Derivation of correlations to evaluate the impact of retrofitted post-combustion CO2 capture processes on steam power plant performance

International Journal of Greenhouse Gas Control 5 (2011) 1232–1239

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International Journal of Greenhouse Gas Control journal homepage: www.elsevier.com/locate/ijggc

Derivation of correlations to evaluate the impact of retrofitted post-combustion CO2 capture processes on steam power plant performance Ulrich Liebenthal ∗ , Sebastian Linnenberg, Jochen Oexmann, Alfons 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

Article history: Received 10 May 2010 Received in revised form 18 May 2011 Accepted 22 May 2011 Keywords: Post-combustion CO2 capture Power Plant Integration Compression

a b s t r a c t When integrating a post-combustion CO2 capture process and CO2 compression into a steam power plant, the three interface quantities heat, electricity and cooling duty must be satisfied by the power plant, leading to a loss in net efficiency. The heat duty shows to be the largest contributor to the overall net efficiency penalty of the power plant. Additional energy penalty results from the cooling and electric power duty of the capture and compression units. In this work, the dependency of the energy penalty on the quantity and quality of the heat duty is analyzed and quantified for a state-of-the-art hard coal fired power plant. Furthermore, the energy penalty attributed to the additional cooling and power duty is quantified. As a result correlations are provided which enable to predict the impact of the heat, cooling and electricity duty of post-combustion CO2 capture processes on the net output of a steam power plant in a holistic approach. © 2011 Elsevier Ltd. All rights reserved.

1. Introduction The application of a process for CO2 capture and subsequent geological storage (CCS) is a promising 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 the power plant. There is a large number of concepts for post-combustion CO2 capture from coal-fired power plants, but it is agreed that the implementation of an absorptiondesorption-process using a chemical solvent is the most developed and adequate process for deployment in the near- to middle-term (Kather et al., 2008; Rochelle, 2009). In recent years the number of selected solvents and proposed process configurations for post-combustion CO2 capture has strongly increased aiming for the lowest energy penalty of the overall steam power plant process. To identify the most promising new solvents and most energy efficient process configurations, an evaluation on a consistent basis is necessary to achieve an objective comparison. Independent of the solvent or the process configuration, the main interface quantities between power plant, capture unit and CO2 compressor which are affecting the net power output of a coal-fired power plant are: 1. The heat needed for solvent regeneration in the reboiler of the capture unit;

∗ Corresponding author. Tel.: +49 40 42878 2771; fax: +49 40 42878 2841. E-mail address: [email protected] (U. Liebenthal). 1750-5836/$ – see front matter © 2011 Elsevier Ltd. All rights reserved. doi:10.1016/j.ijggc.2011.05.033

2. The electrical duty of pumps and blowers within the capture unit and the CO2 compressor and the auxiliary power of additional cooling water pumps; 3. The large amounts of cooling water needed in the capture and compression process. The heat is commonly provided by extracting low-pressure steam from the water–steam-cycle of the power plant. The magnitude of the energy penalty is not only determined by the amount of extracted steam (quantity) but also by the quality of extracted steam (temperature and pressure). When optimizing process parameters of the CO2 capture unit such as the solution circulation rate or the desorber pressure, the variation of these parameters can have opposite effects on the required steam quantity and quality: • Solution circulation rate: an increase in solution circulation rate can enlarge the amount of stripping steam because more sensible heat is required to heat up the solution from absorber to desorber temperature (heat quantity ↑). If the CO2 capture rate is assumed to be constant, an increased solution circulation leads to a higher lean loading meaning a smaller degree of regeneration in the desorber. The higher lean loading is achieved at lower temperatures (Linnenberg et al., 2009) and therefore steam at a lower pressure level which condenses at lower temperatures can be used in the reboiler (heat quality ↓). • Desorber pressure: for solvents with a high heat of absorption such as MEA, an increase in desorber operating pressure and reboiler temperature leads to a smaller amount of water vapour at the

U. Liebenthal et al. / International Journal of Greenhouse Gas Control 5 (2011) 1232–1239

1233

Fig. 1. Schematic flow diagram of the reference power plant.

desorber head (Oexmann and Kather, 2010). Therefore, less heat and less steam must be provided in the reboiler (heat quantity ↓). The increase in desorber pressure and the corresponding increase in reboiler temperature, however, is equivalent to a need for steam with higher pressure (heat quality ↑).

