- Email: [email protected]
Investigating the dynamic response of CO2 chemical absorption process in enhanced- O2 coal power plant with post-combustion CO2 capture
Energy Procedia 4 (2011) 1035–1042
Energy Procedia www.elsevier.com/locate/procedia
Energy Procedia 00 (2010) 000–000 www.elsevier.com/locate/XXX
GHGT-10
Investigating the dynamic response of CO2 chemical absorption process in enhanced-O2 coal power plant with post-combustion CO2 capture Adekola Lawala, Meihong Wanga,1*, Peter Stephensonb a
Process Systems Engineering Group, School of Engineering, Cranfield University, Bedfordshire, MK43 0AL, UK b RWE npower, Windmill Park, Swindon, SN5 6PB, UK Elsevier use only: Received date here; revised date here; accepted date here
Abstract
Studies have been carried out to show that there could be benefits in employing a hybrid of the post combustion capture and oxyfuel processes. The former is suited for retrofit purposes but involves an energy intensive solvent regeneration process. The oxyfuel process would result in high partial pressures of CO2 in the flue gas making separation easier. However, the Air Separation Unit is also energy intensive and significant modifications would have to be made on the power generation process. An enhanced-O2 coal power plant with post combustion CO2 capture would produce flue gas with reduced mass flow and higher CO2 partial pressures. The dynamic response of the downstream CO2 capture plant was studied in this paper. © Elsevier Ltd. All rights c 2010 ⃝ 2011 Published by Elsevier Ltd.reserved Keywords: CO2 Capture; Post-combustion; Chemical absorption; Dynamic modelling; Coal-fired power plant
1. Introduction Post-combustion capture by chemical absorption using monoethanolamine (MEA) solvent is well suited for treating flue gas streams with low CO2 partial pressures typical of coal-fired power plants. The drawback of this process is the high energy requirement for solvent regeneration. However, it requires minimal modifications to the combustion process and is thus well suited for retrofit options. The oxyfuel process produces a flue gas stream that has a high CO2 partial pressure which makes CO2 separation considerably easier. However, the Air Separation Unit (ASU) would require large quantities of energy to generate the amounts of oxygen needed for the conventional oxyfuel process. In addition, significant modifications to the boiler are required when firing pulverized fuel in a concentrated oxygen stream instead of air. Doukelis et al. (2009) show that there could be benefits in a combination of these two types of CO2 capture technologies, resulting in a partial oxyfuel mode in the furnace and the post-combustion solvent scrubbing. They suggested that this option may be particularly beneficial when retrofitting existing power
* Corresponding author. Tel.: +44-1234-754655; fax: +44-1234-754685. E-mail address: [email protected].
doi:10.1016/j.egypro.2011.01.152
1036
A. Lawal et al. / Energy Procedia 4 (2011) 1035–1042 Lawal et al./ Energy Procedia 00 (2010) 000–000
2
plants. This study investigates the operation of the chemical absorption process downstream an enhanced-O2 coal power plant using dynamic modelling and simulation. 2. Operation of an enhanced-O2 coal power plant and CO2 chemical absorption plant The schematic of the enhanced-O2 coal power plant with post-combustion CO2 capture is shown in Figure 1. It is proposed that coal is combusted in an oxygen-enriched environment to increase the CO2 partial pressure in the flue gas to an optimal level (Doukelis et al, 2009). Oxygen is produced in the ASU typically up to 95vol% purity (Wall et al, 2009). This stream is mixed with secondary air prior to combustion. It is not advisable to increase the O2 partial pressure of the primary air since the stream is mixed with the pulverized fuel and increased O2 concentrations could result in explosions. To keep temperatures down to acceptable levels, flue gas is recycled (and mixed with the primary and secondary air stream) as shown in Figure 1. This also results in an increase in the CO2 partial pressure in the flue gas.
