CO2 capture from coal-fired power plants based on sodium carbonate slurry; a systems feasibility and sensitivity study

international journal of greenhouse gas control 3 (2009) 143–151

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CO2 capture from coal-fired power plants based on sodium carbonate slurry; a systems feasibility and sensitivity study Hanna Knuutila a, Hallvard F. Svendsen b,*, Mikko Anttila c a

Tampere University of Technology, Institute of energy and process technology, PL 589, 33101 Tampere, Finland Department of Chemical Engineering, The Norwegian University of Science and Technology (NTNU), NO-7491 Trondheim, Norway c Metso Power Oy, Box 109, FIN-33101 Tampere, Finland b

article info

abstract

Article history:

In this work the feasibility of a CO2 capture system based on sodium carbonate–bicarbonate

Received 20 July 2007

slurry and its integration with a power plant is studied. The results are compared to

Received in revised form

monoethanolamine (MEA)-based capture systems. Condensing power plant and combined

28 April 2008

heat and power plant with CO2 capture is modelled to study the feasibility of combined heat

Accepted 6 June 2008

and power plant for CO2 capture.

Published on line 5 August 2008

Environmental friendly sodium carbonate would be an interesting chemical for CO2 capture. Sodium carbonate absorbs CO2 forming sodium bicarbonate. The low solubility of

Keywords:

sodium bicarbonate is a weak point for the sodium carbonate based liquid systems since it

CO2 capture

limits the total concentration of carbonate. In this study the formation of solid bicarbonate is

Sodium carbonate

allowed, thus forming slurry, which can increase the capacity of the solvent. With this the

Combined heat and power plant

energy requirement of stripping of the solvent could potentially be around 3.22 MJ/kg of

Absorption process

captured CO2 which is significantly lower than with MEA based systems which typically have energy consumption around 3.8 MJ/kg of captured CO2. Combined heat and power plants seem to be attractive for CO2 capture because of the high total energy efficiency of the plants. In a condensing power plant the CO2 capture decreases directly the electricity production whereas in a combined heat and power plant the loss can be divided between district heat and electricity according to demand. # 2008 Elsevier Ltd. All rights reserved.

1.

Introduction

About 24% of the world’s primary energy is produced by coal causing 39% of the total annual carbon dioxide (CO2) emissions (IEA, 2004). Coal-fired power plants are large point sources of carbon dioxide making them attractive for CO2 capture. For retrofit cases post-combustion CO2 capture by absorption is normally considered the most feasible option. One of the most studied chemicals for post-combustion capture in power plants is monoethanolamine (MEA) (Rao and Rubin, 2006; Alstom, 2001). MEA is very reactive with a possibility of high CO2 removal

efficiency. The downside of MEA is a high energy requirement per tonne CO2 captured, and considerable waste generation caused by amine degradation. To decrease the energy requirement and to find environmental friendly chemicals, carbonate systems have gained interest. Carbonate CO2 capture systems have been used in special applications for decades, and in recent years, interest also for power plant applications has increased (Cullinane and Rochelle, 2004; Corti, 2004; Liang et al., 2004). In this paper the feasibility of a CO2-capture system based on sodium carbonate-bicarbonate slurry is studied using the chemical simulation engine CHEMCAD 5.6.

* Corresponding author. E-mail address: [email protected] (H.F. Svendsen). 1750-5836/$ – see front matter # 2008 Elsevier Ltd. All rights reserved. doi:10.1016/j.ijggc.2008.06.006

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international journal of greenhouse gas control 3 (2009) 143–151

Fig. 1 – Flow diagram of condensing power plant.

