Scholarly article on topic 'Process integration analysis of a brown coal-fired power station with CO2 capture and storage and lignite drying'

Process integration analysis of a brown coal-fired power station with CO2 capture and storage and lignite drying Academic research paper on "Chemical engineering"

CC BY-NC-ND
0
0
Share paper
Academic journal
Energy Procedia
OECD Field of science
Keywords
{"Carbon Capture and Storage" / Pinch / Integration / "Energy Penalty"}

Abstract of research paper on Chemical engineering, author of scientific article — Trent Harkin, Andrew Hoadley, Barry Hooper

Abstract Integration of CO2 capture and storage (CCS) into existing and new coal fired power stations is seen as a way of significantly reducing the carbon emissions from stationary sources. A significant proportion of the estimated cost of CCS for post-combustion capture from coal-fired power stations is due to the additional energy expended to capture the CO2 and compress it for transport and storage. The additional energy either reduces the power plant output or creates additional CO2 which will increase the CCS requirements. Therefore, reductions in the overall energy penalty of CCS by improving the efficiency of both the carbon capture processes and the integration of the capture technology with the power plant can lead to significant reductions in the cost of CCS. Pre-drying lignite using low temperature heat sources enables power stations to increase their energy efficiency by the use of low grade heat, providing energy that is less carbon intensive and potentially reducing the cost of electricity production. This work reviews the current thinking for integration of CO2 capture plants using solvent absorption for postcombustion coal fired power stations. It also reviews the integration potential of brown coal dewatering processes to a power plant with CCS. The review uses as a basis a 200MWe(nominal) train of an existing pulverised brown coal fired power plant using heat and process integration techniques such as heat pinch analysis to determine the potential for reductions in capture cost by minimising the energy penalty associated with the addition of the CCS. The study shows that the energy penalty reduces from 39% for a CCS plant with no heat integration to 24% for a plant with effective heat integration. The energy penalty can be further reduced by the addition of pre-drying of the coal. This study shows there is potential to reduce the energy penalty associated with the addition of CCS, however the heat exchanger network and the required modifications to the existing equipment have not been determined and further work identifying these issues is required and these will have a large impact into whether the reductions suggested by this study can be economically implemented.

Academic research paper on topic "Process integration analysis of a brown coal-fired power station with CO2 capture and storage and lignite drying"

Available online at www.sciencedirect.com

ScienceDirect p^JJ*»

Energy Procedia 1 (2009) 3¡017-3825

www.elsevier.com/locate/procedia

GHGT-9

Process integration analysis of a brown coal-fired power station with CO2 capture and storage and lignite drying

Trent Harkina,b*, Andrew Hoadleyb, Barry Hoopera

aCooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) bDepartment of Chemical Engineering, Monash University, Clayton, VIC 3800, Australia Campus

Abstract

Integration of CO2 capture and storage (CCS) into existing and new coal fired power stations is seen as a way of significantly reducing the carbon emissions from stationary sources. A significant proportion of the estimated cost of CCS for post-combustion capture from coal-fired power stations is due to the additional energy expended to capture the CO2 and compress it for transport and storage. The additional energy either reduces the power plant output or creates additional CO2 which will increase the CCS requirements. Therefore, reductions in the overall energy penalty of CCS by improving the efficiency of both the carbon capture processes and the integration of the capture technology with the power plant can lead to significant reductions in the cost of CCS. Pre-drying lignite using low temperature heat sources enables power stations to increase their energy efficiency by the use of low grade heat, providing energy that is less carbon intensive and potentially reducing the cost of electricity production.

This work reviews the current thinking for integration of CO2 capture plants using solvent absorption for postcombustion coal fired power stations. It also reviews the integration potential of brown coal dewatering processes to a power plant with CCS. The review uses as a basis a 211MWe(nominal) train of an existing pulverised brown coal fired power plant using heat and process integration techniques such as heat pinch analysis to determine the potential for reductions in capture cost by minimising the energy penalty associated with the addition of the CCS.