NITROGEN
ASU
OXYGEN
SECONDARY AIR
FLUE GAS RECYCLE FLUE GAS FROM FURNACE
REMOVAL OF NOX AND SOX AND FLUE GAS COOLING
BOILER
AIR
FUEL AMINE CO2 CAPTURE PLANT
MILLS
TREATED FLUE GAS
PRIMARY AIR CO2 PRODUCT
Figure 1 Schematic of an enhanced-O2 coal power plant with post-combustion CO2 capture (adapted from Doukelis et al, 2009) The ratio of the flue gas recycle flow to the flow of flue gas from furnace is referred to here as the recirculation fraction. The estimated compositional and flue gas flow changes observed with oxygen enrichment is shown in Figure 2 for a 600MWe supercritical power plant. In this case, the O2 concentrations in the primary and secondary air range from 21 vol% to 50 vol%. Though the oxygen stream is mixed with the secondary air, the percentage of oxygen discussed is relative to the total of the primary air and secondary air flows to the furnace of the boiler. By maintaining the primary air stream as air and keeping the primary air/fuel ratio, there is an upper limit of 50-60% in the oxygen enrichment possible. The methodology for calculating the flue gas flowrate and CO2 concentration in flue gas from the enhanced-O2 coal plant is presented in Fleche (2009) and Huang et al. (2010). The estimates of the composition of the flue gas were based on the assumption that the fuel specifications and fuel burn rates are kept constant and there is no leakage along the path to the capture plant. The mass flow of CO2 in the flue gas is constant (based on the assumption of
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constant fuel burn rates) while the flue gas total mass flow reduces with the recirculation rate. A steady increase in the CO2 volume fraction in the flue gas is also observed.
CO2 volume fraction
Figure 2 Changes in flue gas mass flow, required recirculation rates and CO2 composition in flue gas with oxygen enrichment
3. CO2 capture model development Chemical absorption is a reactive absorption process. This phenomenon involves the combination of mass transfer and chemical reaction of CO2 with a chemical solvent. Both processes are dependent on the concentration/partial pressure of CO2 in the flue gas. Thus changes in this composition would significantly affect the performance of the process (even with the same quantity of CO2 for capture). MEA solvent could be used to chemically absorb CO2 in the flue gas from the power plant in an absorber and the solvent solution is regenerated in a regenerator column using steam from the power generation process (Dugas, 2006). The gPROMS advanced process modelling environment has been used to develop the required dynamic models. The absorber and regenerator columns were modelled based on the Gas-Liquid Contactor model from Process Systems Enterprise’s Advanced Model Library. Mass transfer rates were modelled based on the two-film theory using the Maxwell-Stefan formulation while the reactions were assumed to attain equilibrium. In developing this dynamic model, the following were assumed: 1 Linear pressure drop along the column 2 Phase equilibrium exists at interface between liquid and vapour films 3 There is negligible solvent degradation 4 There is negligible heat loss in the absorber column 5 There is no water wash section in the absorber The model topology of the process in gPROMS is shown in Figure 3.
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A. Lawal et al. / Energy Procedia 4 (2011) 1035–1042 Lawal et al./ Energy Procedia 00 (2010) 000–000
Figure 3 Model topology in gPROMS Five main control schemes are used in the process. PI controllers are used for temperature control of the regenerator column by manipulating the condenser and reboiler heat duties. The reboiler level was controlled using a P controller by manipulating the reboiler bottoms flow. This is the liquid lean MEA solvent flow from the reboiler to the cross heat exchanger. Water balance is achieved by controlling the water mass fraction in the lean solvent with the water makeup flow rate used as manipulated variable. Finally a capture level controller measures the captured CO2 and controls it by manipulating the lean solvent flow to the absorber (Lawal et al, 2010). The cross heat exchanger was sized to yield the reported regenerator feed temperature and a temperature approach of over 15°C. The pressure of the partial condenser is also assigned to maintain the regenerator operating pressure.