Since post combustion CO2 capture is very energy intensive, decreasing the electricity output of power plants significantly, there is a need to find high efficiency power production systems from which CO2 could be captured more economically. There are many literature studies on high efficiency power generation systems like natural gas combined cycles or gasification cycles (Kaldis et al., 2004; Bolland and Undrum, 2003). Typically, in these studies the plant produces electricity with a total efficiency of 50–60% (LHV) without capture of CO2. In many European countries, the heat needed in district heating systems is produced using combined heat and power plants (CHP). In CHP-plants total energy efficiency around 80–90% can be achieved making them potentially very attractive for CO2 capture (Rong and Lahdelma, 2007; Desideri and Corbelli, 1998). In a CO2 capture plant there is also ‘‘waste heat’’ available at temperatures lower than 100 8C. In a CHP-plant part of this heat could be used to produce district heat. In this paper the potential of using waste heat available in the CO2 capture plant in the power plants is studied in reference to a condensing and combined heat and power plant.

The electricity production of the plant is 521 MW with an LHV energy efficiency of 39%. Two combined heat and power plants (CHP-plant) with different fuel inputs were modelled. In the case CHP-1 reduction in electricity and heat production is accepted, when CO2 capture is added. In case CHP-2 heat production is maintained by extra fuel addition. The flow diagram of the modelled plants is shown in Fig. 2, and operational data given in Table 1. CHP plants are typically operated so that the demand for district heat is satisfied. District heat is used for heating buildings and water, and the heat demand depends on the outdoor temperature. The electricity production depends on the heat production, decreasing as the heat production increases. During low district heat demand, the power plant produces more electricity by using the low pressure steam turbine. At maximum heat demand, no steam passes through the sea water condenser and the backpressure of the turbine is that determined by the temperature of the water in the district heating system.

3. 2.

CO2 capture with sodium carbonate

Power plants

Three power plants are modelled in this study. They have the same boiler size and burn a Polish coal. The plants are considered to be located on the coast, and sea water is used for condensing the low pressure steam coming from the steam turbines. The first is the condensing power plant (CP-plant) shown in Fig. 1, and the main input parameters are shown in Table 1.

Normally sodium carbonate is considered unsuitable for CO2 capture from low CO2 partial pressure sources, because of the limited solubility of both carbonate and bicarbonate. In this study, this problem was circumvented by allowing the systems to work in a slurry phase. Since the CO2 absorption produces sodium bicarbonate, which has lower solubility than the carbonate, the solubility limit is exceeded and solid bicarbonate is precipitated thereby increasing the capacity of the solvent.

international journal of greenhouse gas control 3 (2009) 143–151

Table 1 – Operational data of the power plants Plant Fuel Electrical output (MWe) District heating output (MWth) Fuel input (MWth) Total efficiency (%LHV) Main steam Medium-pressure steam Condensator pressure (Bar) Water in district heating system before heat exchangers (8C) water in district heating system after heat exchangers (8C) Isentropic efficiency of turbine Isentropic efficiencies of pumps

CHP-2

145

HCO3. The overall reaction can be divided into following reactions:

CP

CHP-1

Polish coal 521

Polish coal 360

Polish coal 267

0

810

600

1336 39

1336 88

990 88

240 bar/ 540 8C 46 bar/ 540 8C 0.002

136 bar/ 535 8C –

136 bar/ 535 8C –

0.02

0.02

When bicarbonate concentration in the liquid phase reaches the solubility limit of sodium bicarbonate solid sodium bicarbonate (NaHCO3) will be formed based on following reaction:

–

70

70

Dissociation of solid NaHCO3

Dissolution of CO2 in the liquid CO2 ðgÞ ! CO2 ðlÞ Dissociation of water Dissociation of CO2

–

120

120

0.90

0.90

0.90

0.80

0.80

0.80

A simplified flow diagram of the system is shown in Fig. 3. In the absorber, CO2 reacts with carbonate ions producing bicarbonate ions with overall reaction of CO3 + H2O + CO2 !

