Optimised integration of post-combustion CO2 capture process in greenfield power plants

Energy 35 (2010) 4030e4041

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Optimised integration of post-combustion CO2 capture process in greenfield power plants I. Pfaff*, J. Oexmann, A. Kather Institute of Energy Systems, Hamburg University of Technology, Denickestr. 15, D-21073 Hamburg, Germany

a r t i c l e i n f o

a b s t r a c t

Article history: Received 15 September 2009 Received in revised form 2 June 2010 Accepted 5 June 2010

Newly built (greenfield) power plant offer the advantage of optimised integration measures to reduce the efficiency penalty associated with the application of a post-combustion CO2 capture process by wet chemical absorption. Especially, the integration of waste heat from the desorber overhead condenser of the CO2 capture unit (CCU) and from the CO2 compressor into the water-steam-cycle of the power plant offers optimisation potential. In this work, the adaptation of pressure levels in the water-steam-cycle regarding the steam requirements of the CCU is evaluated. Particular focus is put on waste heat integration by condensate pre-heating and combustion air pre-heating for minimisation of the overall net efficiency loss. The efficiency potential of the available options as well as the limits of integration, especially with respect to a power plant in commercial operation, are discussed. EBSILONÒ Professional is used to develop a model of the overall process including power plant, CO2 compressor and CCU. The power plant represents a state-of-the-art hard-coal-fired power plant with 600 MW power output (gross). The CCU is modelled as a black box, where the interface quantities of the black box are determined by a detailed model of the capture process in ASPEN PlusÒ using monoethanolamine (MEA) as solvent. Ó 2010 Elsevier Ltd. All rights reserved.

Keywords: Waste heat integration Water-steam-cycle optimisation Wet chemical absorption MEA Monoethanolamine

1. Introduction Besides increasing the efficiency, the application of a process for CO2 capture and subsequent geological storage (CCS) is another possibility to significantly reduce the greenhouse gas emissions of coal-fired power plants. In a post-combustion CO2 capture process the CO2 is separated from the flue gas of a power plant. The flue gas of typical hard-coal-fired power plants is close to atmospheric pressure conditions and has a CO2 content in the range of 12e15 vol.% (wet). There is a large number of concepts for the postcombustion capture of CO2 from coal-derived flue gases, but it is agreed that under these boundary conditions the implementation of an absorptionedesorption process using a wet chemical solvent is the most developed and best suited process for deployment in the near- to middle-term [1,2]. Such processes, however, show large heat requirements for the regeneration of the solvent and additional auxiliary power for pumps, blowers as well as for the final compression of the separated

* Corresponding author. Tel.: þ49 40 42878 4544; fax: þ49 40 42878 2841. E-mail address: [email protected] (I. Pfaff). 0360-5442/$ e see front matter Ó 2010 Elsevier Ltd. All rights reserved. doi:10.1016/j.energy.2010.06.004

CO2. These energy demands lead to a decrease in the net efficiency of the overall process of approximately 9e13%-pts. The aim of this study is to evaluate the potential to reduce the net efficiency decrease by an optimal integration of the CO2 capture process into a greenfield, i. e. newly built, power plant. An optimal integration comprises both the optimal supply of heat, cooling and mechanical or electrical duties for capture plant and CO2 compressor as well as the re-integration of waste heat from the capture and the compression processes into the power plant process. To compare the power plant with CO2 capture on a fair basis to the reference power plant which is typically optimised for operation without CO2 capture, one must also optimise the overall process with CO2 capture to fully exploit the potential of integration. This optimisation includes the CO2 capture unit, the CO2 compressor and the power plant. There exist various studies on the integration of post-combustion CO2 capture processes in gas-fired combined cycles [3e5]. Due to the significant differences in the boundary conditions of such power plants (e. g. different steam power process configuration, lower CO2 partial pressure in flue gas) the transfer of the results of those studies onto coal-fired steam power plants is limited. The integration of CO2 absorption processes into coal-fired steam

I. Pfaff et al. / Energy 35 (2010) 4030e4041 Table 1 Key parameters of the reference power plant. Gross power output Net power output Gross efficiency Net efficiency Live steam pressure Live steam temperature Reheat pressure Reheat temperature Boiler feed water temperature Condenser pressure LP turbine inlet pressure Feed water tank pressure Cooling water temperature Cooling water temperature gain Ambient air temperature

Table 2 Flue gas composition downstream FGD. MWel MWel % (LHV) % (LHV) bar  C bar  C  C mbar bar bar  C K  C

600.0 556.6 49.3 45.64 285 600 60 620 303.4 45 5.5 13.2 18.0 10.0 15.0

power plants is subject of [6e9]. Most of these studies, however, do not make use of the possibility to fully adapt the process to an operation with CO2 capture due to one of two reasons: Either a retrofit of an existing power plant is considered, thus the watersteam-cycle can only be adapted within narrow limits. Or simulation tools which are not specifically designed for the representation of complex interrelations of power plant processes are used. Lucquiaud and Gibbins also focus on the retrofit of fossil-fired power plants with post-combustion capture processes [10]. One alternative in this study is the replacement of the old plant with a greenfield power plant with CO2 capture. The optimisation of the water-steam-cycle to minimise the overall energy penalty is, however, not taken into consideration. As there is very little publicly available literature on the integration of a post-combustion CO2 capture process in a greenfield coal-fired steam power plant, this article aims at outlining general concepts for optimised integration with particular focus on watersteam-cycle adaptation and waste heat integration. 2. Methodology When integrating a process for the capture and compression of CO2 into a power plant, the net power output is reduced due to the steam extraction which is needed for the regeneration of the solution and additionally due to the required auxiliary power for pumps and blowers in the capture process as well as the CO2 compressor. As the cooling water demand of the overall process increases, additional power is also needed to drive the cooling water pumps. The CO2 capture process can therefore be characterised by the magnitude of the three interface quantities heat, electricity and cooling. The model of the CO2 capture process is used to determine the values of the interface quantities which are transferred to the overall model that also comprises the power plant and the CO2 compressor to evaluate the impact on the overall process. In this study simulation tools are employed which are widely used in industry and which therefore have proven their applicability to the considered optimisation problem. EBSILONÒ Professional 7.001 is used to model the overall process, i. e. the power plant including the flue gas as well as the water-steam side, the CO2 compressor and the CO2 capture unit (CCU). The latter is modelled as a black box. To provide for the input parameters of the black box model, ASPEN PlusÒ 2006.5 is used to model the CO2 capture plant. To exemplarily demonstrate the impacts of the integration measures on a conventional ultra supercritical (USC) state-of-the-

1

4031

The calculation in this software is to be regarded by default as convergent if the residual error in the energy, pressure and mass balance matrices falls below 0.1 ppm.