4. CO2 capture model validation The steady-state validation of the chemical absorption plant model was carried out using data from the one of the cases of the Separations Research Program at the University of Texas at Austin (Dugas, 2006). The absorber and regenerator columns of the pilot plant are both packed columns with diameters of 0.427m and total packing height of 6.1m. It is shown that the models give good predictions of the shape of the temperature profiles for both absorber and regenerator (referred to as the rate-based stand-alone model) (Lawal et al, 2009a). Further validation studies have been carried out for the amine plant set-up (where the absorber and regenerator columns have been linked with recycle referred to as the rate-based integrated model) (Lawal et al, 2009b; Lawal et al, 2010). Validation results are shown for the absorber and regenerator in Figure 4.
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5
Case 32 Regenerator Temperature Profile
Case 32 Absorber Temperature Profile
400
345 340
Pilot Plant Measurements
390 335
Pilot plant Measurements
325
Rate-based Integrated model
320
Rate-based Standalone model
315
Rate-Based Integrated Model Rate-Based Stand-alone Model
380
Temperature (K)
Temperature (K)
330
370 360
310
350 305
340
300 -2
0
2
4
6
8
10
Height from bottom of packing (m)
-2
0
2
4
6
8
10
Height from the bottom of packing (m)
(a) (b) Figure 4 (a) Absorber and (b) Regenerator temperature profile of columns for Case 32 The steady state predictions of the integrated model were found to be slightly better than the standalone models. In the latter, estimates of the input to the column had to be made and errors in such guesses would affect overall results. This suggests that the model predicts the interaction between the component parts of the plant (mainly the two columns) fairly well. It should be noted that the pilot plant in the study used to validate these results did not have a cross heat exchanger but used a combination of a heater and cooler (Lawal et al, 2010). 5. Dynamic analysis of ASU plant start-up The enrichment of oxygen content in the primary and secondary air supplied to the furnace from atmospheric concentrations of 21% by volume to about 50% by volume would result in changes in the flue gas composition as discussed in Section 2. Similar compositional changes would occur despite the scale employed. Therefore, the validated model for CO2 capture at pilot plant scale could be used to carry out the dynamic studies with the main difference being the absolute flow rates involved. The CO2 mass flow to the absorber was fairly constant while the total mass flow rate of the flue gas was correspondingly reduced (Figure 5). Water vapour content in the flue gas was assumed to remain constant at 1.5wt%. Steady state conditions were maintained for two hours then a slow ASU ramp rate of 1% increase per minute was assumed. Conditions were maintained for about 10 hours. In the first case (Case 1), solvent circulation rates remained unchanged and in the second (Case 2), the rates were adjusted by a controller to maintain CO2 capture levels at 96.7%.
CO2 mass fraction N2 mass fraction Flue gas mass flow
Figure 5 Change in flue gas composition and mass flow rate with ASU start-up
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Figure 6 Effects of increasing O2 enrichment in furnace primary and secondary air on capture process Figure 6 shows the effects of oxygen enrichment on the chemical absorption process without control of capture level or Case 1 (a-c) and the corresponding results with control or Case 2 (d-f). With oxygen enrichment, CO2 partial pressures in the flue gas are significantly increased, thus increasing driving forces for absorption thus significantly increasing capture levels (Figure 6a). The observed dip in capture level is probably due to increased absorber column temperature. This drop would not be observed with a steady state simulation. Figure 6c shows the temperature profile variations with time. With O2 enrichment in the primary and secondary air, the partial pressure of CO2 in the flue gas increases which causes more CO2 to react with MEA releasing more heat of reaction. In addition, there is less quantity of flue gas to exchange heat with, so a sharp rise in temperature occurs which would reduce CO2 solubility in the solvent and thus reduce absorption levels. As the capture levels begin to rise and approach 100%, most of the absorption takes place close to the bottom of the packing and the temperature of the solvent dominates in the column temperature profile. This effect is the case especially since it appears that without control, excessive solvent is circulated for capture. Since more CO2 reacts with MEA, the rich solvent loading increases and the heat requirement for capture reduces (Figure 6b). The heat requirement for capture before and after the oxygen enrichment was relatively high (>3.9MJ/kg CO2) because of the relatively high level of capture that is attained (96.7% as compared with the conventional 90%). As capture level targets increase (whilst all other factors are constant), the heat efficiency of the capture process inadvertently drops. However, without capture level control,