H2 O $ OH þ Hþ CO2 ðlÞ þ H2 O $ HCO3  þ Hþ

Dissociation of bicarbonate ion

HCO3  $ CO3 2 þ Hþ

Naþ þ HCO3  $ NaHCO3 ðsÞ:

The CO2 rich slurry solvent is then taken to the stripper where, the reaction above are reversed by heating the solvent and the captured CO2 is released. The regenerated solvent is recycled to absorber. The concentrated CO2–H2O stream coming from the stripper at about 1.8 bar pressure is cooled down to separate water, and pure CO2 gas is pressurized for transport and storage. Heat of solution for sodium bicarbonate can be found in Perry’s Chemical Engineers’ Handbook (Perry and Green, 1997) and heat of reaction for formation of sodium bicarbonate can be found in article of Vanderzee and Berg (1978). A detailed study was carried out to define working conditions for a post combustion CO2 capture system based on sodium carbonate–bicarbonate slurries. Chemical and phase equilibria calculations of CHEMCAD were checked and found to be accurate enough for this study. For the

Fig. 2 – Flow diagram of the combined heat and power plant.

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Fig. 3 – Simplified flow diagram of the CO2 capture system modelled.

evaluation of the behaviour of the CO2 capture unit, a sensitivity analysis was performed. The parameters varied were the concentration of sodium carbonate in the liquid (10– 30 wt.%), the absorber inlet liquid and flue gas temperatures (45–70 8C), the solvent/gas ratio (2.1–5.5) and the stripper pressure (1–2 bar). The results are shown in Table 2. The results for solvent-gas ratio for 30 wt.% sodium carbonate solutions are shown in Fig. 4 and the effect of capture efficiency and stripper pressure are shown in Fig. 5. The reboiler temperature varies from 104 8C (stripper pressure of 1 bar) to 121 8C (stipper pressure of 2 bar). The energy consumption decreases as the sodium carbonate concentration increases as shown in Table 2. This is mainly because of the increased CO2 capture capacity of the solvent, making it possible to decrease the liquid/gas mass flow ratio. This decreases the amount of water entering the stripper. The chosen 30 wt.% sodium carbonate solution is near the solubility limits of sodium carbonate at 60 8C (Linke, 1965). From the chemical equilibrium point of view, a low temperature in the absorption tower would be beneficial. It is well known that the absorption rate of carbonate solutions is low at low temperatures, and an inlet temperature of 60 8C for the solution was chosen based on the literature (Astarita et al., 1981; Knuutila et al., 2006,) The chosen temperature is somewhat higher than temperatures used in sodium carbonate based CO2 capture systems used in dry ice plants in the beginning of the 1900s (Howe, 1928; Comstock and Dodge, 1937). In the simulations it has been assumed that equilibrium between inlet gas and outlet liquid is obtained at the bottom of the absorber. The minimum slurry/gas ratio needed to achieve 90% CO2 capture with 30 wt.% sodium carbonate solution is 1.36. With this ratio all the sodium carbonate in the solvent would have reacted with CO2 and formed sodium bicarbonate. The minimum limit is theoretical and can never be reached in

reality. Fig. 4 shows that with the chosen temperatures and pressures the minimum energy requirement of the stripper is 3:05 MJ=kgCO2 separated . To decrease the electricity loss in a power plant the possibility of using lower pressure in the CO2 stripper was also

Fig. 4 – Energy requirement of stripper ðMJ=kgCO2 separated Þ as function of slurry/gas ratio with 30 wt.% sodium carbonate solution at capture efficiency of 90%.

Fig. 5 – Heat requirement of the stripper as a function of CO2 capture efficiency.

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Table 2 – Effect of liquid concentration and gas and liquid temperatures at the inlet of the absorber on the CO2-capture efficiency and heat requirement of the stripper Absorber inlet gas temperature (8C) 45 45 45 45 45 45 55 45 70

Absorber inlet solvent temperature (8C)

Sodium carbonate concentration (w-% Na2CO3)

Solvent/ gas-ratio kg/kg

CO2-capture efficiency (%)