The study shows that the energy penalty reduces from 39% for a CCS plant with no heat integration to 24% for a plant with effective heat integration. The energy penalty can be further reduced by the addition of pre-drying of the coal. This study shows there is potential to reduce the energy penalty associated with the addition of CCS, however the heat exchanger network and the required modifications to the existing equipment have not been determined and further work identifying these issues is required and these will have a large impact into whether the reductions suggested by this study can be economically implemented. © 2009 Elsevier Ltd. All rights reserved.

"Keywords: Carbon Capture and Storage; Pinch; Integration; Energy Penalty;"

* Corresponding author. Tel.: +61-3-8344-5148; fax: +61-3-9347-7438. E-mail address: tharkin@co2crc.com.au

doi:10.1016/j.egypro.2009.02.183

1. Introduction

The addition of Carbon Dioxide (CO2) capture and storage (CCS) to existing or new coal fired power stations is seen as a way of significantly reducing the carbon emissions from stationary sources. CCS for traditional pulverised coal power plants involves the addition of equipment to capture the CO2 from the mixture of flue gases, compressing the separated CO2 into a supercritical fluid form and then storing it in geological structures. A significant proportion of the estimated cost of CCS for post-combustion capture from coal-fired power stations is due to the additional energy expended to capture the CO2 and compress it for transport and storage.

This paper reviews the current thinking for integration of CO2 capture plants using solvent absorption for postcombustion coal fired power stations. The study uses a brown coal fired pulverised coal power station as the basis for the work and determines the reduction in the electrical output of the power station due to the addition of a CCS unit for a plant without heat integration and then uses pinch analysis to minimise the energy penalty by maximising the heat integration. Lignite dewatering has been demonstrated as a method of increasing the efficiency of brown coal fired power plants, however the impact of adding both CCS and pre-drying from an overall heat integration perspective has not to the authors knowledge previously been studied, a pinch analysis will be used to determine whether coal dewatering processes remain beneficial in light of a fully heat integrated power plant with CCS.

2. Background

This study is based on adding CCS to an existing 200MWe(nominal) / 220MWe(peaking) subcritical pulverised brown coal fired power plant that operates with a HP and LP turbine and no steam reheat. Steam is currently extracted from the exhaust of the high pressure turbine for deaeration and is also extracted from two points on the LP turbine for heating the boiler feedwater upstream of the deaerator. The raw brown coal has 60wt% moisture and is currently dried in the pulverising mills using flue gases extracted from the combustion chamber. The flue gas composition on a dry basis is detailed in table 1 and produces approximately 300tonnes/hr of CO2.

Table 1 - Power Plant Flue Gas Composition

Component Value Rotary Air Heater Inlet

Oxygen vol% 4.55

Carbon Dioxide vol% 15.39

Carbon Monoxide PPm 99

Sulphur Dioxide PPm 214

Sulphur Trioxide PPm 0.5

Nitrogen Monoxide PPm 1749

Nitrogen Dioxide PPm 1.9

Average Duct Temperature °C 362

2.1. Carbon capture using solvent absorption

The most widely practiced method of extracting CO2 from a mixture of gases is using solvent absorption technology. For post combustion capture where the partial pressure of CO2 is <l bar chemical absorption is the preferred solvent technology with thermal regeneration of the solvent. MEA (monoethanolamine) is considered to be the benchmark of the chemical solvent systems by which all other solvents are compared and will therefore be the basis of this work. This paper will examine the benefits of heat integration of a simple MEA solvent system with the power plant, no attempt at this stage of the work has been made to optimise the solvent or the solvent process to provide an optimally integrated process.

2.2. Energy penalty of carbon capture and storage

CCS equipment creates an 'Energy Penalty' as it reduces the efficiency of the power plant. All the methods to capture CO2 from the flue gases of power plants require significant amount of energy to operate; Solvent absorption requires energy for heat of solvent regeneration and solvent pumping, membrane systems and pressure/vacuum swing adsorption systems require energy to provide pressure differentials, temperature swing adsorption requires energy for regeneration and cryogenic separation requires energy for refrigeration. Further energy is required in all systems to compress the CO2 into a supercritical fluid and transport it to the injection site.