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excessive solvent is circulated, the capture efficiency tends to 100% and the heat requirement for capture begins to rise again owing to the extra heat needed to heat up the excess solvent. With the capture level controller active (Figure 6d), such excesses are avoided and the heat requirement for absorption remains low – about 10% lower compared to the previous steady state (Figure 6e). The temperature in the column generally increases with CO2 concentration and remains relatively high. This is because, as explained earlier, more heat of reaction is released and there is less quantity of gas to exchange heat with. The temperature bulge is roughly in the same position but the temperature profile is flatter than before the enrichment commenced implying higher temperatures in more parts of the column. The performance of the system could possibly be improved if absorber temperatures are minimized. This could be achieved by employing a split-flow configuration where lean MEA solvent is supplied to the top and middle of the absorber column (Kohl and Nielson, 1997).
6. Conclusions
The dynamic response of the CO2 capture plant with enrichment of oxygen content in the primary and secondary air supplied to the furnace from atmospheric concentrations to about 50% by volume was studied. The resulting flue gas compositions with various degrees of O2 enrichment have been calculated. Using a rate-based dynamic model of the chemical absorption process, two cases were studied – x CO2 capture performance with O2 enrichment and a constant solvent circulation rate x CO2 capture performance with O2 enrichment and a controlled circulation rate to maintain a constant capture level. It was shown that higher CO2 partial pressures in the flue gas led to reduced energy requirements for capture and there may be room for improvement since absorber operating temperatures were also increased which may reduce the efficiency of the absorption process. Acknowledgements This work is partly funded by RWE npower and its support is greatly appreciated. References Doukelis A, Vorrias I, Grammelis P, Kakaras E, Whitehouse M, Riley G, Partial O2-fired coal power plant with post-combustion CO2 capture: A retrofitting option for CO2 capture ready plants, Fuel, 2009, 88(12):2428-36. Dugas ER, Pilot plant study of carbon dioxide capture by aqueous monoethanolamine, M.S.E. Thesis, University of Texas at Austin; 2006. Fleche, A, Exploration of a new process for reducing carbon emissions in pulverised coal-fired power plants, MSc Thesis, School of Engineering, Cranfield University, UK, 2009. Huang Y, Wang M, Stephenson P, Rezvani S, McIlveen-Wright D, Minchener A, Hewitt N and Fleche A, Hybrid coal-fired power plants with CO2 capture: A technical and economic evaluation based on computational simulations, Fuel, to be submitted, 2010. Kohl, AL and Nielsen, RB, Gas purification, 5th ed, Gulf Professional Publishing, Houston, TX, 1997. Lawal A, Wang M, Stephenson P, Koumpouras G and Yeung H, Dynamic Modelling and Analysis of PostCombustion CO2 Chemical Absorption Process for Coal-fired Power Plants, Fuel, 2010, 89, (10): 2791–2801. Lawal A, Wang M, Stephenson P and Yeung H, Dynamic modelling of CO2 absorption for post combustion capture in coal-fired power plants, Fuel, 2009a, 88, (12): 2455-62.
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Lawal A, Wang, M, Stephenson P and Yeung H, Dynamic modeling and simulation of CO2 chemical absorption process for coal-fired power plants, Computer Aided Chemical Engineering, 2009b, Volume 27, p1725-1730. Wall T, Liu Y, Spero C, Elliott L, Khare S, Rathnam R, Zeenathal F, Moghtaderi B, Buhre B, Sheng C, Gupta R, Yamada T, Makino K and Yu J, An overview on oxyfuel coal combustion—State of the art research and technology development, Chemical Engineering Research and Design, 2009, 87, (8): 1003-16.