45 45 45 45 45 45 55 60 60

10 15 17 17 20 20 20 30 30

5 5 5 5.5 5 5.5 5 2.3 2.3

43 72 82 85 90 92 84 92 90

considered. With lower pressure in the stripper, the electricity loss in the steam turbine is lower but the energy needed for compression of CO2 will increase. In total, the electricity loss might be smaller (Oyenekan and Rochelle, 2006). In Fig. 5 the optimal capture efficiency as a function of stripper pressure is shown, and it can be seen that the lower temperature and pressure in the stripper affects the vapour-liquid-solidequilibria in the stripper so much that the total energy requirement actually increases with decreasing pressure for removal efficiencies above 75%. The minimum energy requirement with a stripper pressure of 1 bar is achieved with a CO2 capture efficiency around 70%. With a pressure of 2 bar, the minimum can be found at about 90% capture efficiency with a liquid/gas-ratio of 2.4. The minimum heat requirement is found to be about 3:2 MJ=kgCO2 separated but this value does depend on the slurry/gas-ratio chosen. In the model, the assumption of a sulphur-free flue gas is made to ease the modelling of the system. In reality, sulphur compounds present in the CO2 absorber will react quantitatively with the sodium chemicals producing sodium sulphite (Na2SO3) and sodium bisulphite (NaHSO3). This will increase the consumption of make-up carbonate, but does constitute a combined CO2 and SO2 removal system alleviating separate SO2 removal that may be needed for amine-based systems.

Table 3 – Operating conditions of CO2 capture plant Sodium carbonate concentration (wt.%) Solvent temperature at top of the absorber (8C) Liquid/gas ratio at the top of the absorber tower (kg/kg) CO2-capture efficiency (%) Flue gas temperature at inlet of absorber (8C) CO2-content of the flue gas at the inlet of absorber (mol.%) H2O-content of the flue gas at inlet of absorber (mol.%) Stripper pressure (bar) Lean CO2 loading of the solution ðmolNaHCO3 þHCO3  =molNa þ Þ Rich CO2 loading of the solution ðmolNaHCO3 þHCO3  =molNa þ Þ Heat requirement of the stripper ðMJ=kgCO2 separated Þ

30.3 60 2.3 90 70 13.5 7.8 2 0.29 0.83 3.22

Heat requirement (MJ=kgCO2 ) 7.4 4.5 3.9 3.8 3.4 3.5 3.9 3.2 3.2

The only solid phases taken into account in the simulations were sodium carbonate and sodium bicarbonate. In reality, the variety of the solid phases is large, and each of these phases is stable in a specific temperature, carbonate concentration, and bicarbonate concentration range (Ga¨rtner et al., 2004; Kobe and Sheehy, 1948; Waldeck et al., 1932, 1934; Hill and Bacon, 1927). In Table 3, a summary of the main operating conditions for the CO2 capture unit are shown. CO2 compression is part of the CO2 capture unit, and a simple model for compression of CO2 was also included. The CO2-water vapour leaving the stripper was cooled, and water separated before compression. Pure CO2 was then compressed to 128 bar by six adiabatic compressors with output pressures of 4, 8, 16, 32, 64 and 128 bar. All the compressors had an isentropic efficiency of 0.9 with intercooling to 25 8C. The compression power is 39 MW and power needed for cooling is 8 MW. The compression energy was compared with the model of Rao and Rubin (2006) which gives a compression energy of 40 MW.

3.1. Sodium carbonate systems compared to MEA capture systems Since the electricity demand for compression and cooling of CO2 for chemical absorption systems with the same stripper pressure would be the same, the main difference in energy requirement comes from the energy demand of the stripper. The energy requirement of the stripper in MEA-based CO2 capture systems is typically 3:9  4:3 MJ=kgCO2 separated with 30 wt.% solution (Desideri and Paolucci, 1999). The energy consumption found in this study with sodium carbonate is 3:22 MJ=kgCO2 separated which is much lower than the values for MEA. The main drawback with sodium carbonate is the low absorption rate compared to amines, leading to high absorption towers. To overcome the problem, rate-increasing additives will be needed (Harte et al., 1933; Comstock and Dodge, 1937; Knuutila et al., 2006). In the literature many materials have been reported to increase the absorption rate of carbonate systems, for example arsenous acid, formaldehyde, hypochloride, phenols, sucrose, dextrose, piperazine, diethanolamine, monoethanolamine, DIPA and piperazine (Tseng et al., 1988; Mahajani and Danckwerts, 1983; Cullinane and Rochelle, 2004; Sharma and Danckwerts, 1963; Martin and Killefer, 1937). Most of these, however, will affect the CO2 capture energy requirement negatively since they most of the