For solvent capture of CO2 the majority of the energy is to provide the heat for the reboiler to regenerate the solvent. The heat is generally provided by extracting steam from the LP turbine, this reduces the electricity produced from the power plant, furthermore, electricity is required to operate the solvent pumps, compressors and increased cooling water flowrate or air coolers. The efficiency of a power plant can be reduced by approximately 30 - 40% by the addition of CCS [1].

Many authors have investigated how to minimise the energy penalty associated with CCS, however none appear to use pinch analysis to minimise the energy penalty. Aroonwilas [2] and Romeo [3] both state that the optimal location to extract power for a solvent system is from the LP turbine at the appropriate pressure to provide steam at lowest quality that satisfies the solvent system reboiler requirements. Bozzutto [4] uses an auxiliary turbine with steam from the IP/LP crossover to provide the steam at the required quality for the solvent reboiler, this method was considered by Zachary [5] to provide the most efficient method of providing steam at the correct quality of steam compared to using throttling valves, floating pressure or clutch arrangements for dealing with steam extracted between the IP/LP turbines. Mimura [6], Desederi [7] and Romeo [3] all suggest variations in utilising some of the available heat from the CO2 compressor intercoolers and stripper condenser to heat the boiler feed water. An IEA GHG report [8] also produce hot water for coal pre-drying using waste heat in the flue gas, the stripper condenser and the CO2 compressor intercoolers.

2.3. Process integration - pinch analysis

Pinch analysis is the systematic analysis of the energy flow of a process, it is based on the first and second laws of thermodynamics. The first law providing the conservation of energy through a heat exchanger and the second law determining the direction of heat flow. A pinch analysis will determine the minimum energy requirements of a process by ensuring that the flow of energy from the hot streams in a process to the cold streams is maximised.

Linhoff [9] used pinch analysis to improve the efficiency of a power plant reducing the fuel use by 2.8% by determining the optimum amount of steam extracted from the turbines for a given number of boiler feedwater heaters and utilising topping and intermediate desuperheaters to achieve the required heat transfer. With the addition of CCS to a power plant, there are additional hot streams; the flue gas, which will need to be cooled down for FGD and CO2 capture, the stripper condenser and the CO2 compressor intercoolers, there are also additional cold streams; the stripper reboiler and the regeneration for the CO2 dehydration process. For this study targets for the amount of electricity that can be generated using a constant rate of coal will be determined. In the case of a power plant with CCS, the targeting process will identify how much steam needs to be extracted from the power cycle to provide sufficient heat to satisfy the CCS equipment. This paper is primarily based on establishing targets, determining the heat exchange network to meet those targets will be considered later. It should be noted that to meet improved energy targets usually requires additional capital and process complexity and there is normally a trade-off necessary between capital and operating costs.

3. Process flowsheet development

A model of the base power plant has been developed in Aspen Plus® and validated against a Gatecycle® model of the same plant. The Aspen model includes the coal drying in the pulverizing mill, coal combustion, flue gas heat recovery and simulation of the steam cycle. The flue gas from the plant under investigation enters the rotary air

preheater at 362°C and is cooled down to 272°C at the precipitator inlet. This is assuming that there is no air leakage in rotary air heaters. In actual operation the air leakage is likely to be around 6%, however this is ignored in this work as the process integration arrangements may determine that the air preheat is either unnecessary or is better performed with other streams. The air leakage has a negative impact on the carbon capture process as the oxygen concentration is increased and the CO2 partial pressure is reduced, reducing the efficiency of the absorption as well as increasing the oxygen degradation potential.

MEA is intolerant to a number of contaminants in the flue gas. MEA forms heat stable salts and formates with oxygen and carbon monoxide in the flue gas however vendors provide inhibited oxygen tolerant solvents based on amines such as Fluor's Econamine-FG. Nitrogen dioxide will degrade MEA, however as the NO2 is typically less than 10% of the NOx in the flue gas, it is anticipated [10] that in Australia there is no financial incentive to install NOx reduction beyond low NOx burners. Amine solvents react with SOx to form heat stable salts that need to be removed and decomposed in a side stream reclaimer. It is generally regarded that SOx levels should be lowered to less than 10ppmv to avoid excessive solvent degradation [11-13], however there is an economic trade-off between increased capital costs for the flue gas desulphurisation (FGD) and decreasing operating costs of the solvent system. The economic optimum level of FGD will be site specific depending on factors like the fuel burnt, the solvent selected and the costs for spent solvent disposal. Particulate matter in the flue gas will cause operational issues including foaming, erosion, solvent degradation and equipment fouling in all solvents including MEA, therefore the particulate matter will need to be low prior to the CO2 capture plant.

