raw oxyfuel-derived CO₂ and therefore, for emissions control and CO₂ product purity, traditional FGD and deNO_x systems should not be required in an oxyfuel-fired coal power plant.     

Flue gas desulphurization for hot recycle Oxyfuel combustion: Experiences from the 30 MWth Oxyfuel pilot plant in Schwarze Pumpe

Significant differences exist in the flue gas composition in hot recycle Oxyfuel conditions as e.g. the high CO₂ partial pressure (>90 vol%, dry), the very high SO₂ concentration and the high water content (approx. 30 vol%). Therefore certain design and operation criteria have to be observed for the flue gas desulphurization with forced oxidation under Oxyfuel combustion conditions. Several performance tests have been executed at the 30 MW_th Oxyfuel pilot plant in Schwarze Pumpe to evaluate the main performance parameters and to assess the influence of the major operation parameters. The results show that there are no fundamental problems for the operation of the flue gas desulphurization unit under Oxyfuel combustion conditions. High removal rates could be reached and no negative impact of the high CO₂ partial pressure was observed under the tested operating conditions. No major differences in the gypsum quality have been observed between air firing and Oxyfuel conditions.     

Power generation with CO2 capture: Technology for CO2 purification

The goal of this paper is to find methodologies for removing a selection of impurities (H₂O, O₂, Ar, N₂, SO_x and NO_x) from CO₂ present in the flue gas of two oxy-combustion power plants fired with either natural gas (467 MW) or pulverized fuel (596 MW). The resulting purified stream, containing mainly CO₂, is assumed to be stored in an aquifer or utilized for enhanced oil recovery (EOR) purposes. Focus has been given to power cycle efficiency i.e.: work and heat requirements for the purification process, CO₂ purity and recovery factor (kg of CO₂ that is sent to storage per kg of CO₂ in the flue gas). Two different methodologies (here called Case I and Case II) for flue gas purification have been developed, both based on phase separation using simple flash units (Case I) or a distillation column (Case II). In both cases purified flue gas is liquefied and its pressure brought to 110 atm prior to storage.Case I: A simple flue gas separation takes place by means of two flash units integrated in the CO₂ compression process. Heat in the process is removed by evaporating the purified liquid CO₂ streams coming out from both flashes. Case I shows a good performance when dealing with flue gases with low concentration of impurities. CO₂ fraction after purification is over 96% with a CO₂ recovery factor of 96.2% for the NG-fired flue gas and 88.1% for the PF-fired flue gas. Impurities removal together with flue gas compression and liquefaction reduces power plant output of 4.8% for the NG-fired flue gas and 11.6% for the PF-fired flue gas. The total amount of work requirement per kg stored CO₂ is 453 kJ for the NG-fired flue gas and 586 kJ for the PF-fired flue gas.Case II: Impurities are removed from the flue gas in a distillation column. Two refrigeration loops (ethane and propane) have been used in order to partially liquefy the flue gas and for heat removal from a partial condenser. Case II can remove higher amounts of impurities than Case I. CO₂ purity prior to storage is over 99%; CO₂ recovery factor is somewhat lower than in Case I: 95.4% for the NG-fired flue gas and 86.9% for the PF-fired flue gas, reduction in the power plant output is similar to Case I.Due to the lower CO₂ recovery factor the total amount of work per kg stored CO₂ is somewhat higher for Case II: 457 kJ for the NG-fired flue gas and 603 kJ for the PF-fired flue gas.     

Comparison of data-based methods for monitoring of air leakages into oxyfuel power plants

Air leakages compromise the CO₂ capture rate and auxiliary power consumption of oxyfuel power plants. Constructive measures can significantly improve the leakage rate in newly built plants. However, the mitigation of increasing leakage rates during the plant lifetime is crucial for high plant efficiency. In this paper, we apply three statistical methods on experimental process data gathered in an air leakage test in Vattenfall's Oxyfuel Pilot Plant in Schwarze Pumpe, Germany. The performance of the methods in identifying increasing leakage rates and localizing the leakage source is investigated. It was found that all three methods can identify and localize even small increases of the leakage rate. A combination of all three methods allows taking advantage of the individual features of each method. Additional installation of CO₂, O₂, H₂O, and SO₂ measurements in the oxidizer can considerably enhance localization performance. Finally, it is shown that the results can be transferred to commercial-scale oxyfuel pilot plants by generating training data with thermodynamic plant models.     