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Table 4 – Modelled power plants Plant

CP

CP + CO2

CHP-1

CHP-2

Plant type

Condensing

Condensing

CO2 capture Fuel input (MWth) Electricity output (MWe) District heat (MWth) Total efficiency (%)

No 1336 521 – 39

Yes 1336 404 – 30

Combined heat and power No 1336 360 810 88

Combined heat and power No 990 267 600 88

rated-increasing additives have higher heat of reaction than the carbonate. However some of these additives may also affect the equilibria which can give both a positive and negative effect. On the other hand, there are other advantages that may make sodium carbonate based systems feasible. Sodium carbonate solutions are non-hazardous, non-volatile and the corrosion rate is low. They are also non-fouling and do not degrade, apart from the reactions with SO2 and NOx. Sodium based chemicals are already used in power plants for SO2 removal from flue gases (FGD) and the possibility of combining CO2 and SO2 removal makes sodium chemicals very attractive as even though the reactions with SO2 and NOx will be non-reversible they will provide a cheap outlet for these contaminants. The price of sodium carbonate is also approximately 1/10 of the price of MEA (Abanades et al., 2004). Even though the price difference is high, the effect on total cost of CO2 capture is low, since the price of sorbent is less than 10% of the total annual costs of a capture system (Rao and Rubin, 2006). The energy requirement and investment cost covers approximately 75% of the total annual costs (Rao and Rubin, 2006), so to be competitive it is more important to have low energy requirement and low investment cost. Slurry-based sodium carbonate systems have been used in the pulp and paper industry for decades (Niemi, 2005), and the modeling shows that there is potential in sodium-based processes if the presence of solids is allowed. The presence of solids could give possibility to make process improvements, and more research is needed to find out the real potential of slurry-based systems.

4.

CO2-capture as part of power generation

The modelled systems plants were retrofits so the power plant is the same with or without CO2 capture. This means that the high pressure steam production of the boiler is constant in the condensing power plant and in the combined heat and power plant respectively, with and without CO2 capture. But the steam production in the boilers is different in the two plants because of the difference in main steam values as shown in Table 1. The fuel input to all modelled plants, except for plant CHP-2, is the same as shown in Table 4. A CO2 removal efficiency of 90% was chosen. Low pressure steam of 5 bar from the turbine was used as heat source for the CO2 stripper. Condensate returning to the power plant from the stripper was preheated and fed to the feed water tank. ‘‘Waste heat’’, e.g. water condenser energy after the stripper and the cooling energy of the CO2 compression, available from

CHP + CO2 Combined heat and power Yes 1336 288 600 66

the CO2 plant, was used in the power plant to preheat the feed water or/and produce district heat. Sea water was assumed to be available for cooling in the CO2 capture plant and in the power plant at a temperature of 20 8C. The main results and the power plants modelled are shown in Table 4.

4.1.

Condensing power plant with CO2 capture

When the CO2 capture plant was integrated with the condensing power plant, the efficiency of the plant decreased from 39% to 30% as shown in Table 5. Typically, with MEA-based CO2 capture processes, the power plant efficiency decreases by 11– 15 percentage points (Alstom Power, 2001; Desideri and Paolucci, 1999) The CO2 stripper causes an electricity loss of 70 MW and the compression and cooling 47 MW. Part of the waste heat was used to preheat the feed water to the power plant and with this the electricity output of the CP + CO2 plant was increased by approximately 13 MW. Since the stripper is the largest energy consumer, an increase in energy needed to regenerate the solution has a strong effect on the electricity output of the plant, as shown in Fig. 6. An increase in the energy demand from 3 MJ=kgCO2 to 4 MJ=kgCO2 would decrease the electricity output by 28 MW, leading to a total efficiency of 28%.