CO2 N2 H2O O2 SO2 a

vol.-% vol.-% vol.-% vol.-% ppmv

13.6 70.3 11.9 3.2 8.8a

SO2 concentration with enhanced FGD for CO2 capture.

art power plant, the model of a hard-coal-fired power plant with a gross power output of 600 MWel based on the study2 Reference Power Plant North-Rhine-Westphalia [11] is used. A greenfield power station with CCS is likely to be designed for full load operation with a high targeted CO2 capture rate of, for example, 90%. This assumption can be justified by the high additional investments for applying post-combustion CCS. As the total specific investment costs (V per kW) will be roughly doubled compared to a power plant without CO2 capture, a greenfield power station with CCS will only be built if the capture of CO2 is economically advantageous or regulated by law. Otherwise the newly built power station will be retrofitted with CCS in the future as soon as this option becomes economically feasible. Therefore, this study focuses on the integration task at design point, i.e. full load, conditions with a CO2 capture rate of 90%. Furthermore, steady state conditions are assumed and no discontinuous processes for normal operation are considered like soot blowing or reclaiming of degraded solvent. For all design cases the live steam mass flow is kept constant. Within the scenario described above, it could be economically beneficial to bypass and idle or shut down the CCU at periods with high electricity prices. In this study the effects of this non-capture operation condition on the steam cycle are pointed out for the basic integration considerations (Section 4.4). In the following, the underlying models that are used for this study are described. Afterwards, the considerations regarding the demands for the basic integration and related results are discussed. Finally, measures to minimise the efficiency losses by advanced integration concepts are addressed. 3. Modelling To ensure an adequate representation of the overall process and a sufficient degree of detail within the sub-process models, two commercial simulation tools EBSILONÒ Professional (power plant, CO2 compressor) and ASPEN PlusÒ (CO2 capture unit) are used. The two tools are coupled via a mutual spreadsheet interface (MS Excel). 3.1. Power plant As mentioned above, an ultra supercritical hard-coal-fired power plant with a gross power output 600 MWel is used in this study. The model is based on the study “Reference Power Plant North-Rhine-Westphalia” [11]. A South-African bituminous coal with a lower heating value of 25.1 MJ/kg and related specific CO2 emissions of 339.1 g/kWhth is considered. The main features and parameters of this power plant at full load are given in Table 1. The flue gas composition is given in Table 2. Fig. 1 shows the topology of the chosen reference power plant. To maintain comparability on a fair basis this topology is only modified for integrating the CCU, i.e. no changes that would also

2 Modifications to the study are a reheat spray attemperator mass flow of 1%, a relative pressure drop of the IP/LP turbine crossover of 1% as well as an air ingress rate of 4% of the flue gas mass flow leaving the steam generator.

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8

7

to steam air heater 6 4

3

2

1

5 Fig. 1. Simplified topology of the hard-coal-fired power plant with a gross output of 600 MWel.

increase efficiency of the reference power plant are applied. The same approach is used for the key parameters of the power plant; e.g. the pressure of the turbine condenser is kept constant at 45 mbar. For each of the integration variants as discussed in Sections 4 and 5, the steam bleed pressures of the water-steamcycle are optimised.3 To investigate the part-load characteristics of the water-steam side during non-capture operation, the following estimation principles are taken as a basis: steam path rule (Stodola’s law) and typical characteristic curves for steam turbine efficiencies, outlet losses, heat exchanger behaviour and pressure losses. The simulation tool uses the IAPWS 1997 industrial formulation for the thermodynamic properties of water and steam [12] and the FDBR method for the representation of the flue gas side [13]. The model of the power plant is validated against information from the cited study in particular in terms of steam temperatures and pressures as well as net power output and net efficiency. 3.2. CO2 capture unit Monoethanolamine (MEA) is often regarded as the first chemical solvent to be used in the early large-scale applications of postcombustion CO2 capture in coal-fired power plants. The usage of MEA shows some drawbacks when considered for CO2 capture from coal-derived flue gas: in particular the large amount of heat of app. 3.5e4 GJ per tonne of CO2 needed for the regeneration of the solvent must be mentioned. Some suppliers state that by process optimisation the heat requirement could be reduced to values as low as 3.0 GJ/tCO2 [14]. The chemical reaction scheme for the representation of the chemical absorption of CO2 in aqueous solutions of H2O-MEA-CO2 is taken from Hilliard [15]. Hilliard used vast experimental data in the form of water vapour depression, mean ionic activity coefficient, heat capacity, CO2-solubility, acid dissociation constant and proton nuclear magnetic resonance (NMR) speciation to regress the

3 This classical optimisation problem is n-dimensional, where n is the number of steam bleed pressures to be optimised and that are not given as a boundary condition. To perform this optimisation, a nested one-dimensional iterative solution method is chosen.

parameters of the Electrolyte Non-random Two Liquid (eNRTL) activity coefficient model that satisfactorily correlates the experimental data of the mixed solvent electrolyte system over a wide range of temperature, mixed solvent concentration and CO2 loading. The simulation tool with the regressed parameter set is used to build a complete flow sheet for the CO2 capture process as shown in Fig. 2. The flue gas coming from the FGD is pre-cooled in a direct contact cooler and enters the absorber at a temperature of 40  C. Due to the low temperature at the bottom of the absorber, high rich loadings of 0.51 mol CO2/mol MEA are achieved. The cooled lean solution enters the top of the absorber at 40  C. The CO2 is absorbed by the solution as it flows downward. In the washing section vaporised or entrained solvent is recovered from the CO2-lean treated gas and a neutral water balance is kept by controlling the degree of cooling of the circulated wash water. A reflux of 3% from the washing section to the absorber is assumed. To avoid the buildup of solvent concentration or particles in the water wash section, make-up water is provided by recycling the condensate from the desorber overhead condenser back to the washing section. The CO2-rich solution exits the bottom of the absorber. In the rich-lean heat exchanger (RLHX), sensible heat is transferred from the lean to the rich solution. The pre-heated rich solution is pumped to the desorber. CO2 is desorbed by providing heat in the reboiler at the bottom of the column. The desorber overhead product (mostly CO2 and H2O) flows to a condenser, where the gas is cooled and the largest part of the water is condensed. The remaining CO2-rich stream is then passed to the compressor. The boundary conditions of the CO2 capture process are given in Table 3. The vaporisation efficiencies4 of the CO2 in the absorber are assumed to increase linearly from 1.4 in the top to 5.0 at the bottom of the column to account for strong decrease in temperature. The latter is associated with an increasing departure from the equilibrium conditions due to the decreasing reaction kinetics. Because of the exothermic nature of the absorption reaction, the vapour temperature in the upper part of the absorption column is app.