These two examples show that an overall process optimization requires the consideration of the impact of process parameters not only on the CO2 capture unit in an isolated manner but on the overall process in a holistic approach. To determine the impact of the capture plant on the power plant detailed modelling and analysis of the water–steam-cycle of the power plant is necessary. Such work is done by several research groups (Abu-Zahra et al., 2007; Aroonwilas and Veawab, 2007; Linnenberg and Kather, 2009). As the development and evaluation of such models is a time consuming and complex task one possibility to evaluate the overall process is to use simplified correlations. Oyenekan and Rochelle introduced a correlation referred to as “equivalent work” (Oyenekan and Rochelle, 2006). With this expression, the amount of steam extraction for solvent regeneration, based on the Carnot efficiency, is transformed into an electrical power loss. Additionally, the power duty of the CO2 compressor is taken into account. In later publications the power duty of pumps within the capture plant are also included as an electrical power loss (Ziaii et al., 2009). The conversion of heat duty into equivalent (electric) power loss is also mentioned by Peeters et al. (2006). In their work the thermal energy for solvent regeneration multiplied by a power factor describes the power loss due to regeneration energy requirements. The intention of this work is to estimate the power loss due to steam extraction for solvent regeneration via a set of correlations derived from detailed power plant models. Additionally, correlations are provided to estimate the energy penalty attributed to the additional cooling and power duties of CO2 capture unit and CO2 compressor. Using these correlations researchers involved in the development of new solvents and/or process configurations for post-combustion CO2 capture processes can evaluate their findings with respect to the integrated overall process (“steam power plant” + “CO2 capture unit” and “CO2 compressor”) with a high degree of accuracy.

2. Modelling methodology Today, rigorous models are capable to provide accurate predictions for the heat, cooling and power duty of a CO2 capture unit (CCU). To evaluate the overall process it is not sufficient to represent the steam power plant and CO2 compressor in a simplified model. Therefore the intricate interaction of CCU with the steam power process duties need adequate models of similar accuracy for the steam power plant, and also for the CO2 compressor. In this work the commercial software tool EBSILONProfessional® 8.00 is applied to represent an adequate modelling methodology for the overall process. 2.1. Power plant island To allow comparisons to currently planned power plant projects, the power plant model used in this work is based on a state-of-the-art supercritical power station. The hard-coal fired power plant with high steam parameters (280 bar, 600 ◦ C) has a net power output of 1015.44 MWel,net (1100 MWel,gross ) and a net efficiency of 45.49% at its design point. The schematic flow diagram of the reference power plant is shown in Fig. 1. Additional information about the boundary conditions for the power plant is listed in Table 1. The flue gas parameters are listed in Table 2. If the power plant is retrofitted with a CO2 capture unit and a CO2 compressor certain components and units of the steam power plant are no longer being operated in their design point. Hence, the off-design behaviour of these components is adjusted by using twodimensional characteristics. For the characteristics of the steam turbines which are the main influencing components with respect

Table 1 Boundary conditions for the reference power plant (100 % load). Net (output) capacity (MWel )

1015.44

Heat input (MWth ) Net efficiency (%) Live steam conditions (◦ C/bar) Reheated steam conditions (◦ C/bar) IP/LP pressure (bar)

2232.06 45.49 600/285 620/60 3.9

1234

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Table 2 Flue gas parameters downstream flue gas desulphurisation unit (FGD) for the reference power plant (100 % load). Temperature (◦ C) Pressure (bar) Volumetric flow (m3 /s) Total mass flow (kg/s) CO2 mass flow (kg/s)

48.5 1.019 912.64 1021.05 213.40

Composition

vol.%

N2 O2 Ar H2 O CO2 SO2

70.70 3.29 0.85 11.24 13.92 <10 ppmva

a

SO2 concentration with enhanced FGD for CO2 capture.

to the net power output of a coal-fired power plant the following assumptions are made: • The isentropic efficiencies of each steam turbine (i.e. highpressure, HP; intermediate pressure, IP; low-pressure, LP) are kept constant over all stages and loads. Due to CCS the mass flow upstream of the LP turbine is reduced. As described in Section 2.2 the pressure decreases with increasing steam extraction. Hence, the volume flow and so the isentropic efficiencies are hardly affected due to these counteracting effects. The performance of the LP steam turbine in CCS operation is dominated by the effects of exhaust losses (see next item but one). • The last few stages of the LP turbine operate under wet steam conditions. The influence of moisture on the efficiency of the steam turbine is considered using a Baumann correction factor of 0.9 (Traupel, 2000). • In the LP turbine a kinetic energy loss and enthalpy increase associated with the steam exhausting from the last stage of the low-pressure section is assumed (Drbal et al., 1995). It includes losses associated with the turbine exhaust hood and the kinetic energy of the leaving steam. These exhaust losses are considered as a function of the exhaust loss area and the exhaust volume. • If the existing cooling system was capable of providing an additional cooling duty of the CO2 capture unit and the CO2 compression (about 30 % compared to the power plant without CCS) the condenser pressure would increase compared to the nominal condenser pressure. In this case modifications of the last stages in the LP-turbine would become necessary. In this work the installation of an additional cooling system to yield the cooling duty for the CCU and the compressor unit is assumed. As the steam going to the conventional condenser is decreased due to steam extraction the condenser pressure decreases and thus a beneficial power output of the LP-turbine is achieved if CO2 is captured. On the one hand the steam extraction leads to a decreasing exhaust volume flow of the LP-turbine. On the other hand, this effect is counteracted by a decreasing condenser pressure which leads to an increasing volume flow. Nevertheless the exhaust volume flow decreases in power plant performance with CCS. As shown in Fig. 1 two serial condensers are considered with a design condenser pressure of 40 mbar and 49 mbar, respectively. Within this work all results are based on this configuration. A variation of the cooling system (seawater cooling) or design condenser pressure strongly affects the performance of the LP turbine and so the efficiency penalty caused by CCS. However, a quantitative analysis of this effect is beyond the scope of this work.