4.2.

CHP plant

The results for the CHP plant with CO2 capture at full district heat load are shown in Table 5. The CHP-1 plant has a maximum district heat production of 810 MWth. Adding CO2 capture will decrease the heat production by 26%, leading to a maximum district heat production of 600 MWth. The loss of electricity is 71 MWe. Of this electricity loss compression, and cooling comprise 47 MW. The behaviour of the system under different district heat loads is shown in Figs. 7 and 8. At low

Table 5 – Modelled power plants with and without CO2 capture at full load. CP Electricity output (MWe) District heat (MWth) Total efficiency (%LHV) Power plant + CO2 capture Turbine output (MWe) CO2 compression and cooling (MWe) Electricity output (MWe) Loss of electricity (MWe) District heat (MWth) Loss of District heat (MWth) Total efficiency (%)

521 – 39 CP + CO2 451 47 404 117 (23%) – – 30

CHP-1 360 810 88 CHP + CO2 335 47 288 71 (20%) 595 215 (26%) 66

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Fig. 6 – Electricity output as a function of stripper heat demand at constant CO2 capture efficiency.

149

Fig. 8 – Total efficiency and loss of electricity and district heat of CHP-1 and CHP + CO2 -plants as a function of district heat demand. Total efficiency is calculated with equation: (district heat production + electricity production)/fuel input.

district heat load (<107 MW) the district heat is almost totally produced with the waste heat from the CO2 plant and electricity production is constant. But since most of the steam in the power plant is used to produce electricity and not district heat the plant behaves more like a condensing power plant. Almost all the losses caused by the CO2 capture effects only the electricity production and the loss of electricity is around 100 MW. The CHP + CO2 plant achieves its maximum production of electricity and district heat at a district heat load of 600 MW and a higher district heat demand can not be satisfied. The electricity production is all the time lower than in the CHP-1 case and, depending on the heat load the loss of electricity is between 20% and 27%. The highest electricity decrease is found at the maximum production of the CHP + CO2 plant at 600 MWth. With the CHP + CO2 plant the district heat production is lower than in the CHP-1 plant. This means that there will be a decrease in district heat and in electricity output at full heat demand. The maximum district heat production of CHP-2 -plant is 600 MWth. The results are shown in Table 4 and Fig. 9. When CHP-2 and CHP + CO2 are compared, it is seen that the CHP + CO2 plant can satisfy the heat demand with 35% higher fuel input compared to the CHP-2 plant. In Fig. 9, it can also been seen that higher fuel input leads to an approximately 8% increase in electricity production. This is because of the increased mass flow in the steam turbine.

Percentage-wise the CO2 capture in power plants with the same fuel input (CP and CHP-1 plants) causes an equal decrease in total efficiency and in electricity output as shown in Table 5. If absolute values are considered in the combined heat and power plant, the loss of electricity at full district heat demand is 46 MWe less than in the condensing power plant. But one has to keep in mind that in the CHP + CO2 -plant the district heat production is 210 MW lower than in the CHP-1 plant. Based on the model of Bolland and Undrum (2003) the district heat loss of 210 MWth equals about 38 MW loss of electricity. This means that in the CHP-plants a part of the loss of electricity is shifted to a loss of thermal energy. The main difference between the plants stems from the fact that the energy efficiency of the CHP-plant is much higher than the efficiency of the condensing power plant. With the same CO2 capture efficiency the CHP plant produces much more energy. Since both plants have the same fuel feed and CO2 capture efficiency, the captured CO2 is in both plants around 108 kg/s leading to energy production (electricity + district heat) to captured CO2 –ratio of 3:8 MJe =kgCO2 separated in condensing

Fig. 7 – Electricity and heat outputs of CHP-1 and CHP + CO2 -plants as a function of district heat demand.