4 In contrast to Murphree efficiencies, low vaporisation efficiencies close to 1 correspond to an operation close to equilibrium, where higher values describe the lift of the operation line from the equilibrium line in a McCabeeThielen diagram.

I. Pfaff et al. / Energy 35 (2010) 4030e4041

flue gas from FGD

to atmosphere

4033

make-up water

intercooled compression

washing section

overhead condenser

to CO 2 storage

solvent cooler to make-up water system rich-lean HX

absorber

blower

desorber

filter

reboiler flue gas cooler

steam/condensate from/to power plant

solvent pump (CO2-lean)

solvent pump (CO2-rich)

reclaimer to water conditioning or FGD

disposal

Fig. 2. Simplified flow sheet of CO2 capture process by wet chemical absorption.

70  C. The cooling of the flue gas upstream the absorber ensures high equilibrium loadings at the rich end of the absorber. The temperature decrease to values as low as 45  C leads to a reduced absorption rate in the lower part of the column. There is a discrete minimum in the specific reboiler heat duty for a certain solution flow rate, i.e. liquid to gas (L/G) ratio in the absorber, when considering a constant CO2 capture rate [16]. The L/G must therefore be optimised whenever process parameters such as the CO2 capture rate, the desorber pressure or the logarithmic mean temperature difference (LMTD) in the RLHX are varied. It shows that for a CO2 capture rate of 90% the specific reboiler duty reaches a minimum at an L/G of 2.8 kg/kg. This corresponds to a lean loading of 0.17 mol CO2/mol MEA. Table 4 shows the results for the three interface quantities of the simulations of the CO2 capture process at the optimal L/G and the corresponding lean and rich loading. A specific reboiler duty of 3.3 GJ/t CO2 is quite an optimistic result for the shown process configuration but this value agrees well with results from literature and by manufactures for optimised MEA-based capture processes [6,7,14].

Table 3 Boundary conditions of CO2 capture plant model. MEA concentration in solution Absorber equilibrium stages Absorber CO2 vaporisation efficiencies (1st/last stage) Desorber equilibrium stages Desorber pressure (1st stage) Rich-lean HX temperature difference Absorber solvent inlet temperature Reboiler temperature difference Flue gas cooler pressure drop Absorber pressure drop Desorber pressure drop Washer/flue gas cooler/solvent pump efficiency Blower isentropic efficiency Blower mechanical efficiency

% e e e bar K  C K mbar mbar mbar % % %

30 20 1.4/5.0 20 2.1 10 40 10 10 80 50 80 75 95

3.3. CO2 compressor To transport the separated CO2 to the injection well, a pipeline pressure of 110 bar is assumed to be sufficient. As the CO2 leaving the desorber at 40  C and 2.1 bar is water saturated, the compressor has to cope with moist CO2. In this study an integrally-geared (radial) compressor with eight intercooled stages followed by an aftercooler is considered (cf. Fig. 3). This reflects a quite moderate layout as manufacturers indicate that seven or even six stages could be sufficient [17]. The CO2 compressor is also modelled within EBSILONÒ Professional 7.00, where the calculation method for the real gas behaviour is chosen to take in consideration the non-ideal behaviour of the CO2 during compression and cooling [18]. Table 5 shows the assumed polytropic efficiencies and the pressure ratios of each stage. As the first stage is equipped with adjustable inlet guide vanes the efficiency is slightly reduced. The decrease of the pressure ratio5 with increasing stage number is in consideration of the rotor dynamics of the integrally-geared compressors [19]. The pressure drop of each intercooler and the aftercooler is set to 50 mbar. After each intercooler of the first four stages a water knock-off to dispose the condensing water is modelled. Before the CO2 enters the 5th stage an adsorptive drying stage is provided (pressure range of about 17 bar). This is necessary to account for the assumed strict requirements of contained water within the CO2 for pipeline transport. Therefore, an additional pressure drop of 100 mbar for the application of adsorption beds is assumed after the 4th stage. As the alternatives of the regeneration of the drying process are not further investigated, a possible increase in heat or power demand is neglected for this study.

5 The first stage pressure ratio is 5% higher than the averaged pressure ratio across the compressor. Correspondingly the last stage is devaluated with a factor of 1/1.05. All other stages are calculated analogously with linearly decreasing factors so that the factorial of all factors is one.

I. Pfaff et al. / Energy 35 (2010) 4030e4041

assumed. In Section 4.3 the efficiency potential of a lower temperature difference is evaluated. With a desorber temperature of 124.1  C and an assumed temperature difference of 10 K for the heat exchanger, steam at a pressure of 3.05 bar is required. As MEA tends to excessively degrade at temperatures above 125  C [20], the reboiler may not be impinged directly with the superheated steam: attemperation of the supplied steam is necessary. The most effective solution is the attemperation by spray injection of reboiler condensate, which is assumed for the base case within this study. An optimised solution is the re-integration of the sensible heat of superheat into the water-steam-cycle to minimise exergy losses (cf. Section 4.2). Both the location of steam extraction as well as the location to return the reboiler condensate have to be considered carefully concerning the aspects of optimal efficiency, part-load capability as well as flexibility of the steam power plant. For an optimal efficiency the reboiler condensate has to be returned at that point into the preheat train where the feed water shows a similar temperature. In this context, attention must be turned to the degree of sub-cooling of the condensate at the feed water tank (FWT) inlet. Besides storing feed water for process control reasons and pre-heating condensate as a part of the pre-heat train, the FWT also provides for the deaeration of the feed water to avoid corrosion issues in the water-steam-cycle. To guarantee a proper deaeration, the sub-cooling of the feed water at the FWT inlet must not fall below a value of 5e20 K [21]. When considering the integration of waste heat into the watersteam-cycle by pre-heating of condensate it is typically reintroduced somewhere upstream the FWT. Depending on the temperature level of the heat source and therefore on the temperature of the condensate, the optimal introduction point can lie directly in front of the FWT downstream pre-heater 4 (cf. No. 5 in Fig. 1). Therefore, within this study it is assumed that the temperature difference between the condensate and the FWT must not decrease below 20 K.