2.2. Integration of the CO2 capture unit Steam extraction for solvent regeneration represents the largest contributor to the efficiency penalty. The possibilities to adapt the water–steam-cycle for a retrofit integration of a capture unit to optimize the overall process operation are limited. In this work the steam for the reboiler is considered to be extracted from the IP/LP crossover. The reboiler condensate is forwarded to the feed water tank in the water–steam-cycle of the power plant (cf. Fig. 2). Advanced integration configurations (e.g. waste heat integration, cf. Pfaff et al. (2009)) are not considered within this work. Due to the steam extraction for the CO2 capture unit the nominal pressure (3.9 bar) in the IP/LP crossover drops significantly to a low pressure level. The magnitude of pressure drop is estimated by Stodola’s Ellipse Law (cf. Stodola, 1922). As a certain steam quality is necessary to regenerate the solvent (depending on the desired reboiler temperature), steam conditioning is required. Taking into account the pressure drop due to steam extraction, it has to be differentiated whether the pressure in the IP/LP crossover is too high or too low for solvent regeneration. To provide the steam at the required pressure a throttle and a pressure maintaining valve are necessary (cf. Fig. 2). a. If the pressure in the IP/LP crossover is higher than required for solvent regeneration, the excessive pressure has to be throttled to the required level. The throttle is located between the IP/LP crossover pipe and the reboiler. b. If the pressure is lower than required for solvent regeneration, a pressure maintaining valve (PMV) has to be installed in the IP/LP crossover pipe downstream the extraction point. The pressure in front of the PMV can be held at a certain value while the pressure drops downstream the PMV. Due to the expected distance of a retrofitted CO2 capture unit to the steam turbine of the power plant a pressure loss of 0.4 bar in the branch pipe is assumed. Furthermore the mean temperature difference in the reboiler is assumed to be 10 K. For example, a temperature of 120 ◦ C in the reboiler and a temperature approach of 10 K leads to a required steam quality of 2.7 bar (Tsat 130 ◦ C) in front of the reboiler. Including the pressure loss in the feed pipe (0.4 bar), a steam quality of 3.1 bar is required in the IP/LP crossover. To avoid hot spots in the reboiler which could lead to thermal degradation of the solvent or increased fouling in the reboiler, the steam for solvent regeneration has to be saturated (e.g. by spray attemperation). 2.3. CO2 compressor The electric energy duty of the CO2 compressor has a large influence on the efficiency penalty of the integrated overall process (∼2.5%-pts., Linnenberg et al., 2009). In this work, a simplified correlation is derived to evaluate the impact of the CO2 compressor. To transport the separated CO2 to the injection well, a pipeline pressure of 110 bar is assumed. As the CO2 leaving the desorber is water saturated, the compressor has to cope with moist CO2 . In this study an integrally geared (radial) compressor with six stages, three intercoolers and an after-cooler is considered. Depending on the overall pressure ratio it might be necessary to vary the number of stages for the compressor. A calculation method for the real gas behaviour is chosen within EBSILONProfessional® 8.00 to take into consideration the non-ideal behaviour of the CO2 during compression and cooling (Kretzschmar et al., 2008). The assumptions for the model of the CO2 compressor are summarised in Table 3. A steam-driven CO2 compressor is not taken into account.

U. Liebenthal et al. / International Journal of Greenhouse Gas Control 5 (2011) 1232–1239

HP

IP

LP

LP

1235

generator

3.9 1.8 bar bar PMV throttle

SG

condenser HP: High pressure IP: Intermediate pressure LP: Low pressure SG: Steam generator FWT: Feed water tank FWP: Feed water pump PMV: Pressure maintenance valve

Reboiler FWT

FWP

Fig. 2. Schematic integration of the reboiler.

The overall loss in net power output of the power plant due to post-combustion CO2 capture can be expressed as a sum of five terms: PLoss = PCCU,Steam + PCCU,el + PComp,el + PCCU,cw + PComp,cw .