Energy Procedia www.elsevier.com/locate/procedia
Energy Procedia 00 (2010) 000–000 www.elsevier.com/locate/XXX
GHGT-10
Investigating the dynamic response of CO2 chemical absorption process in enhanced-O2 coal power plant with post-combustion CO2 capture Adekola Lawala, Meihong Wanga,1*, Peter Stephensonb a
Process Systems Engineering Group, School of Engineering, Cranfield University, Bedfordshire, MK43 0AL, UK b RWE npower, Windmill Park, Swindon, SN5 6PB, UK Elsevier use only: Received date here; revised date here; accepted date here
Abstract
Studies have been carried out to show that there could be benefits in employing a hybrid of the post combustion capture and oxyfuel processes. The former is suited for retrofit purposes but involves an energy intensive solvent regeneration process. The oxyfuel process would result in high partial pressures of CO2 in the flue gas making separation easier. However, the Air Separation Unit is also energy intensive and significant modifications would have to be made on the power generation process. An enhanced-O2 coal power plant with post combustion CO2 capture would produce flue gas with reduced mass flow and higher CO2 partial pressures. The dynamic response of the downstream CO2 capture plant was studied in this paper. © Elsevier Ltd. All rights c 2010 ⃝ 2011 Published by Elsevier Ltd.reserved Keywords: CO2 Capture; Post-combustion; Chemical absorption; Dynamic modelling; Coal-fired power plant
1. Introduction Post-combustion capture by chemical absorption using monoethanolamine (MEA) solvent is well suited for treating flue gas streams with low CO2 partial pressures typical of coal-fired power plants. The drawback of this process is the high energy requirement for solvent regeneration. However, it requires minimal modifications to the combustion process and is thus well suited for retrofit options. The oxyfuel process produces a flue gas stream that has a high CO2 partial pressure which makes CO2 separation considerably easier. However, the Air Separation Unit (ASU) would require large quantities of energy to generate the amounts of oxygen needed for the conventional oxyfuel process. In addition, significant modifications to the boiler are required when firing pulverized fuel in a concentrated oxygen stream instead of air. Doukelis et al. (2009) show that there could be benefits in a combination of these two types of CO2 capture technologies, resulting in a partial oxyfuel mode in the furnace and the post-combustion solvent scrubbing. They suggested that this option may be particularly beneficial when retrofitting existing power
* Corresponding author. Tel.: +44-1234-754655; fax: +44-1234-754685. E-mail address: [email protected].
doi:10.1016/j.egypro.2011.01.152
1036
A. Lawal et al. / Energy Procedia 4 (2011) 1035–1042 Lawal et al./ Energy Procedia 00 (2010) 000–000
2
plants. This study investigates the operation of the chemical absorption process downstream an enhanced-O2 coal power plant using dynamic modelling and simulation. 2. Operation of an enhanced-O2 coal power plant and CO2 chemical absorption plant The schematic of the enhanced-O2 coal power plant with post-combustion CO2 capture is shown in Figure 1. It is proposed that coal is combusted in an oxygen-enriched environment to increase the CO2 partial pressure in the flue gas to an optimal level (Doukelis et al, 2009). Oxygen is produced in the ASU typically up to 95vol% purity (Wall et al, 2009). This stream is mixed with secondary air prior to combustion. It is not advisable to increase the O2 partial pressure of the primary air since the stream is mixed with the pulverized fuel and increased O2 concentrations could result in explosions. To keep temperatures down to acceptable levels, flue gas is recycled (and mixed with the primary and secondary air stream) as shown in Figure 1. This also results in an increase in the CO2 partial pressure in the flue gas.