The carbon capture plant and associated equipment will be assumed to be located downstream of the electrostatic precipitator and the induced draft fan to minimise effects of particulate matter. As the flue gas has >200ppmv of SOx, it is assumed in this study that FGD will be required upstream of the solvent plant, however due to the low level of NO2 (<10ppm) in the flue gas, no additional equipment is considered for NOx removal.

3.1. Flue gas desulphurisation

Flue gas desulphurisation can be achieved using either wet or dry systems. Dave [10] suggests that for Australian black coal with less than 250ppm of SOx that dry sorbent injection into the furnace would be sufficient to lower the SOx to an economically attractive level. However, wet FGD using lime or limestone has dominated over the other technologies and will be considered as the standard for this work. There are no heating/cooling requirements for the FGD but a nominal electrical requirement for the fans and pumps of 3MW has been assumed, this has been prorated from a similar unit designed in an IEA report [8].

3.2. CO2 capture

The flue gas is cooled to 40°C before it enters the solvent absorption column, all cooling for the new processes are at 40°C to enable the use of air cooling. At least 90% of the CO2 is captured in the CO2 capture plant producing a high purity (>99%) CO2 stream after dehydration. An MEA plant has been modelled using AspenPlus®, the absorber and stripper have been modelled using RadFrac columns using rate based calculation methods. The physical properties, equilibrium data and reaction kinetics are based on a 30wt% MEA model developed by Aspen for CO2 capture [14]. The stripper is operated at 1.8bar to limit the MEA temperature to less than 122° to avoid thermal degradation. The absorber is operated at 1bar as increasing the pressure to improve the absorption is not justified compared to the additional energy required to provide the elevated pressures [7]. The reboiler energy required to capture the CO2 from this simulation is 4.5GJ/tCO2 captured, which is similar to models reported by Desederi [7] which obtained heating requirements of between 3.7 and 5.7GJ/tCO2 for similar flue gas CO2 concentrations. However this is significantly higher than the leading solvent technologies available, which require between 2.7 and 3.3 GJ/tCO2 [1]. The lower energy requirements are for improved solvents and optimised processes. This study prorates the heating/cooling curves of the stripper reboiler and condenser and the lean/rich heat exchangers predicted by the model to a reboiler duty of 3GJ/tCO2 to provide results comparable to the leading solvent technologies.

3.3. CO2 compression and dehydration

The CO2 will be compressed to 100bar in a four stage compressor with intercooling and water removal. The first three stages below the supercritical point of CO2 have an assumed efficiency of 85% while the last stage has an efficiency of 75%. Dehydration will occur after the second stage of compression at around 13.5bar, the location of the dehydration unit is an economical trade-off between the ease of dehydration and the cost of the equipment as the pressure increases in the compression train. For this study it has been assumed that glycol dehydration will be used, however it could be equally assumed that the dehydration can be achieved using molecular sieve adsorption with thermal regeneration. The dehydration system uses 25L/kgH2O of 99.8wt% triethyleneglycol (TEG) regenerated in a vacuum stripper with a reboiler temperature of 200°C. The dehydration package has not been included for potential heat integration with the process at this stage, but the effect would be minimal due to the small duties involved in the process. The auxiliary power for the TEG package is less than 200kW and the reboiler requirement is 1.5MW which is assumed to be provided by an electrical heater. Integration of the glycol package will be considered in future work.

3.4. Lignite pre- drying

Coal dewatering using low quality heat can increase the efficiency of a power plant and has been the focus of much work and commercial processes are now being demonstrated. The drying needs to be performed at low temperatures (<180°C) to avoid the loss of volatile components that are required for good coal combustion. The USA EPRI are sponsoring R&D into a dry lignite system that uses hot Water at 85°C in coils within a bed of coal fluidised by air fed at 65°C, where the RWE system operates hotter and uses a bed fluidised by steam with internal heating by condensing steam in a submerged coil [8]. A lot of research has also been performed looking at thermal-mechanical dewatering where the coal is pressed or centrifuged after heating, however these systems appear less advanced than the pure thermal systems.