(1)

where PCCU,Steam is the power decrease due to steam extraction for solvent regeneration, PCCU,el is the additional auxiliary power of the CO2 capture unit, PComp,el is the additional auxiliary power of the CO2 compressor, PCCU,cw is the auxiliary power of the cooling water pumps of the CCU and PComp,cw is the auxiliary power the cooling water pumps of the CO2 compressor. 3.1. Heat duty (PCCU,Steam ) The impact of steam extraction PCCU,Steam can be determined by a factor that converts an extracted heat flow Q˙ Steam into the equivalent electric power loss: ( = f (Q˙ Steam , Treb )).

(2)

The factor  is referred to as “Power Loss Factor”. The power loss factor is a function of the extracted steam quantity (Q˙ Steam ) and the steam quality by means of the reboiler temperature (Treb ). The required steam quantity Q˙ Steam can be determined by: ˙ CO2 qreb Q˙ Steam = εm

0,5 Required IP/LP pressure IP/LP pressure (open-valve operation) Power Loss Factor

(3)

Table 3 Boundary conditions for the intercooled CO2 compressor with six stages. CO2 temperature after desorber (◦ C) CO2 pressure after desorber (bar) CO2 purity (%) Number of radial stages Pressure ratio for all stages (–) Polytropic efficiency (%) Number of intercoolers (+after cooler) Recooling temperature (◦ C) Pressure drop of cooler (mbar) Pressure drop between stages (mbar) Pressure at outlet (bar) Temperature at outlet (◦ C)

a. A relatively high reboiler temperature of, for example, 140 ◦ C leads to a required steam pressure of 5.2 bar (including throttling losses and temperature approach in the reboiler) for solvent regeneration (cf. Fig. 3). As the nominal pressure (3.9 bar) in the IP/LP crossover is below 5.2 bar, a pressure maintaining valve (PMV) is necessary to back up the pressure (see Section 2.2). As a result the pressure downstream the PMV drops. For a deeper understanding of the impact of steam extraction at a certain temperature level on the steam power plant process a closer look at the behaviour of the steam turbines is necessary. Fig. 4 shows a h,s-diagram of the steam turbines for power plant performance with and without CCS. The HP-turbine is not significantly affected by CCS as the steam extraction is located in the IP/LP crossover. The influence of CCS on the IP- and LP-turbines can be delineated by four magnitudes of influence. P1 and P2 : For the assumed reboiler temperature of 140 ◦ C the PMV needs to be activated. Hence, the pressure in the

40 Variable 98.5 6 Constant 85 3 (+1) 40 50 50 110 40

0,4

Power Loss Factor σ

PCCU,Steam = Q˙ Steam ,

˙ CO2 is the CO2 mass flow at the where ε is the CO2 capture rate, m inlet of the absorber and qreb is the mass specific heat duty of the CO2 capture unit (e.g. in MJth /kg CO2 ). The lower the power loss factor, the lower the electrical power loss of the power plant due to steam extraction (Eq. (2)). To explain the behaviour of the power loss factor for different steam quality and quantity levels three exemplary situations are discussed below.

6

5

4

0,3

3 0,2 2 0,1 1

0,0 0

100

200

300 .

400

500

600

Q Steam(MWth) Fig. 3. Power loss factor for a reboiler temperature of 140 ◦ C.

0 700

Pressure in IP/LP crossover (bar)

3. Results

1236

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Fig. 4. h,s-diagram for turbine performance with PMV.

(4)

As different reboiler temperatures lead to different load allocation between the IP-turbine and the LP-turbine Fig. 4 is only valid for a reboiler temperature of 140 ◦ C. For example a shift of the energy conversion from the LP-turbine to the IP-turbine is expected if the pressure in the IP/LP crossover drops below the nominal value of 3.9 bar. This explanation above leads to the characteristics of the power loss factor shown in Fig. 3: Even if the pressure drop of the PMV increases with increasing steam extraction, the power loss factor, related to the extracted heat, decreases with increasing steam extraction. b. A low reboiler temperature of 100 ◦ C on the solvent side leads to a required steam pressure of 1.8 bar (including throttling losses and temperature approach in the reboiler) for solvent regeneration (cf. Fig. 5). For the entire range of steam extraction shown in Fig. 5 the pressure in the IP/LP crossover is above the required pressure of 1.8 bar (3.5–1.8 bar). Hence, as mentioned in Section 2.2, a throttle is necessary to throttle the excessive pressure difference (pressure in IP/LP crossover – required pressure). The less the excessive pressure is that needs to be throttled to the desired

0,5 Required IP/LP pressure IP/LP pressure (open-valve operation) Power Loss Factor

0,4

6

5

4

0,3

3 0,2 2 0,1 1

0,0 0

100

200

300

400

. QSteam(MW th)

500

600

Fig. 5. Power loss factor for a reboiler temperature of 100 ◦ C.