NITROGEN
ASU
OXYGEN
SECONDARY AIR
FLUE GAS RECYCLE FLUE GAS FROM FURNACE
REMOVAL OF NOX AND SOX AND FLUE GAS COOLING
BOILER
AIR
FUEL AMINE CO2 CAPTURE PLANT
MILLS
TREATED FLUE GAS
PRIMARY AIR CO2 PRODUCT
Figure 1 Schematic of an enhanced-O2 coal power plant with post-combustion CO2 capture (adapted from Doukelis et al, 2009) The ratio of the flue gas recycle flow to the flow of flue gas from furnace is referred to here as the recirculation fraction. The estimated compositional and flue gas flow changes observed with oxygen enrichment is shown in Figure 2 for a 600MWe supercritical power plant. In this case, the O2 concentrations in the primary and secondary air range from 21 vol% to 50 vol%. Though the oxygen stream is mixed with the secondary air, the percentage of oxygen discussed is relative to the total of the primary air and secondary air flows to the furnace of the boiler. By maintaining the primary air stream as air and keeping the primary air/fuel ratio, there is an upper limit of 50-60% in the oxygen enrichment possible. The methodology for calculating the flue gas flowrate and CO2 concentration in flue gas from the enhanced-O2 coal plant is presented in Fleche (2009) and Huang et al. (2010). The estimates of the composition of the flue gas were based on the assumption that the fuel specifications and fuel burn rates are kept constant and there is no leakage along the path to the capture plant. The mass flow of CO2 in the flue gas is constant (based on the assumption of
A. Lawal et al. / Energy Procedia 4 (2011) 1035–1042
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Lawal et al./ Energy Procedia 00 (2010) 000–000
3
constant fuel burn rates) while the flue gas total mass flow reduces with the recirculation rate. A steady increase in the CO2 volume fraction in the flue gas is also observed.
CO2 volume fraction
Figure 2 Changes in flue gas mass flow, required recirculation rates and CO2 composition in flue gas with oxygen enrichment
3. CO2 capture model development Chemical absorption is a reactive absorption process. This phenomenon involves the combination of mass transfer and chemical reaction of CO2 with a chemical solvent. Both processes are dependent on the concentration/partial pressure of CO2 in the flue gas. Thus changes in this composition would significantly affect the performance of the process (even with the same quantity of CO2 for capture). MEA solvent could be used to chemically absorb CO2 in the flue gas from the power plant in an absorber and the solvent solution is regenerated in a regenerator column using steam from the power generation process (Dugas, 2006). The gPROMS advanced process modelling environment has been used to develop the required dynamic models. The absorber and regenerator columns were modelled based on the Gas-Liquid Contactor model from Process Systems Enterprise’s Advanced Model Library. Mass transfer rates were modelled based on the two-film theory using the Maxwell-Stefan formulation while the reactions were assumed to attain equilibrium. In developing this dynamic model, the following were assumed: 1 Linear pressure drop along the column 2 Phase equilibrium exists at interface between liquid and vapour films 3 There is negligible solvent degradation 4 There is negligible heat loss in the absorber column 5 There is no water wash section in the absorber The model topology of the process in gPROMS is shown in Figure 3.
1038 4
A. Lawal et al. / Energy Procedia 4 (2011) 1035–1042 Lawal et al./ Energy Procedia 00 (2010) 000–000
Figure 3 Model topology in gPROMS Five main control schemes are used in the process. PI controllers are used for temperature control of the regenerator column by manipulating the condenser and reboiler heat duties. The reboiler level was controlled using a P controller by manipulating the reboiler bottoms flow. This is the liquid lean MEA solvent flow from the reboiler to the cross heat exchanger. Water balance is achieved by controlling the water mass fraction in the lean solvent with the water makeup flow rate used as manipulated variable. Finally a capture level controller measures the captured CO2 and controls it by manipulating the lean solvent flow to the absorber (Lawal et al, 2010). The cross heat exchanger was sized to yield the reported regenerator feed temperature and a temperature approach of over 15°C. The pressure of the partial condenser is also assigned to maintain the regenerator operating pressure.