Table 4 Results of L/G optimisation for 90% capture rate. Optimal L/G Lean loading Rich loading Reboiler temperature Spec. heat duty Heat duty Spec. cooling duty Cooling duty Spec. power duty Power duty

kg/kg mol CO2/mol MEA mol CO2/mol MEA  C GJth/t CO2 MWth GJth/t CO2 MWth MJel/t CO2 MWel

2.78 0.17 0.51 124.1 3.32 350 4.14 437 80.8 8.53

The results of the model in terms of compression work and generated heat in the intercoolers agree well with information from manufacturers [17,19]. 4. Basic integration The term basic integration denotes those measures which are necessary to meet the minimal interface requirements of the CO2 capture process and the CO2 compressor. As mentioned above these are 1. steam to regenerate the rich solvent in sufficient quantity as well as quality, 2. cooling water to discharge waste heat due to losses, and 3. power to drive the CO2 compressor, pumps and fans. In this section various options to meet the interface requirements are discussed. The re-integration of waste heat into the power plant process to minimise the energy penalty is denoted by the optimised integration and is considered in Section 5. Besides providing for the heat, cooling and power demands, the conventional flue gas treatment has to be enhanced due to the chemical sensibility of MEA regarding pollutants in the flue gas, in particular SOx. The improved FGD performance is accounted for by an additional pressure drop of 5 mbar and an increase in power demand for the recirculation pumps of 25% when the CCU is in operation. The required steam quality is determined by the temperature of the reboiler. To provide for the heat at a constant temperature level, the steam is condensed at the associated saturation pressure. The heat required must be available at a temperature that corresponds to the temperature of the reboiler plus a reasonable temperature difference. The latter is typically a subject of economic optimisation: The larger the temperature difference in the heat exchanger, the smaller the heat exchange area and thus the lower the investment cost. A larger temperature difference does, however, require the supply of heat at a higher temperature, i.e. higher pressure, and thus leads to larger losses in the power plant. In this study a temperature difference of 10 K between the condensing steam from the power plant and the boiling solution in the reboiler is

1. Stage

There are a number of imaginable options to provide for the heat at the necessary temperature level for the regeneration of the solution: 1. The further cooling of the flue gas downstream the air preheater (115  C) is not appropriate as the temperature level is not sufficient. Additionally the sensible heat would only provide for about 1/10 of the heat required by the capture process. 2. The use of an auxiliary boiler or an auxiliary gas turbine with an HRSG was suggested by Romeo et al. but it was shown that these options lead to large efficiency penalties [8]. Additionally, the partial substitution of coal by natural gas prevents a direct comparison as natural gas-fired power plants inherently show lower specific CO2 emissions.

2. Stage

Water-knock off

After 4. Stage 3.& 4. Stage

Intercooler

Adjustable inlet guide vanes Compressor stage

4.1. Sources of reboiler heat

Adsorptive drying unit

Fig. 3. Intercooled CO2 compressor with eight stages.

5. Stage

Last Stage 6.& 7. Stage

4034

Aftercooler

I. Pfaff et al. / Energy 35 (2010) 4030e4041

4035

Table 5 Stage pressure ratio and polytropic efficiencies of the CO2 compressor. Stage No. Polytropic efficiency Stage pressure ratio

% e

1

2

3

4

5

6

7

8

87.0 1.730

88.0 1.684

87.5 1.671

87.0 1.653

86.5 1.621

86.0 1.610

85.5 1.589

85.0 1.569

3. The most reasonable option is the use of the latent heat of condensing low-pressure steam from the water-steam-cycle of the power plant. Large steam quantities have to be provided as about one fourth of the fuel heat input is needed in the desorber to separate 90% of the CO2. There are many possible extraction points in the water-steamcycle of the power plant to provide steam at the necessary parameters. When assuming 8% pressure losses in the branch pipe from the power plant to the capture process, the minimal required steam pressure at the interface of the power plant is 3.32 bar for this study. The higher the pressure of the extracted steam lies above the minimal required pressure level, the higher are the efficiency penalties. An operation of the desorber at a lower pressure could possibly be beneficial to the performance of the overall process. The lower steam quality requirements at lower operating pressures and therefore a lower temperature in the reboiler could overcompensate the increased absolute amount of heat for solvent regeneration. This increased steam demand occurs when considering a capture process with a high heat of absorption solvent such as MEA at a lower desorber pressure [22]. However, as this work focuses on the optimised integration of the CO2 capture unit, all process parameters of the CCU such as the desorber pressure are held constant. If live steam or reheat steam is considered for use in the capture process, an additional steam turbine is strongly recommended to reduce the energy penalty. Such a back-pressure turbine could not only be used to meet the reboiler steam requirements, but could also drive the CO2 compressor. This measure, however, does not only lead to additional investment costs but also shows lower isentropic efficiencies than the HP and IP turbines of the reference power plant as it is much smaller in size. Also, it introduces an additional degree of integration between the water-steam-cycle of the power plant and the CO2 compressor and therefore impairs operability and flexibility of the overall process. Furthermore, the thermodynamic cycle efficiency is significantly lowered if a nontapped steam turbine is applied or a non-reheat process is realised for that portion of steam. Additionally, it should be pointed out that whenever steam extraction involving live steam or cold reheat steam is considered, the significant changes of mass flows within the reheat heating surfaces must be taken into account for steam generator design if the operation without CO2 capture should still be possible.

a

b

to CCU

In conclusion, the choice of the optimal sources for steam supply is not only affected by efficiency considerations but also by operability and part-load capability. The best extraction point to provide for the large steam quantities at the required pressure level considering low energy penalty, low investment costs, high flexibility and good part-load capability is therefore the crossover pipe connecting the IP and LP steam turbines. For maximum design point efficiency the water-steam-cycle has to be designed for the pressure required by the capture process. In this case the IP/LP crossover pipe pressure should therefore be 3.32 bar. To be able to keep this pressure also during part-load operation, a controlled steam extraction must be provided (cf. Fig. 4a). Due to throttling of the steam entering the LP turbine during part-load operation, this approach is affiliated with poor part-load performance. An alternative approach (cf. Fig. 4b) is a design providing for an adequate pressure that allows for minimum load conditions without throttling the LP steam and thus showing a better efficiency during part-load operation than solution a. To reach a part-load capability of 40%, a design crossover pipe pressure of around 7.0 bar would be required. This solution has the disadvantage of a lower design point efficiency because at full load the pressure is too high for the capture process and must thus be throttled upstream the CCU. A practice-orientated approach is the combination of both solutions (cf. Fig. 4c) to optimise plant efficiency with respect to the planned operation and is therefore chosen for the following considerations in this study. For the simulations an additional pressure loss for the steam extraction pressure governing valve (cf. Fig. 4a) of 10 mbar is presumed. Fig. 5 shows the effects of varied pressure of the IP/LP crossover. For each case of Fig. 5 the bleed point pressures as well as the reheat pressure are optimised. Reducing the design pressure of the IP/LP crossover by 0.5 bar results in an increase of the design point efficiency of app. 0.2%-pts. This advantage comes with the price of adverse part-load efficiency behaviour as it is discussed above. For all cases the optimal return point for the reboiler condensate is after feed water pre-heater No. 3 (cf. Fig. 1). For the further integration analyses the case with 5.5 bar at LPturbine inlet is chosen as an example to investigate the effects of the advanced integration which is presented in the following. The most important parameters of the corresponding power plant with CO2 capture are shown in Table 6.

c

IP/LP crossover pipe

LP turbine

Fig. 4. Options to maintain the reboiler steam pressure at different loads. a) steam extraction pressure governing valve; b) steam bleed with control valve at reboiler branch pipe; c) combination of a) and b)).