0 700

Pressure in IP/LP crossover (bar)

Pturbine = P1 + P2 + P3 − P4 .

1.8 bar (corresponding to an increasing steam extraction), the lower the power loss factor. As the pressure in the IP/LP crossover drops, both the back pressure of the IP-turbine and the inlet pressure of the LP-turbine decrease. Hence, a part of the energy conversion is shifted from the LP-turbine to the IP-turbine. A detailed illustration of the turbine performance, which is exemplarily shown in Fig. 4 for a high reboiler temperature, is out the scope of this work. c. A combination of (a) and (b) can be shown for an intermediate reboiler temperature of, for example, 120 ◦ C which leads to a required steam pressure of 3.1 bar (including throttling losses and temperature approach in the reboiler) for solvent regeneration (cf. Fig. 6). For a small amount of extracted steam the pressure in the IP/LP crossover is above the required pressure and the pressure difference has to be throttled (cf. case (b)). Extracting more steam would lead to a pressure drop below 3.1 bar (see turning point for solid line in Fig. 6). Hence, at a certain amount of extracted steam, the throttle has to be deactivated and the PMV has to be activated in order to keep the pressure level at 3.1 bar. As long as the throttle is active, the power loss factor decreases with increasing steam extraction. Further increasing of steam extraction boosts the power loss factor (cf. Fig. 6).

Power Loss Factor σ

IP/LP crossover increases from 3.9 bar to the required pressure of 5.2 bar and the energy conversion is shifted from the IPturbine to the LP-turbine (h1 in Fig. 4). Simultaneously, the inlet pressure for the LP-turbine (e.g. 1.9 bar, depending on the amount of extracted steam) decreases due to the isenthalpic behaviour of the PMV. Within the range h1 and h2 less steam can be converted into electrical power due to steam extraction for solvent regeneration. P3 : As the isobar lines increase with increasing entropy a constant condenser pressure (=back pressure for the LP-turbine) would lead to a decrease of energy conversion in the LP-turbine for the CCS case (h1 in Fig. 4). P4 : As mentioned in Section 2.1 an additional cooling system for the cooling duty of the CCU and the CO2 compressor is assumed. For performance with CCS the exhaust steam of the LP-turbine decreases. Thus, the condenser pressure decreases, which leads to an increase of energy conversion in the LP-turbine. The overall influence of CCS on the turbine performance Pturbine can be summarised to be

U. Liebenthal et al. / International Journal of Greenhouse Gas Control 5 (2011) 1232–1239

Required IP/LP crossover pressure for open-valve operation (bar)

0,5 Required IP/LP pressure IP/LP pressure (open-valve operation) Power Loss Factor

3 0,2 2 0,1 1

0,0 300

400

. QSteam(MWth )

500

1,5

2,0

2,5

3,0

0,5

110 105 100 95 90 85 80 75 70 0

3,5

4,0

4,5

5,0

5,5

Treb 0,5

Power Loss Factor σ

1,0

65

Specific heat duty for 90 % capture rate (MJ/kg CO2) 1,0

1,5

115

0 700

600

As the required pressure is below the nominal pressure of 3.9 bar, energy conversion is shifted from the LP-turbine to the IP-turbine. Depending on the amount of extracted steam different characteristics of the turbine in a h,s-diagram occur. A detailed description of the turbine performance goes beyond the scope of this work. The results using the simulation methodology explained in Section 2.2 are presented in Fig. 7. The lower the reboiler temperature, the more steam can be extracted without activating the PMV and thus an increased power loss factor can be avoided. Additionally to the explanations above, it turns out that the power loss factor is nearly independent of the reboiler temperature as long as the throttle (cf. case (b)) is activated. It has to be mentioned that for lower quality steam extraction (Treb < 130 ◦ C) the pressure level in the IP/LP crossover drops below the nominal pressure of 3.9 bar. As the live steam mass flow remains constant the specific exhaust volume flow in the last stage of the IP turbine (actual volume flow/nominal volume flow) increases. For a specific exhaust volume flow in the IP turbine larger than approx. 1.4 this might lead to a limitation as damages in the last turbine stages of the IP turbine might occur. Further discussions of this limitation can be found in Section 3.5. To describe the curves shown in Fig. 7 two different mathematical approaches are necessary. The asymptotic curves reveal

0,5

2,0

120

200

Fig. 6. Power loss factor for a reboiler temperature of 120 ◦ C.