4. CO2 capture model validation The steady-state validation of the chemical absorption plant model was carried out using data from the one of the cases of the Separations Research Program at the University of Texas at Austin (Dugas, 2006). The absorber and regenerator columns of the pilot plant are both packed columns with diameters of 0.427m and total packing height of 6.1m. It is shown that the models give good predictions of the shape of the temperature profiles for both absorber and regenerator (referred to as the rate-based stand-alone model) (Lawal et al, 2009a). Further validation studies have been carried out for the amine plant set-up (where the absorber and regenerator columns have been linked with recycle referred to as the rate-based integrated model) (Lawal et al, 2009b; Lawal et al, 2010). Validation results are shown for the absorber and regenerator in Figure 4.
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5
Case 32 Regenerator Temperature Profile
Case 32 Absorber Temperature Profile
400
345 340
Pilot Plant Measurements
390 335
Pilot plant Measurements
325
Rate-based Integrated model
320
Rate-based Standalone model
315
Rate-Based Integrated Model Rate-Based Stand-alone Model
380
Temperature (K)
Temperature (K)
330
370 360
310
350 305
340
300 -2
0
2
4
6
8
10
Height from bottom of packing (m)
-2
0
2
4
6
8
10
Height from the bottom of packing (m)
(a) (b) Figure 4 (a) Absorber and (b) Regenerator temperature profile of columns for Case 32 The steady state predictions of the integrated model were found to be slightly better than the standalone models. In the latter, estimates of the input to the column had to be made and errors in such guesses would affect overall results. This suggests that the model predicts the interaction between the component parts of the plant (mainly the two columns) fairly well. It should be noted that the pilot plant in the study used to validate these results did not have a cross heat exchanger but used a combination of a heater and cooler (Lawal et al, 2010). 5. Dynamic analysis of ASU plant start-up The enrichment of oxygen content in the primary and secondary air supplied to the furnace from atmospheric concentrations of 21% by volume to about 50% by volume would result in changes in the flue gas composition as discussed in Section 2. Similar compositional changes would occur despite the scale employed. Therefore, the validated model for CO2 capture at pilot plant scale could be used to carry out the dynamic studies with the main difference being the absolute flow rates involved. The CO2 mass flow to the absorber was fairly constant while the total mass flow rate of the flue gas was correspondingly reduced (Figure 5). Water vapour content in the flue gas was assumed to remain constant at 1.5wt%. Steady state conditions were maintained for two hours then a slow ASU ramp rate of 1% increase per minute was assumed. Conditions were maintained for about 10 hours. In the first case (Case 1), solvent circulation rates remained unchanged and in the second (Case 2), the rates were adjusted by a controller to maintain CO2 capture levels at 96.7%.