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I. Pfaff et al. / Energy 35 (2010) 4030e4041

Spray attemperator

Reboiler

De-superheater from IP/LP crossover pipe

to condensate pre- heat train

Fig. 6. Optimised de-superheating scheme of reboiler steam.

Fig. 5. Effect of IP/LP crossover pressure on overall process.

For the separation and compression of 90% of the CO2 contained in the flue gas, a net efficiency of 35.01% is calculated for the basic configuration. With respect to the reference case this represents an efficiency decrease of 10.63%-pts. This result lies within the range given in the publically available literature, e.g. Refs. [10,23]. However, there are considerable differences up to the magnitude of greater than 1%-pts. These are originated by the underlying assumptions of process parameters and boundary conditions as well as the chosen approach for the integration of the CCU and CO2 compression. The significant impact of varying assumptions on the net efficiency is addressed by the help of two examples in Section 4.3.

This optimisation measure is the most critical regarding the subcooling of condensate to ensure deaeration in the feed water tank. But all simulations performed in this study showed that this is not be an issue for a greenfield power plants as long as the pressures at the tapping points of the steam turbine are optimised. Additional it can be concluded that the net efficiency increase which can be realised by the de-superheating of reboiler steam with reboiler condensate is the higher, the higher the design pressure in the IP/LP crossover is chosen. This can be attributed to the larger degree of superheating with higher IP/LP pressures at the IP outlet where the reboiler steam is extracted. Therefore, when considering this integration option the disadvantage of a higher IP/ LP pressure in term of net efficiency can be partly compensated by an optimised de-superheating of reboiler steam.

4.2. Optimised de-superheating of reboiler steam

4.3. Impact of boundary conditions

The steam which is extracted from the water-steam-cycle to be used for the regeneration of the solvent in the CO2 capture process shows a temperature of around 240  C (in the base case) and must be de-superheated prior to entering the reboiler to avoid local temperatures above 125  C which cause excessive thermal degradation of the solvent (polymerisation of carbamate ions). A straightforward approach is to de-superheat the steam by recycling part of the condensate, transforming the sensible heat of the steam into latent heat at a temperature level of app. 134  C. The aim of the optimisation of the de-superheating is to make use of this sensible heat thus to reduce the exergy losses. The most reasonable heat sink for the sensible heat (app. 31.7 MWth in the base case) between 240  C and the dew point of the steam at 3.32 bar, i. e. app. 134  C, is the reboiler condensate. Fig. 6 shows the studied set-up with a de-superheating heat exchanger. When considering a minimal lower terminal temperature difference of 20 K, 88.3% of the available sensible heat (28.0 MWth) can be recovered. Heating the condensate to 176  C leads to a moderate efficiency benefit of 0.06%-pts. This can only be achieved by changing the condensate return to a position downstream of feed water heater No. 4 (cf. Fig. 1). When doubling the lower terminal temperature difference, i.e. to 40 K, the efficiency benefit is reduced to 0.05%-pts.

The impact of two important boundary conditions shall be discussed in this section. First the importance of the temperature difference realised in the reboiler is demonstrated by varying this parameter between 3 and 15 K. Afterwards the effect of the allowed increase in cooling water temperature on the overall process efficiency is discussed. In the base case the temperature difference between the condensing low-pressure steam from the water-steam-cycle of the power plant and the boiling aqueous MEA solution was held constant at 10 K, thus a steam pressure of 3.32 bar is needed to provide the heat at the temperature required by the reboiler. In this case the minimal part-load without throttling in the IP/LP crossover is 56.4%.

MWel MWel % (LHV) % (LHV) %-pts. bar bar bar K

Table 7 shows both parameters for various reboiler temperature differences. The reduction of the reboiler temperature difference therefore has either a positive effect on the part-load or the design point efficiency of the power plant: if the crossover pressure is kept Table 7 Effect of reboiler temperature difference on required reboiler steam pressure and minimal part-load without throttling in the base case.

Table 6 Design parameters of the base case power plant with 90% CO2 capture. Gross power output Net power output Gross efficiency Net efficiency Net efficiency decrease due to CCS Reheat pressure IP/LP crossover pressure Feed water tank pressure Subcooling of main feed water at FWT

If the temperature difference in the reboiler is reduced, e.g. by increasing the heat exchanger surface or by improving the heat transfer coefficient, the required steam pressure as well as the minimal part-load without throttling is reduced.

504.8 420.4 42.03 35 10.6 75.0 5.5 15.0 44.4

Reboiler temperature difference in K

Required steam pressure in bar

Minimal part-load without throttling in IP/LP crossover in %

3 5 10a 15

2.96 2.86 3.32 3.83

44.3 48.0 56.4 65.6

a

Base case.

I. Pfaff et al. / Energy 35 (2010) 4030e4041

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water outlet temperature of 43  C) would lead to an increase in net efficiency of 0.23%-pts. This benefit comes along with increasing heat exchanger surfaces in the CO2 capture unit as well as in the intercoolers of the CO2 compressor, as the hot end temperature differences are decreasing. Note that within this study the cooling water temperature gain in the turbine steam condenser is kept constant at 10 K for all cases. Additionally, it is assumed that the cold cooling water temperature stays constant, thus that any influence of the cooling tower is neglected. 4.4. Impact of non-capture operation

Fig. 7. Effect of cooling water temperature increase in CO2 compressor and CO2 capture unit on net efficiency.