0,0

2,5

125

Treb (°C)

0,3

Pressure in IP/LP crossover (bar)

Power Loss Factor σ

4

200

3,0

130 5

100

3,5

6

0,4

0

1237

160 °C 150 °C 140 °C 130 °C 120 °C 110 °C 100 °C 70 °C

0,4

600

800

. QSwitch(MW th)

1000

Fig. 8. Switch function for varying reboiler temperature (open-valve operation).

the operation with a PMV, showing a stringent dependency on the reboiler temperature and can be described by:   = a

(Treb − b ) + c . Q˙ Steam

(5)

The (nearly) reboiler temperature independent curves (lowermost curves in Fig. 4) reveal the operation with a throttle and can be described by: 2 + b Q˙ |Steam + c  .   = a Q˙ Steam

(6)

In order to decide whether Eq. (5) or Eq. (6) has to be used to calculate the power loss factor, a “switch”-function is necessary: 2 + bSwitch Treb + cSwitch . Q˙ Switch = aSwitch Treb





(7)

  , for Q˙ Steam > Q˙ Switch   , for Q˙ Steam < Q˙ Sswitch

(8)

The “switch”-function also defines an open-valve operation. (i.e. the pressure available for the capture unit is given by the amount of steam extraction see Fig. 8). If the capture unit is capable using the resulting IP/LP crossover pressure level, both the PMV and the throttle can be avoided using this configuration. The coefficients and units for the equation system are listed in Table 4. 3.2. Auxiliary power duty of the CO2 capture unit (PCCU,el ) The auxiliary power duty of the CO2 capture unit is mainly attributed to the additional blower and the solvent pumps. This duty directly decreases the net power output of the power plant. Table 4 Coefficients for the power loss calculation. Power loss factor a (MW) = 1.6248 b (◦ C) = 130.2970 c (–) = 0.2542

0,3

400

a (1/MW2 ) = −5.207E−8 b (1/MW) = −6.466E−6 c (–) = 0.1955

aSwitch (1/◦ C2 ) = −0.2003 bSwitch (1/◦ C) = 24.8435 cSwitch (MW) = 138.8601

Specific power duty and cooling duty for CO2 compressor

0,2

0

200

400

.

600

800

QSteam(MWth) Fig. 7. Modelling results of the power loss factor.

1000

ael (MW/bar kg) = (MW/kg)) = 0.3948 bel (–) = −0.3893 cel (MW/kg) = 0.0301

acw (MW/bar) = 0.5736 bcw (–) = −0.2698 ccw (MW/kg) = 0.0901

Specific auxiliary power duty ϕcw (MJel /tcw (MegaJoule electric/tonnes cooling water)) = 0.3882

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U. Liebenthal et al. / International Journal of Greenhouse Gas Control 5 (2011) 1232–1239

where pin is the inlet pressure. The outlet pressure is assumed to be 110 bar. The coefficients and corresponding units are listed in Table 4.

Specific cooling / power duty (MJ/kg CO2)

1,0 Cooling duty Power duty

0,9 0,8

3.4. Auxiliary power duty of the cooling water pumps of the CCU and the CO2 compressor (PCCU,cw and PComp,cw )

0,7

Both the capture plant and the CO2 compressor have a certain duty of cooling water. Hence, additional cooling water pumps are required which reduce the net power output of the power plant. The Eqs. (11) and (12) enable to convert a cooling duty into an electric power loss:

0,6 0,5 0,4 0,3

PCCU,cw =

Q˙ Comp,cool ϕcw

0,2 0,0

0,5

1,0

1,5

2,0

2,5

3,0

3,5

4,0

4,5

Inlet pressure (bar) Fig. 9. Specific cooling/power duty of the CO2 compressor for varying inlet pressure.

Table 5 Maximal steam extraction for IP turbine operation leading to a specific exhaust volume flow of 140%. Treb (◦ C)

Q˙ Steam,max (MWth )

70 80 90 100 110

456 450 444 439 432

PComp,cw =

Cp,cw Tcw Q˙ Comp,cool ϕcw Cp,cw Tcw

(11)

(12)

where Q˙ Comp,cool is the cooling duty of the CCU, Q˙ Comp,cool is the cooling duty of the compressor, cp,cw is the specific heat capacity of the cooling water, Tcw is the temperature gain of the cooling water and ϕcw is the specific auxiliary power duty. The cooling duty of the CCU can be calculated by: ˙ CO2 qCCU,cool Q˙ CCU,cool = εm

(13)

where qCCU,cool is the specific cooling duty of the CO2 capture unit. Besides the specific power duty, the specific cooling duty of the CO2 compressor is also shown in Fig. 9. A similar correlation as used for the power duty (cf. Section 3.3) can be used to determine the cooling duty:

Hence, it is either known from the simulation results as an absolute figure PCCU,el or, in case a specific power duty is known, can be calculated by: ˙ CO2 wCCU,el . PCCU,el = εm

(9)

where wCCU,el is the specific power duty of the CO2 capture unit.