Fig. 9 – Electricity and heat production of CHP-2 and CHP + CO2 plants as a function of district heat demand.

4.3. Comparison between condensing power plant and combined heat and power plant

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plant. In CHP-plant the ratio is 8:4 MJthþe =kgCO2 separated . This indicates clearly that CHP-plants would be more attractive for CO2 capture than condensing plants. Also in the CHP-plants the need for low temperature heat is higher than in condensing plants and all the waste heat above 70 8C can be used in district heat production. On the other hand, in the condensing plant part of the waste heat above a temperature of 20 8C can be used to heat the feed water in the power plant, whereas in a CHPplant, when running at full load, there is no need for waste heat below a temperature of 70 8C. In CHP-plants the energy loss caused by CO2 capture can be divided between electricity and district heat production. The CHP-1 –plant and the CHP + CO2 –plant have the same constant fuel input and the CHP-1 plant produces at full load 360 MW electricity and 810 MW district heat. If electricity is more valuable than district heat, the energy losses caused by CO2 capture can be distributed in a way that no electricity is lost. In that case the CHP + CO2 –plant still produces 360 MW of electricity, but only 220 MW of district heat, as can be seen from Fig. 7. So the loss of electricity is zero but the loss of district heat is 590 MW. If district heat is more valuable the district heat production of 810 MW can be achieved by adding an auxiliary boiler which produces low pressure steam just for district heat production. Still using the same total input of fuel, part of the fuel input must then be used to produce low pressure steam. This will decrease the amount of high pressure steam and thereby electricity production, but the district heat demand can be satisfied. As shown earlier, with no changes to the plant construction, the maximum district heat available, when CO2 capture is introduced, will be 600 MW. Both the electricity and district heat demands can be satisfied, but then the fuel input needs to be increased. Using either CHP plant as base case and keeping the inherent production ratio between electricity and heat constant, the fuel input must be raised by 35% to satisfy the district heat demand. Expanding the plant in this way gives a potential electricity production increase of 8% as shown in Fig. 9. The fuel input increase can be reduced by converting electricity production to heat, using the high pressure steam for district heating.

5.

Conclusions

In this work the feasibility of a CO2-capture system based on a sodium carbonate-bicarbonate slurry and its integration with a power plant was studied. The results were compared to MEA-based capture systems. The integration of a CO2 capture plant with coal-fired power plants was studied with two power plant types: condensing power plant and combined heat and power plant. Being environmentally friendly, sodium carbonate would be an interesting chemical for CO2 capture. Based on the calculations done in this study, it lowers the energy requirement to about 3.2 MJ/kg CO2 captured. The main drawback will be the slow transfer kinetics, leading to the need for a larger absorption tower. Using the slurry sodium carbonate process for CO2 capture from a condensing power plant, the loss in electricity production was found to be 9 percentage points, lowering

the efficiency from 39% to 30%.Typically with MEA-based CO2 capture processes the power plant efficiency decreases from 11–15 percentage points (Alstom Power, 2001; Desideri and Paolucci, 1999). CHP-plants are attractive for CO2 capture because they have a high total energy efficiency and the losses caused by CO2 capture can be divided between electricity and district heat production during operation according to the needs for the two commodities. In this study the aim has been to maintain a high district heat production, and in this case CO2 capture leads to a decrease of electricity production of 20% (from 360 MW to 288 MW) and a 26% loss of district heat (from 810 MW to 600 MW). These losses decrease the total energy efficiency of the plant from 88% to 66%. To satisfy both the district heat demand and the electricity production target, the fuel input needs to be increase by about 35% using a constant ratio between electricity and heat production. Using ‘‘waste heat’’ available in the CO2 capture plant has only a minor effect on the power plant energy production. In the case of a condensing plant the use of waste heat for preheating increases the total efficiency from 29.5% to 30.0%. In a combined heat and power plant the increase in efficiency is from 65% to 66%.

Acknowledgements Financial support was provided by Metso Power Oy, National Technology Agency of Finland and Pohjolan Voima Oy.

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