constant, the activation of extraction steam throttling can be shifted to lower loads which leads to an increase in part-load efficiency. Alternatively a smaller reboiler temperature difference can be used to decrease the chosen crossover pressure and thus to increase the design point efficiency as investigated Section 4.1. However, in both cases the additional costs for the heat exchanger must be considered. As known from optimisation of conventional power plant, an increase in cooling water outlet temperature would increase the turbine condenser pressure having a negative effect on the watersteam-cycle efficiency on the one hand but reducing power consumption of the cooling water pumps. Therefore, an optimal temperature gain of the cooling water is determined in the optimisation of the cold end of the power plant. When applying a post-combustion CO2 capture process to a power plant, the amount of heat that has to be rejected into the cooling water is considerably increased. In the base case the total heat rejected is increasing by 39.0% with respect to the reference power plant. For a greenfield power plant with CO2 capture, only one third of the overall cooling duty is resulting from the condensation of steam in the main steam condenser of the power plant, since only about half of the steam mass flow remains for expansion in the LP turbine. The remaining two thirds are due to the cooling requirements of the CO2 capture unit and the CO2 compressor. Within both sub-processes, CCU and CO2 compressor, all fluids show temperature slides when cooled. Therefore, there is no need to keep a small cooling water temperature gain if a counter-current flow pattern is realised. A higher temperature gain within these processes would reduce the amount of cooling water thus saving auxiliary power for the pumps and finally increasing overall plant efficiency. Note that the main steam condenser of the power plant should still be designed for a small cooling water temperature gain to ensure optimal steam cycle efficiency. Fig. 7 shows that an increase in the cooling water temperature gain from 10 K in the base case to 25 K (corresponding to a cooling

Table 8 Amount and temperature of available heat in the CO2 capture process.

As mentioned above, a greenfield power plant equipped with a CO2 capture process would be operated at the designed CO2 capture rate whenever possible. Nevertheless, there are conditions in which an operation without CO2 capture can be economically advantageous or necessary, for example during periods of high electricity prices or during a trip in the capture process or the CO2 compressor. Presumed that the steam which is used for solvent regeneration in the capture process can instead be used in the LP turbine, an increase in power output of app. 107 MWel is achieved. In this case, the steam mass flow to the LP turbine increases by 92%. The LP turbine inlet pressure consequently also increases from 5.5 to 11.4 bar. Due to the pressure increase the volumetric steam flow in the LP turbine increases by only 9%, but the volumetric steam flow at the outlet of the IP turbine decreases by 41%. Due to the increased steam flow, the condenser back-pressure rises significantly to 87 mbar with a corresponding negative effect on the thermal efficiency of the water-steam-cycle. The cooling water outlet temperature increases from 28  C to 37.4  C if the cooling water mass flow is kept constant. The sum of the effects mentioned above leads to a net efficiency which is 1.6%-pts. lower than for the reference power plant that is designed for operation without CO2 capture. The increase in pressure as well as in mass flow has a significant effect on the flow regimes as well as on mechanical forces in both IP and LP turbine. If the turbine design could not be changed to stand these high loads, part of the additional steam from the capture unit has to be forwarded to the turbine condenser to preserve the design parameters of the turbine. Another option is to provide for an additional (peak load/standby) turbine involving additional investment costs. A last option for non-capture operation is to reduce the amount of live steam. To limit the LP turbine inlet pressure to 5.5 bar, the live steam flow has to be reduced to 45.5% which would then reduce the power output to 219.5 MWel. To preserve the net power output of 421.2 MWel the steam generator must be operated at a load of 80.6% which would lead to an increase of the IP/LP crossover pressure to 9.4 bar. 5. Optimised integration According to the first law of thermodynamics, all of the heat input to the reboiler minus the energy necessary to separate the CO2 from Table 9 Summary of the variants of the CO2 compressor for heat integration analysis.

Location (cf. Fig. 2)

Upper temperature  C

Lower temperature  C

Available heat MWth

Name

# of coolers

TIC,in  C

TIC,out  C

Pel MWel

Q_ tot MWth

Flue gas cooler Washing section cooler Solvent cooler Overhead condenser

29.8 46.8 49.3 105.7

23.0 24.4 40.0 40.0

79.7 210.0 48.8 98.2

IC8_T40a IC8_T55 IC4_T40 IC2_T40

8 8 4 2

76.7e86.7 85.7e108.4 80.4e133.3 85.4e237.6

40 55 40 40

28.8 30.8 31.6 37.5

53.8 55.7 56.5 62.2

436.7

a

Total

Base case, no waste heat recovery.

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I. Pfaff et al. / Energy 35 (2010) 4030e4041

CO2 compressor SH

CO2 capture unit OHC

SH

APH

BPE SG

HP

IP

LP

G

SH

SH

SH

Cond

HPP1-3 LPP4

FWT

LPP3

LPP2

LPP1

FWP

Fig. 8. Simplified flow sheet of the overall process with CO2 capture showing all investigated options for optimised integration by waste heat recovery.

the solvent must emerge in other locations of the capture process: flue gas cooler, washing section cooler, solvent cooler, overhead condenser, the separated CO2-rich stream or the treated flue gas (cf. Fig. 2). Additional cooling duty arises since the flue gas from the FGD is present at a higher temperature (w50  C) than the outgoing treated flue gas at the absorber head and the CO2-rich gas stream at the desorber head (w40  C). As all three streams are saturated with water, more water would enter the system with the flue gas from the FGD than would leave the system with the treated flue gas and the CO2. Due to the cooling of the flue gas before entering the absorber, in order to facilitate the absorption process, water condenses and is discharged (cf. Fig. 2). To keep a neutral water balance within the CO2 capture process one must therefore further cool down the treated flue gas in the washer at the top of the absorber column (cf. Fig. 2). Table 8 shows the available heat with the corresponding temperature level in the CO2 capture process.

Additional heat is available in the intercoolers of the CO2 compressor, where the CO2 is compressed to a pressure of 110 bar. When the intercooling concept is modified by omitting particular intercoolers, the available temperature level for waste heat recovery is increased at the cost of higher power consumption of the compressor. Four variants are considered to investigate the impact on overall plant efficiency: 1. IC8_T40: Intercooling after each stage to 40  C (base case), no waste heat recovery 2. IC8_T55: Intercooling after each stage to 55  C 3. IC4_T40: Intercooling after stage 2, 4, 6 and 8e40  C 4. IC2_T40: Intercooling after stage 4 and 8e40  C Table 9 shows the available heat and the corresponding temperature levels in the intercoolers of the CO2 compressor as well as the power demand. In all cases the CO2 leaves the compressor with an outlet temperature of 40  C. Intercooling after each stage to 40  C is considered. With a cooling water inlet temperature of 18  C this corresponds to a lower temperature difference of 22 K. Hence, in all following analyses a minimal lower Table 10 Results of heat integration by condensate pre-heating. Var. No.

Source of waste heat

Net efficiencya (%)

Efficiency decreaseb (%-pts.)

Efficiency improvementc (%-pts.)