CO2 mass fraction N2 mass fraction Flue gas mass flow
Figure 5 Change in flue gas composition and mass flow rate with ASU start-up
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Figure 6 Effects of increasing O2 enrichment in furnace primary and secondary air on capture process Figure 6 shows the effects of oxygen enrichment on the chemical absorption process without control of capture level or Case 1 (a-c) and the corresponding results with control or Case 2 (d-f). With oxygen enrichment, CO2 partial pressures in the flue gas are significantly increased, thus increasing driving forces for absorption thus significantly increasing capture levels (Figure 6a). The observed dip in capture level is probably due to increased absorber column temperature. This drop would not be observed with a steady state simulation. Figure 6c shows the temperature profile variations with time. With O2 enrichment in the primary and secondary air, the partial pressure of CO2 in the flue gas increases which causes more CO2 to react with MEA releasing more heat of reaction. In addition, there is less quantity of flue gas to exchange heat with, so a sharp rise in temperature occurs which would reduce CO2 solubility in the solvent and thus reduce absorption levels. As the capture levels begin to rise and approach 100%, most of the absorption takes place close to the bottom of the packing and the temperature of the solvent dominates in the column temperature profile. This effect is the case especially since it appears that without control, excessive solvent is circulated for capture. Since more CO2 reacts with MEA, the rich solvent loading increases and the heat requirement for capture reduces (Figure 6b). The heat requirement for capture before and after the oxygen enrichment was relatively high (>3.9MJ/kg CO2) because of the relatively high level of capture that is attained (96.7% as compared with the conventional 90%). As capture level targets increase (whilst all other factors are constant), the heat efficiency of the capture process inadvertently drops. However, without capture level control,
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Lawal et al./ Energy Procedia 00 (2010) 000–000
7
excessive solvent is circulated, the capture efficiency tends to 100% and the heat requirement for capture begins to rise again owing to the extra heat needed to heat up the excess solvent. With the capture level controller active (Figure 6d), such excesses are avoided and the heat requirement for absorption remains low – about 10% lower compared to the previous steady state (Figure 6e). The temperature in the column generally increases with CO2 concentration and remains relatively high. This is because, as explained earlier, more heat of reaction is released and there is less quantity of gas to exchange heat with. The temperature bulge is roughly in the same position but the temperature profile is flatter than before the enrichment commenced implying higher temperatures in more parts of the column. The performance of the system could possibly be improved if absorber temperatures are minimized. This could be achieved by employing a split-flow configuration where lean MEA solvent is supplied to the top and middle of the absorber column (Kohl and Nielson, 1997).
6. Conclusions
The dynamic response of the CO2 capture plant with enrichment of oxygen content in the primary and secondary air supplied to the furnace from atmospheric concentrations to about 50% by volume was studied. The resulting flue gas compositions with various degrees of O2 enrichment have been calculated. Using a rate-based dynamic model of the chemical absorption process, two cases were studied – x CO2 capture performance with O2 enrichment and a constant solvent circulation rate x CO2 capture performance with O2 enrichment and a controlled circulation rate to maintain a constant capture level. It was shown that higher CO2 partial pressures in the flue gas led to reduced energy requirements for capture and there may be room for improvement since absorber operating temperatures were also increased which may reduce the efficiency of the absorption process. Acknowledgements This work is partly funded by RWE npower and its support is greatly appreciated. References Doukelis A, Vorrias I, Grammelis P, Kakaras E, Whitehouse M, Riley G, Partial O2-fired coal power plant with post-combustion CO2 capture: A retrofitting option for CO2 capture ready plants, Fuel, 2009, 88(12):2428-36. Dugas ER, Pilot plant study of carbon dioxide capture by aqueous monoethanolamine, M.S.E. Thesis, University of Texas at Austin; 2006. Fleche, A, Exploration of a new process for reducing carbon emissions in pulverised coal-fired power plants, MSc Thesis, School of Engineering, Cranfield University, UK, 2009. Huang Y, Wang M, Stephenson P, Rezvani S, McIlveen-Wright D, Minchener A, Hewitt N and Fleche A, Hybrid coal-fired power plants with CO2 capture: A technical and economic evaluation based on computational simulations, Fuel, to be submitted, 2010. Kohl, AL and Nielsen, RB, Gas purification, 5th ed, Gulf Professional Publishing, Houston, TX, 1997. Lawal A, Wang M, Stephenson P, Koumpouras G and Yeung H, Dynamic Modelling and Analysis of PostCombustion CO2 Chemical Absorption Process for Coal-fired Power Plants, Fuel, 2010, 89, (10): 2791–2801. Lawal A, Wang M, Stephenson P and Yeung H, Dynamic modelling of CO2 absorption for post combustion capture in coal-fired power plants, Fuel, 2009a, 88, (12): 2455-62.
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A. Lawal et al. / Energy Procedia 4 (2011) 1035–1042 Lawal et al./ Energy Procedia 00 (2010) 000–000
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