˙ CO2 (acw pbincw + ccw ). Q˙ Comp,cool = εm

(14)

The coefficients for Eqs. (10)–(13) are listed in Table 4. The value for the specific auxiliary power duty ϕcw is determined for a cooling system with 3 bar pressure increase assuming an isentropic pump efficiency of 80%. The electric motor is modelled with an electrical efficiency of 97%. Additionally, 0.2% mechanical losses are considered. The coefficient ϕcw and the units for the equation system are also given in Table 4.

3.3. Auxiliary power duty of the CO2 compressor (PComp,el ) 3.5. Accuracy and valid parameter range As mentioned in Section 2.3, correlations are derived from a CO2 compressor model to determine the corresponding power duty as a function of the inlet pressure. Fig. 9 shows the specific cooling duty of the CO2 compressor. The correlation is based on an exponential approach: ˙ CO2 (ael pbinel + cel ). PComp,el = εm

(10)

The analysis presented in this work is accomplished for reboiler temperatures between 70 and 160 ◦ C. The amount of extracted steam has been varied from 190 to 960 MWth which corresponds to specific heat duties for solvent regeneration between 1.0 and 5.0 GJ/t CO2 for a capture rate of 90% (cf. Fig. 7). The inlet pressure for CO2 compressor is analyzed between 0.5 and 7 bar.

Table 6 Example calculation. Input values

Pre-calculation steps

Results for solvent evaluation

qreb (MJ/kg CO2 ) = 3.5

QSteam (MWth ) = 672.21

PCCU,steam (MWel ) = 154.15

wCCU,el (MJ/kg CO2 ) = 0.1

QSwitch (MWth ) = 235.40

PCCU,el (MWel ) = 19.21

qCCU,cool (MJ/kg CO2 ) = 4.0

QSwitch < QSwitch  =  

PComp,el (MWel ) = 62.77

Treb (◦ C) = 120

 (–) = 0.23

PCCU,cw (MWel ) = 7.13

pdes = pin (bar) = 2.1

Q˙ CCU,cool (MWth ) = 768.24

PCopm,cw (MWel ) = 1.00

ε (–) = 0.9

Q˙ Comp,cool (MWth ) = 107.48

Tcw (K) = 10.0

Ploss (MWel ) = 244.25

cp,cw (MJ/(t K)) = 4.18 Pel,nom (MWel ) * = 1015.44

net (%) = 34.55

Q˙ in (MWth )∗ = 2232.06

net (% -pts.) = 10.94

˙ CO2 (kg/s)∗ = 213.40 m *From reference power plant (fixed values).

U. Liebenthal et al. / International Journal of Greenhouse Gas Control 5 (2011) 1232–1239

All correlations are developed targeting the lowest deviance between the power plant model with steam extraction for solvent regeneration and the correlations in order to reach the highest degree of accuracy. The largest discrepancy between modelling results and correlations in the given parameter range with respect to a single power loss term Pi is below 6%. As mentioned in Section 3.1, there are limitations for the maximal exhaust volume flow of the IP turbine and thus the minimal pressure in the IP/LP crossover. Reboiler temperatures below 115 ◦ C and steam extractions higher than approx. 430 MWth lead to a specific exhaust volume flow above 1.4 for the IP turbine outlet and a corresponding pressure level of about 2.4 bar in the IP/LP crossover (cf. Table 5 for exact values). Due to the increased steam flow bending stresses in the last turbine stage of the IP turbine become higher compared to the design case and can lead to a destruction of the blades. To evaluate if the operation of the turbine is still feasible or a retrofitting of the IP turbine is necessary detailed turbine analysis is required. For a retrofitting of the turbine, additional integration effort and investment costs have to be considered. The correlations derived in this work are based on the power plant model as described in Section 2.1 and might deviate for other coal-fired power plants. One important issue is the nominal pressure level in the IP/LP crossover which varies for different power plants (between approx. 3.5–6 bar for newly build power plants). It must be kept in mind that the pressure level directly affects the steam extraction and thus the power loss factor. 3.6. Example calculations In Table 6 a step-by-step example calculation is given which serves as a guideline for the application of the presented equations. 4. Conclusions and outlook In this work, the overall loss in net power output of the power plant due to post-combustion CO2 capture was analyzed and quantified for a state-of-the-art hard coal fired power plant using the simulation tool EBSILONProfessional® 8.00. As the overall loss in net power output can be expressed as a sum of five terms (Eq. (1)), all terms were analyzed and transferred into empirical correlations. The impact of steam extraction was determined by the power loss factor  that converts an extracted heat flow for solvent regeneration into the equivalent electric power loss. To provide the steam at the required pressure (heat quality), a throttle and a pressure maintaining valve are necessary. For the power plant process observed in this work it was shown that for reboiler temperatures between 130 ◦ C and 160 ◦ C the power loss factor decreases with increasing steam extraction (heat quantity) due to lower specific losses of the PMV. For reboiler temperatures below 130 ◦ C the power loss factor decreases with increasing steam extraction (cf. case (b) in Section 2.2) as long as the pressure in the IP/LP crossover pipe is sufficient for solvent regeneration. When the PMV needs to be activated, the power loss factor increases with increasing steam extraction. Furthermore it was shown that the specific power duty of the CO2 compressor decreases for a higher reboiler temperature and thus a higher inlet pressure. Correspondingly, the specific cooling duty of the CO2 compressor decreases for a higher inlet pressure. Correlations for the additional auxiliary power of the CO2 capture unit, the auxiliary power of the cooling water pumps of the CCU and the CO2 compressor were also provided in order to allow a complete evaluation of new solvents and/or process configurations for post-combustion CO2 capture processes in a holistic approach.