Study of individual reactions of the sour compression process for the purification of oxyfuel-derived CO2

Following the feasibility study of sour compression process as a novel purification method of producing NO_x-free, SO₂-free oxyfuel-derived CO₂ using actual fluegas, in this paper, we present the study of the individual reactions taking place in the process in a controlled environment. We have previously showed that an increase of NO/NO₂ concentration in the inlet stream is beneficial for SO₂ removal as NO₂ promotes SO₂ oxidation and the further removal as liquid acid. In this study we show that the reaction SO₂ + NO₂ → SO₃ + NO does not take place significantly in the absence of liquid water at a range of conditions relevant to the sour compression process. When liquid water is present, SO₂ is oxidised by NO₂ regenerating NO with the rate of conversion of SO₂ being dependent on the acid concentration in the liquid. The formation of small liquid droplets where very low levels of pH (?0) can be reached is shown to be of great importance to the SO₂ + NO₂ conversion process.     

Assessment of the different parameters affecting the CO2 purity from coal fired oxyfuel process

The oxyfuel process is one of the most promising options to capture CO₂ from coal fired power plants. The combustion takes place in an atmosphere of almost pure oxygen, delivered from an air separation unit (ASU), and recirculated flue gas. This provides a flue gas containing 80–90 vol% CO₂ on a dry basis. Impurities are caused by the purity of the oxygen from the ASU, the combustion process and air ingress. Via liquefaction a CO₂ stream with purity in the range from 85 to 99.5 vol% can be separated and stored geologically. Impurities like O₂, NO_X, SO_X, and CO may negatively influence the transport infrastructure or the geological storage site by causing geochemical reactions. Therefore the maximum acceptable concentrations of the impurities in the separated CO₂ stream must be defined regarding the requirements from transportation and storage. The main objective of the research project COORAL therefore is to define the required CO₂ purity for capture and storage.     

Study of Hg and SO3 behavior in flue gas of oxy-fuel combustion system

Oxy-fuel combustion systems have been under development to reduce CO₂ emissions from coal-fired power plants. In oxy-fuel combustion system, Hg in the flue gas causes corrosion in CO₂ purification and compression units. Also, SO₃ in the flue gas corrodes the equipment and ducts of oxy-fuel combustion system. Therefore, Hg and SO₃ need to be removed.Babcock-Hitachi conducted tests using a 1.5 MWth Combustion & Air Quality Control System (AQCS) test facility which consists of oxygen supply unit, furnace, Selective Catalytic Reduction (SCR) catalyst, Clean Energy Recuperator (CER), Dry Electrostatic Precipitator (DESP), flue gas recirculation system, Wet Flue Gas Desulfurization (WFGD), and CO₂ Compression and Purification Unit (CPU). In both cases of air and oxy-fuel combustion, the Hg removal across the DESP could be improved, and SO₃ concentration at the DESP outlet could be reduced to less than 1 ppm by installing a CER upstream of the DESP and reducing the gas temperature at the DESP inlet. Hg was not dissolved in the drain recovered from CO₂ compressor, and may be adsorbed at an inner part of CO₂ compressor. This indicated that Hg needs to be removed at a location upstream of the CO₂ compressor to prevent corrosion of the compressor.     

Mercury measurement and control in a CO2-enriched flue gas

Oxycombustion is being considered as a promising solution to carbon capture and sequestration. Standard sampling and measurement methods may or may not be valid under oxycombustion conditions because the flue gas differs significantly from that of conventional air-blown coal combustion.Bench-scale tests were conducted to evaluate the measurement validity of continuous mercury monitors (CMMs), with and without a flue gas preconditioning unit, in a simulated oxycombustion flue gas with varied CO₂ concentrations. Tests also included mercury capture with activated carbon in typical oxyfuel combustion flue gas. Research data indicated that highly concentrated CO₂ streams affect the accuracy of the mass flow rate and the subsequent gaseous mercury measurement, although this is specific to the type of CMM. Concentrated CO₂ streams also induced solid precipitation in the wet-chemistry conversion unit and resulted in a biased measurement of the gas-phase mercury. Flue gas dilution appeared to provide accurate measurement of total gas-phase mercury and be applicable to mercury measurement in highly concentrated CO₂ streams, although mercury speciation appeared to be problematic and will require additional modification and validation. Mercury capture with activated carbon under CO₂-enriched conditions showed similar performance to typical high-acid coal combustion flue gas.     