1 2 3 4

OHC IC8_T55 IC4_T40 IC2_T40

35.32 34.90 35.25 35.32

10.32 10.74 10.39 10.32

þ0.31 0.11 þ0.24 þ0.31

a b

Fig. 9. Heat curve of desorber overhead condenser.

c

based on lower heating value. with respect to the reference power plant. with respect to the base case.

Temperature

I. Pfaff et al. / Energy 35 (2010) 4030e4041

APH Sec. I

APH Sec. II

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Availiable temperature level of flue gas bypass (available heat determined by bypass mass flow)

Feedwater -heater

Configuration without bypass Flu

Air Heater

eG as

Constant flue gas temperature

Combustion Air

(steam/waste heat)

APH Sec. I

APH Sec. II

Transferred Heat

Waste Heat Input

Fig. 10. Heat integration by pre-heating of combustion air.

temperature difference of 22 K is kept to assure a fair comparison and reasonable sizes of the necessary heat exchangers. For the variant IC8_T55 the intercooler outlet temperature of 55  C is chosen to be able to use the entire heat for condensate preheating (available at app. 32  C) accounting for the assumed minimal temperature difference of 22 K. In this variant an additional aftercooler must be applied to ensure the pipeline interface temperature of 40  C (heat duty 9.3 MWth). From Tables 8 and 9 it is clear that there is a lot of heat available (490.5 MWth in total in the base case). However, most of this heat is present at very low temperature levels (<50  C). The problem when considering the integration of this heat into the power plant process is to find adequate heat sinks. The only two available heat sinks at low temperatures are the combustion air which enters the process at a temperature of 15  C, and the condensate in the watersteam-cycle which exits the main turbine condenser at a temperature of 31.0  C in the reference case and which is subsequently heated to 154.0  C in the four low pressure condensate pre-heaters before it enters the feed water tank. Therefore, the two only heat sources which can be reasonably integrated into the power plant process are the desorber overhead condenser and the intercoolers of the modified CO2 compressor. Fig. 8 shows the simplified flow sheet of the overall process including the integrated CO2 capture unit and CO2 compressor. The figure shows various variants for waste heat recovery that are explained in Section 5.1 through 5.3. The heat curves of intercoolers are assumed to be linear between the upper and lower temperature of the hot gas stream as an acceptable simplification. As a partial condensation takes place in the overhead condenser, one must consider the heavily nonlinear heat curve of this component as shown in Fig. 9. For all cases recovering heat from the overhead condenser of the desorber it is ensured that the minimal temperature difference does not fall below a value of 15 K. 5.1. Heat integration by condensate pre-heating The recovery of waste heat by pre-heating condensate is relatively simple, as condensate is a liquid medium at moderate pressures (<20 bar) and can therefore be easily transported from the water-steam-cycle to the waste heat source of the capture plant or the CO2 compressor. In contrast, heat integration by pre-heating of

combustion air as presented below in Section 5.2 requires large additional investments. Table 10 shows the results of heat integration by condensate pre-heating for both OHC and intercooler waste heat usage. In all variants condensate is taken directly downstream the turbine condenser (before feed water heater No. 1 in Fig. 1), is pre-heated and then returned to the water-steam-cycle between the preheaters with matching temperature level (cf. Fig. 8). When the use of waste heat from the CO2 compressor is considered, it shows that fewer intercoolers can increase the net efficiency of the overall process, even though the power consumption of the CO2 compressor is increased. The principle is comparable to the concept of heat pumps. Variant No. 2 shows a slight decrease in efficiency, since the increase in power demand overcompensates the efficiency gain due to the integration of waste heat. In this variant, the upper terminal temperature difference is restricting the amount of heat recovery, as already the entire condensate stream is deployed and thus cannot be increased any further. 5.2. Heat integration by pre-heating of combustion air The combustion air fed to the steam generator is commonly preheated by recovering heat from the hot flue gases between DeNOx and ESP in an air pre-heater (APH). To keep the flue gas temperature at the APH outlet above the acid dew point (>115  C), the combustion air has to be pre-heated prior to entering the APH to at least 34  C by a steam air heater (5.6 MWth). To make use of waste heat from the capture process, condensate is used as a heat transfer medium and is first heated in the OHC and then passed to a heat exchanger which substitutes the steam air heater. Here, the condensate is partially cooled down in the heat exchanger transferring its heat onto the combustion air and is then returned to the water-steam-cycle between pre-heater 2 and 3 (cf. Fig. 8). This way the steam bleed to the steam air heater can be closed and more steam remains in the turbine, leading to an increase in power output as well as to an efficiency gain of app. 0.29%-pts. compared to the base case. This way, 5.6 MWth is recovered, while keeping the flue gas temperature at 115  C. An increase in heat input in the steam air heater would increase the flue gas temperature at the APH outlet without any benefit to the overall efficiency. Therefore, a portion of the flue gas is bypassed along the e now splitted e APH and is used to pre-heat feed water on

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I. Pfaff et al. / Energy 35 (2010) 4030e4041

a higher temperature level (cf. Fig. 10). Thus, the integration of waste heat from the capture process by pre-heating combustion air involves additional flue gas heat recovery by pre-heating part of the feed water (app. 5.5%) which bypasses the entire HP pre-heating train. The use of waste heat, however, is limited as the more waste heat is recovered the more the temperature difference between the incoming air and the flue gas is reduced (cf. Fig. 10). To retain reasonable heat exchanger surface areas in the APH, a minimal temperature difference of slightly below 30 K is assumed. Furthermore, a minimal temperature difference in the flue gas heat recovery feed water pre-heater of 50 K is assumed. This constrains the waste heat recovery to 15.7 MWth according to an air temperature of 59  C at the APH inlet. It must be noted that the net efficiency of the reference power plant without CO2 capture could also be increased by enlarging the amount of bleed steam to the steam air heater and by realising the same flue gas heat recovery system by feed water pre-heating. As this measure leads to an efficiency increase of only 0.14%-pts., it is usually not considered for state-of-the-art power plants due to the additional investment costs involved. By making use of waste heat from the CO2 capture process by maximum pre-heating of combustion air, the efficiency gain becomes as high as 0.52%-pts. in comparison to the base case without heat integration. The optimal point of condensate return is moved to a position between pre-heater 1 and 2 (cf. Fig. 1). 5.3. Combination of optimisation measures In the preceding paragraphs, various options to reduce the energy penalty were presented and the respective efficiency improvement potential was evaluated for each individual measure. The use of waste heat from the OHC requires the least interference: Part of the condensate is pre-heated in one heat exchanger in the capture process and is returned to the water-steam-cycle. Integration of waste heat from the intercoolers of the CO2 compressor is a more complex task as the compressor design has to be changed as well as various heat exchangers (intercoolers) are involved. Finally, the heat integration by pre-heating of combustion air is very costly and requires several changes to the configuration on both flue gas and water-steam side of the reference power plant. Ultimately, the corresponding additional investment costs for the individual integration options must be considered. The combination of all integration measures leads to an efficiency increase with respect to the base case of 1.02%-pts., thus reducing the efficiency penalty due to CCS to app. 9.6%-pts. Table 11 shows a summary of the determined net efficiencies for selected variants. “Reference” refers to the reference power plant without CO2 capture. “Base case” describes the variant in which the basic integration with no additional waste heat integration is realised. The variant “Optimised I” includes the use of OHC waste heat for condensate pre-heating. In the variant “Optimised II”, additional condensate pre-heating by waste Table 11 Net efficiency of selected variants with 90% CO2 capture. Variant

Net efficiencya (%)

Efficiency decreaseb (%-pts.)