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As mentioned in Section 3.5, power plants with different design pressures in the IP/LP crossover pipe lead to different characteristics of the power loss factor and will be considered in future work. Furthermore, the requirements for the operation of a power plant change due to the increasing importance of renewable energy sources. A flexible operation range of conventional steam power plants becomes necessary. Hence, part-load conditions of the power plant, the capture unit, and the CO2 compressor need to be investigated and considered in the evaluation of post-combustion CO2 capture processes. 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. Appendix A. Supplementary data Supplementary data associated with this article can be found, in the online version, at doi:10.1016/j.ijggc.2011.05.033. References Abu-Zahra, M., Schneiders, L., Niederer, J., Feron, P., Versteeg, G., 2007. CO2 capture from power plants: Part I. A parametric study of the technical performance based on monoethanolamine. International Journal of Greenhouse Gas Control 1 (1), 37–46. Aroonwilas, A., Veawab, A., 2007. Integration of CO2 capture unit using single- and blended-amines into supercritical coal-fired power plant: implications for emission and energy management. International Journal of Greenhouse Gas Control 1 (1), 143–150. Drbal, L.F., Boston, P., Westra, K.L., 1995. Power Plant Engineering. Springer Netherlands, ISBN 0-412-06401-4. Kather, A., Rafailidis, S., Hermsdorf, C., Klostermann, M., Maschmann, A., Mieske, K., Oexmann, J., Pfaff, I., Rohloff, K., Wilken, J., 2008. Research & development needs for clean coal deployment number CCC/130. IEA Clean Coal Centre, ISBN:97892-9029-449-3. Kretzschmar, H.-J., Stoecker, I., Jaehne, I., Kleemann, L., Seibt, D., 2008. Property Software for Humid Gas Mixtures, LibHuGas. Faculty of Mechanical Engineering, Department of Technical Thermodynamics, Hochschule Zittau/Görlitz. Linnenberg, S., Kather, A., 2009. Evaluation of an integrated post-combustion CO2 capture process for varying loads in a coal-fired power plant using monoethanolamine. In: 4th International Conference on Clean Coal Technologies , Dresden. Linnenberg, S., Oexmann, Kather, A., 2009. Design consideration of post-combustion CO2 capture process during part load operation of a coal-fired power plant. In: 12th Workshop of the International Network for CO2 Capture , Regina, Kanada. Oexmann, J., Kather, A., 2010. Minimising the regeneration heat duty of postcombustion CO2 -capture processes by wet chemical absorption: the misguided focus on low heat of absorption solvents. International Journal of Greenhouse Gas Control 4 (1), 36–43. Oyenekan, B.A., Rochelle, G.T., 2006. Energy performance of stripper configurations for CO2 capture by aqueous amines. Industrial & Engineering Chemistry Research 45 (8), 2457–2464. Peeters, A., Faaij, A., Turkenburg, W., 2006. Technological and economic comparison of CO2 capture technologies including development potential evaluations. In: Proceedings of the 8th International Conference on Greenhouse Gas Control Technologies , Trondheim. Norway. Pfaff, I., Oexmann, J., Kather, A., 2009. Integration studies of post-combustion CO2 capture process by wet chemical absorption into coal-fired power plant. In: 4th International Conference on Clean Coal Technologies , Dresden. Rochelle, G., 2009. Amine scrubbing for CO2 capture. Science 325, 1652–1654. Stodola, A., 1922. Dampf- und Gasturbinen. VDI, ISBN 3184007278. Traupel, W., 2000. Thermische Turbomaschinen: Zweiter Band. Geänderte Betriebsbedingungen, Regelung, Mechanische Probleme. In: Temperaturprobleme. Springer, Berlin, ISBN 978-354-0673774. Ziaii, S., Rochelle, T., Edgar, T.F., 2009. Dynamic modeling to minimize energy use for CO2 capture in power plants by aqueous monoethanolamine, industrial & engineering chemistry research. American Chemical Society 48, 6105–6111.