Assessing the current practice and policy with recommendations for emission control strategy for coal‐fired thermal power plants under Indian regulatory framework emphasizing the roles of R&D

On December 7, 2015, the Ministry of Environment, Forest and Climate Change (MoEFCC), Government of India (GoI), promulgated stack emission standards for sulfur dioxide (SO₂), oxides of nitrogen (NO_x), and mercury (Hg) from coal‐fired thermal power plants (TPPs). These standards were promulgated in addition to tightening the emission standard for particulate matter. Thus far, the GoI and a non‐governmental organization (NGO) have recommended the use of limestone‐based flue‐gas desulfurization (FGD) technology for removing only SO₂ emissions, which would then require the application of additional technologies to remove the other regulated pollutants. A single technology, such as the Multi‐pollutants Control Technology (MPCT), which was recently developed elsewhere in the world and can remove all of the pollutants from the TPP, could be more economical than introducing separate technologies for the removal of each pollutant. Furthermore, unlike the limestone‐based FGD technology, which generates carbon dioxide (CO₂) during the desulfurization process, the MPCT does not increase power plant CO₂ emissions. Water consumption is also lower in MPCT than with the limestone‐based FGD technology. Thus, MPCT offers a lower carbon footprint as well as a lower water footprint than the limestone‐based FGD technology in accordance with the United Nations Environmental Programme's Sustainable Development Goals. In light of these observations, this article aims to assess current practices and policies and offers policy recommendations for Indian TPPs with the goal of providing a cogent technological solution that also strengthens the Decision Support System for the holistic protection of the Indian environment.     

Hollow fiber membrane separation process in the presence of gaseous and particle impurities for post-combustion CO2 capture

The membrane separation process for CO₂ capture can be interfered by the gaseous components and the fine particles in flue gas, especially in desulfurized flue gas. In this work, the pint-sized Polyimide(PI) hollow fiber membrane contactors were self-packed to investigate the membrane CO₂ separation from flue gas containing fine particles and gaseous contaminants (SO₂,SO₃,H₂O). First, the effects of SO₂, SO₃, water vapor, and gypsum particles on the CO₂ capture were studied independently and synergistically. The results showed that the effect of SO₂ on the membrane separation properties is indistinctive; however, the membrane performance was damaged seriously with the addition of SO₃. The high humidity promoted the CO₂ separation initially before inhibiting the PI membrane performance. Moreover, the decrease of the CO₂/N₂ selectivity and the permeation rate were accelerated with the coexistence of SO₂. The membrane performance showed an obvious deterioration in the presence of gypsum particles, with a 21% decrease in the CO₂/N₂ selectivity and 51% decrease in the permeation rate. Furthermore, the gypsum particles exerted dramatic damage. Under the WFGD conditions, the combined effects of SO₂, water vapor, and the gypsum particles influenced the stability of the membrane significantly. This tendency is mainly attributed to the deposition of fine particles and aerosol on the membrane surface, which occupied the effective area and enhanced the mass transfer resistance. This study of impurities’ influence could play an important role in further industrial application of membrane CO₂ capture.     

Life cycle assessment of a pulverized coal power plant with post-combustion capture, transport and storage of CO2

In this study the methodology of life cycle assessment has been used to assess the environmental impacts of three pulverized coal fired electricity supply chains with and without carbon capture and storage (CCS) on a cradle to grave basis. The chain with CCS comprises post-combustion CO₂ capture with monoethanolamine, compression, transport by pipeline and storage in a geological reservoir. The two reference chains represent sub-critical and state-of-the-art ultra supercritical pulverized coal fired electricity generation. For the three chains we have constructed a detailed greenhouse gas (GHG) balance, and disclosed environmental trade-offs and co-benefits due to CO₂ capture, transport and storage. Results show that, due to CCS, the GHG emissions per kWh are reduced substantially to 243 g/kWh. This is a reduction of 78 and 71% compared to the sub-critical and state-of-the-art power plant, respectively. The removal of CO₂ is partially offset by increased GHG emissions in up- and downstream processes, to a small extent (0.7 g/kWh) caused by the CCS infrastructure. An environmental co-benefit is expected following from the deeper reduction of hydrogen fluoride and hydrogen chloride emissions. Most notable environmental trade-offs are the increase in human toxicity, ozone layer depletion and fresh water ecotoxicity potential for which the CCS chain is outperformed by both other chains. The state-of-the-art power plant without CCS also shows a better score for the eutrophication, acidification and photochemical oxidation potential despite the deeper reduction of SO_x and NO_x in the CCS power plant. These reductions are offset by increased emissions in the life cycle due to the energy penalty and a factor five increase in NH₃ emissions.     