Efficiency improvementc (%-pts.)

Reference w/out CCS Base case Optimised I Optimised II Best case

45.64 35.01 35.43 35.60 36.03

e 10.63 10.21 10.04 9.61

e e 0.42 0.59 1.02

a b c

based on lower heating value. with respect to the reference power plant. with respect to the base case.

heat from compressor intercoolers (option IC2_T40) is considered. A comparable efficiency of 35.53% is achieved by additional combustion air pre-heating as discussed in Section 5.2; however, this option involves higher additional expenses. Finally, the variant “best case” shows the efficiency that is reached if all integration options are considered, i. e. including the optimised de-superheating of reboiler steam (cf. Section 4.2) and the maximum pre-heating of combustion air by OHC waste heat. 6. Conclusions and outlook A base case configuration with an IP/LP crossover pressure of 5.5 bar (value at LP turbine inlet) was chosen to evaluate the integration of a post-combustion CO2 capture process (MEA) and a CO2 compressor into a greenfield state-of-the-art USC hard-coalfired power plant. In combination with the requirements for the simulated CO2 capture process this value corresponds to an excess pressure of 2.2 bar at the design point. It was shown that the basic integration which satisfies the heat, cooling and power duties without considering any additional integration measures leads to an efficiency decrease of 10.63%-pts. A tremendous impact of the choice of design IP/LP crossover pressure on design efficiency was identified. Lowering this pressure to 3.5 bar is accompanied by an increase in efficiency of 0.8%-pts. at the cost of negative part-load behaviour. The optimal design pressure is therefore a trade-off where the optimum strongly depends on the scheduled operating regime of the power plant. The suggested optimised de-superheating of reboiler steam by transferring the sensible heat onto the reboiler condensate by providing for an additional heat exchanger led to an efficiency increase of only 0.06%-pts. The temporary operation of the power plant without CO2 capture could be an economically attractive option, as the steam and power duties that are usually required by the CO2 capture unit and the CO2 compressor can be used to quickly increase the net power output of the power plant. However, non-capture operation implies a significant impact on the IP as well as the LP turbine flow regime. The mass flow to the LP turbine almost doubles when shifting from 90% CO2 capture to non-capture operation, while the volumetric steam flow at the IP outlet is nearly halved. Both effects must be considered when designing the turbines of a greenfield power plant with CO2 capture in which temporary non-capture operation is envisaged. The only attractive locations to extract waste heat at reasonable temperature levels are the desorber overhead condenser (OHC) in the capture process and the intercoolers of the CO2 compressor. Recovering the waste heat of the OHC by pre-heating the entire condensate stream to a temperature of app. 90  C and by bypassing pre-heaters 1 and 2 increases the efficiency of the overall process by 0.31%-pts. with respect to the base case. Using waste heat from the intercoolers of the CO2 compressor raises the power plant net efficiency by a maximum of 0.31%-pts. Since the heat at the OHC is recovered in only one heat exchanger, OHC waste heat usage appears to be the economically most viable option. By combining OHC and intercooler waste heat usage a net efficiency of 35.6%-pts. can be achieved, increasing the base case efficiency by 0.59%-pts. The restraining factor in combining the integration measures is the limited choice of heat sinks. As roughly 50% of the LP steam is extracted for solvent regeneration which bypasses the entire LP pre-heating train, the amount of condensate which can be pre-heated by waste heat is limited. Another possible heat sink is the combustion air. The effort involved in realising the heat integration by pre-heating of combustion air is much higher than the presented measures that involve the pre-heating of condensate. Nonetheless, the efficiency potential that lies in the advanced heat integration including the pre-heating of combustion air with OHC waste heat ranges from 0.52%-pts. without any

I. Pfaff et al. / Energy 35 (2010) 4030e4041

additional measures up to 1.02%-pts. if combined with the preheating of condensate by intercooler waste heat. Finally, it can be anticipated that for post-combustion CO2 capture processes that have similar sources and temperature levels of waste heat as the MEA process investigated in this work will show a similar potential for efficiency improvements by optimised integration measures. In the future, the effect of the integration variants presented in this study on the power plant in part-load and on the operability of the overall process must be considered. Ultimately, all options have to be compared based on their economical profitability. A flexible CO2 capture rate depending on the load regulating the amount of steam and thus influencing the throttling losses could be an option for the optimisation of the overall power plant in commercial operation. Acknowledgements The work presented in this paper has been supported financially by the German Ministry of Economics and Technology (BMWi). The opinions and interpretations expressed in this paper are, however, entirely the responsibility of the authors. References [1] Simmonds M, Hurst P. Post combustion technologies for CO2 capture: a techno-economic overview of selected options. In: Proceedings of the 7th international conference on greenhouse gas control technologies. BC, Canada: Vancouver; 2004. [2] Allam R, Bolland O, Davison J, Feron P, Goede F, Herrera A, et al. Special report on carbon dioxide capture and storage. IPCC; 2005 [chapter 3]. [3] García I, Zorraquino J. Energy and environmental optimization in thermoelectrical generating processes e application of a carbon dioxide capture system. Energy 2002;27:607e23. [4] Möller BF, Assadi M, Potts I. CO2-free power generation in combined cycles e integration of post-combustion separation of carbon dioxide in the steam cycle. Energy 2006;31:1520e32. [5] Pellegrini G, Strube R, Manfrida G. Comparative study of chemical absorbents in postcombustion CO2 capture. Energy 2010;35(2):851e7. [6] Abu-Zahra M, Schneiders L, Niederer J, Feron P, Versteeg G. CO2 capture from power plants: part I. A parametric study of the technical performance based on monoethanolamine. Int J Greenhouse Gas Control 2007;1(1):37e46.

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