Thermodynamic and Economic Aspects of the Hard Coal Based Oxyfuel Cycle

The present study shows a new approach in modelling the hard coal fired Oxyfuel Cycle on the whole. The static process model comprises an Oxyfuel combustion principle applied to an existing state-of-the-art hard coal power plant located in Rostock, Germany. It includes the air separation unit and the flue gas liquefaction unit, which are modelled in detail. As one of the main advances to previous work, the closed simulation of all components in one model delivers a coherent solution with a significantly reduced number of assumptions. The model needs no interfaces between different stand alone simulation tools or manual iteration and transfer of internal variables. Results from a thermodynamic and economic feasibility study on this process are shown and areas relevant for future research are identified.

The present study shows the feasibility and prospective key figures of the technology under realistic, comparable and reproducible assumptions and boundary conditions. The basic engineering of the process with a detailed study of the necessary gas separation and flue gas handling technologies is undertaken in the effort to a first stage optimisation of the process.

The flowsheet tool Aspen Plus (TM) was used to simulate the overall process. This particular tool was chosen because it offers an advanced data library on chemical substances and allows the calculation of phase equilibria and real gas behaviour during air separation and flue gas liquefaction. Emissions, coal consumption and investment costs of the Oxyfuel power plant are compared to those of the original state-of-the-art hard coal power plant which is used as the reference case.     

Drying of granulated wood ash by flue gas from saw dust and natural gas combustion

At the district heating plant of Kalmar, Sweden an on-line unit for production of granulated wood ash for nutrient recycling on forest soils is being applied. Currently, the granules are dried by hot air from an oil-fired burner. The objective of this work was to investigate how drying by flue gas affects the hardening of granules, or impacts their chemical composition and properties. Ninety-six granule samples were treated by flue gas from natural gas combustion in a laboratory pilot scale flue gas generator. CO₂, CO, O₂, C₃H₈ and NO concentrations were varied during the experiment. Additionally, some samples were treated by flue gas from combustion of sawdust at the heating plant in Kalmar. Drying by flue gases did not affect the chemical composition of granules, but minor effects were seen in their mineralogy. The carbonate content was slightly higher in granules treated with flue gas from natural gas combustion compared to the granules dried by hot air only, when measured by wet chemical methods. Results from XRD analysis imply that the calcite content is higher and the portlandite and arcanite content slightly less in granules treated with flue gas from sawdust combustion compared to the granules dried by hot air only. The results from this investigation showed no negative effects on ash granule composition or physical structure by the use of a flue as a drying medium.     

Life cycle assessment of carbon dioxide capture and storage from lignite power plants

In this article, we present a life cycle assessment (LCA) of CO₂ capture and storage (CCS) for several lignite power plant technologies. The LCA includes post-combustion, pre-combustion and oxyfuel capture processes as well as subsequent pipeline transport and storage of the separated CO₂ in a depleted gas field.The results show an increase in cumulative energy demand and a substantial decrease in greenhouse gas (GHG) emissions for all CO₂ capture approaches in comparison with power plants without CCS, assuming negligible leakage within the time horizon under consideration. Leakage will, however, not be zero. Due to the energy penalty, CCS leads to additional production of CO₂. However, the CO₂ emissions occur at a much lower rate and are significantly delayed, thus leading to different, and most likely smaller, impacts compared to the no-sequestration case. In addition, a certain share of the CO₂ will be captured permanently due to chemical reactions and physical trapping.For other environmental impact categories, the results depend strongly on the chosen technology and the details of the process. The post-combustion approach, which is closest to commercial application, leads to sharp increases in many categories of impacts, with the impacts in only one category, acidification, reduced. In comparison with a conventional power plant, the pre-combustion approach results in decreased impact in all categories. This is mainly due to the different power generation process (IGCC) which is coupled with the pre-combustion technology.In the case of the oxyfuel approach, the outcome of the LCA depends highly on two uncertain parameters: the energy demand for air separation and the feasibility of co-capture of pollutants other than CO₂. If co-capture were possible, oxyfuel could lead to a near-zero emission power plant.     

Design and off-design analyses of a pre-combustion CO2 capture process in a natural gas combined cycle power plant

In this study, a cycle designed for capturing the greenhouse gas CO₂ in a natural gas combined cycle power plant has been analyzed. The process is a pre-combustion CO₂ capture cycle utilizing reforming of natural gas and removal of the carbon in the fuel prior to combustion in the gas turbine. The power cycle consists of a H₂-fired gas turbine and a triple pressure steam cycle. Nitrogen is used as fuel diluent and steam is injected into the flame for additional NO_x control. The heat recovery steam generator includes pre-heating for the various process streams. The pre-combustion cycle consists of an air-blown auto-thermal reformer, water–gas shift reactors, an amine absorption system to separate out the CO₂, as well as a CO₂ compression block. Included in the thermodynamic analysis are design calculations, as well as steady-state off-design calculations. Even though the aim is to operate a plant, as the one in this study, at full load there is also a need to be able to operate at part load, meaning off-design analysis is important. A reference case which excludes the pre-combustion cycle and only consists of the power cycle without CO₂ capture was analyzed at both design and off-design conditions for comparison. A high degree of process integration is present in the cycle studied. This can be advantageous from an efficiency stand-point but the complexity of the plant increases. The part load calculations is one way of investigating how flexible the plant is to off-design conditions. In the analysis performed, part load behavior is rather good with efficiency reductions from base load operation comparable to the reference combined cycle plant.     

Effect of oxygenated liquid additives on the urea based SNCR process

An experimental investigation was performed to study the effect of oxygenated liquid additives, H₂O₂, C₂H₅OH, C₂H₄(OH)₂ and C₃H₅(OH)₃ on NO_x removal from flue gases by the selective non-catalytic reduction (SNCR) process using urea as a reducing agent. Experiments were performed with a 150 kW pilot scale reactor in which a simulated flue gas was generated by the combustion of methane operating with 6% excess oxygen in flue gases. The desired levels of initial NO_x (500 ppm) were achieved by doping the fuel gas with ammonia. Experiments were performed throughout the temperature range of interest, i.e. from 800 to 1200 °C for the investigation of the effects of the process additives on the performance of aqueous urea DeNO_x. With H₂O₂ addition a downward shift of 150 °C in the peak reduction temperature from 1130 to 980 °C was observed during the experimentation, however, the peak reduction efficiency was reduced from 81 to 63% when no additive was used. The gradual addition of C₂H₅OH up to a molar ratio of 2.0 further impairs the peak NO_x reduction efficiency by reducing it to 50% but this is accompanied by a downward shift of 180 °C in the peak reduction temperature. Further exploration using C₂H₄(OH)₂ suggested that a 50% reduction could be attained for all the temperatures higher than 940 °C. The use of C₃H₅(OH)₃ as a secondary additive has a significant effect on the peak reduction efficiency that decreased to 40% the reductions were achievable at a much lower temperature of 800 °C showing a downward shift of 330 °C.     

Life cycle assessment of natural gas combined cycle power plant with post-combustion carbon capture,transport and storage

Hybrid life cycle assessment has been used to assess the environmental impacts of natural gas combined cycle (NGCC) electricity generation with carbon dioxide capture and storage (CCS). The CCS chain modeled in this study consists of carbon dioxide (CO₂) capture from flue gas using monoethanolamine (MEA), pipeline transport and storage in a saline aquifer.Results show that the sequestration of 90% CO₂ from the flue gas results in avoiding 70% of CO₂ emissions to the atmosphere per kWh and reduces global warming potential (GWP) by 64%. Calculation of other environmental impacts shows the trade-offs: an increase of 43% in acidification, 35% in eutrophication, and 120–170% in various toxicity impacts. Given the assumptions employed in this analysis, emissions of MEA and formaldehyde during capture process and generation of reclaimer wastes contributes to various toxicity potentials and cause many-fold increase in the on-site direct freshwater ecotoxicity and terrestrial ecotoxicity impacts. NO_x from fuel combustion is still the dominant contributor to most direct impacts, other than toxicity potentials and GWP. It is found that the direct emission of MEA contribute little to human toxicity (HT < 1%), however it makes 16% of terrestrial ecotoxicity impact. Hazardous reclaimer waste causes significant freshwater and marine ecotoxicity impacts. Most increases in impact are due to increased fuel requirements or increased investments and operating inputs.The reductions in GWP range from 58% to 68% for the worst-case to best-case CCS system. Acidification, eutrophication and toxicity potentials show an even large range of variation in the sensitivity analysis. Decreases in energy use and solvent degradation will significantly reduce the impact in all categories.     

Continuous operation of the potassium-based dry sorbent CO2 capture process with two fluidized-bed reactors

The dry sorbent CO₂ capture process is an advanced concept to efficiently remove CO₂ from flue gas with two fluidized-bed reactors. This paper summarizes the results of performance of the two fluidized-bed reactors in the continuous solid circulation mode to investigate the feasibility of using potassium carbonate-based solid sorbent (Sorb KX35). The parameters such as gas velocity, solid circulation, carbonation temperature, and water vapor content were investigated during several continuous operations of two fluidized-bed reactors. The CO₂ removal increased as gas velocity was decreased and as solid circulation rate was increased. The CO₂ removal ranged from 26% to 73% was rather sensitive to the water vapor content among other parameters. A 20 h continuous operation conducted in a bench scale fast fluidized-bed reactor system indicated that the spray-dried potassium-based sorbent, Sorb KX35 having superior attrition resistance and high bulk density, had a promising CO₂ removal capacity of 50–73% at steady state and was able to regenerate and reuse. The results from this work are good enough to prove the concept of the dry sorbent CO₂ capture process to be one of viable methods for capturing CO₂ from dilute flue gas of fossil fuel-fired power plants.     

The challenge in understanding the corrosion mechanisms under oxyfuel combustion conditions

Basic research on the corrosive effect of flue gases has been performed at the BAM Federal Institute for Materials Research and Testing (Germany). Conditions at both high and low temperatures were simulated in specially designed experiments. Carburization occured in flue gases with high CO₂ content and temperatures higher than 500 °C. In SO₂ containing flue gases sulphur was detected in the oxide scale. At lower temperatures no corrosion was observed when gases with low humidity were investigated. Humidity higher than 1500 ppm was corrosive and all steels with Cr contents lower than 12% revealed corroded surfaces. At low temperatures below 10 °C a mixture of sulphuric and nitric acid condensed on metal surfaces. Acid condensation caused severe corrosion. Humidity, CO₂, O₂, and SO₂ contents are the important factors determining corrosion. Below 300 °C acid condensation is the primary reason for corrosion. Low humidity and low temperatures are conditions which can be expected in the CO₂ separation and treatment process. This work includes major conditions of the flue gas and CO₂ stream in CCS plants and CCS technology.     

Integration of post-combustion capture and storage into a pulverized coal-fired power plant

Post-combustion CO₂ capture and storage (CCS) presents a promising strategy to capture, compress, transport and store CO₂ from a high volume–low pressure flue gas stream emitted from a fossil fuel-fired power plant. This work undertakes the simulation of CO₂ capture and compression integration into an 800 MW_e supercritical coal-fired power plant using chemical process simulators. The focus is not only on the simulation of full load of flue gas stream into the CO₂ capture and compression, but also, on the impact of a partial load. The result reveals that the energy penalty of a low capture efficiency, for example, at 50% capture efficiency with 10% flue gas load is higher than for 90% flue gas load at the equivalent capture efficiency by about 440 kWh_e/tonne CO₂. The study also addresses the effect of CO₂ capture performance by different coal ranks. It is found that lignite pulverized coal (PC)-fired power plant has a higher energy requirement than subbituminous and bituminous PC-fired power plants by 40.1 and 98.6 MW_e, respectively. In addition to the investigation of energy requirement, other significant parameters including energy penalty, plant efficiency, amine flow rate and extracted steam flow rate, are also presented. The study reveals that operating at partial load, for example at half load with 90% CO₂ capture efficiency, as compared with full load, reduces the energy penalty, plant efficiency drop, amine flow rate and extracted steam flow rate by 9.9%, 24.4%, 50.0% and 49.9%, respectively. In addition, the effect of steam extracted from different locations from a series of steam turbine with the objective to achieve the lowest possible energy penalty is evaluated. The simulation shows that a low extracted steam pressure from a series of steam turbines, for example at 300 kPa, minimizes the energy penalty by up to 25.3%.