For this study when the effect of coal drying is reviewed it will be assumed that the coal will be heated from ambient temperature, assumed to be 25°C up to at least 100°C to dry the coal to 45wt%. The net steam generated by the dewatering process will also be assumed to be available for heating requirements if required and the coal will be cooled down to 60°C before being fed to the boiler to allow for safe storage of the coal if required.

4. Results

Five cases have been considered in this study, in each case the amount of raw coal fed to the plant is maintained, and for the first four cases the amount and quality of steam produced from the boiler remains constant. The heat and power requirements for the FGD and CCS plant are provided by the heat generated within the power plant rather than importing heat or power from an external source, the results are displayed in Table 2.

1. Base Case - This is the existing plant with no FGD or carbon capture plant.

2. CCS - This case includes CCS and FGD with no heat integration.

3. Integrated CCS - This case includes CCS and FGD with maximum heat integration.

4. CCS & Drying - Coal dewatering and CCS with maximum heat integration.

5. CCS/Drying/Increased Steam - This case looks at utilising the additional heat content in the pre-dried coal to produce additional steam to utilise in the plant for additional heat and power.

5. Discussion

As this analysis is based on a potential retrofit of an existing power plant rather than a new build power plant, the flue gas has been considered as a hot stream as the heat that can be provided by the flue gas is relatively fixed, whereas the steam extracted from the turbines is used as a utility to provide more or less for the process, which will in turn affect the amount of electricity produced by the generator. For a new build design, the process may be different as the turbine and boiler could be sized to meet the heat and power requirements of the plant with CCS in mind.

Table 2 - Power plant performance for each case

1 2 3 4 5

Moisture Content (Inlet to mill) wt% 60.8 60.8 60.8 45 45

Steam Production kg/s 208 208 208 208 248

Flue Gas Temperature (Exiting Economiser) °C 362 362 362 416 189

Steam Extraction

HP Exhaust (177°C) kg/s 10.9 111.6 54 42.1 53

LP Bleed 1 (110°C) kg/s 11.4 11.4 0 7.1 6.8

LP Bleed 2 (84°C) kg/s 8.7 8.7 0 0 0

Electricity Produced MW 220 172 205 208 203

Plant Auxiliary Power MW 13.8 22.1 22.1 22.1 22.8

CO2 Compression Power MW - 24.8 24.8 25.2 1.7*

Net Electrical Power MW 206.2 125 158 161 178

Net Cycle HHV Efficiency % 23.01 14 18 18 20

Reduction in Net Cycle HHV Efficiency % Points - 9 5 5 3

Energy Penalty % - 39 24 22 14

CO2 Emissions kt/y 2641 263 263 216 216

CO2 Emissions t/MWh 1.46 0.24 0.19 0.15 0.14

* The CO2 compression power in this case is offset by the addition of an auxiliary steam turbine.

5.1. Base plant - case 1

The base case is based on a representation of an existing plant, therefore the extraction steam is included in the hot composite curves (Figure 1) and the hot and cold curves for this case are balanced. The base case is a threshold problem from a pinch point analysis perspective, which means that by reducing the ATmin below a threshold ATmin there is no change in utility requirements. The threshold ATmin for the base case is 30°C, therefore between 0 and 30°C, with a fixed amount of extraction steam, there is no change in the fuel/cooling water requirements of the plant. With a global 30°C ATmin the pinch point is located at the condenser. If the cooling water ATmin can be considered less than the other streams, which in reality the condenser will operate with a temperature difference of less than 10°C, then the pinch point becomes located at the lowest extraction steam temperature.

The extraction steam will be considered as a hot utility for the further analysis and as such the amount of steam extracted from the turbine will be varied so that the heating requirements of the power plant including CCS will be met. For this study the extraction steam has been assumed to be cooled down to the condenser temperature and then returned to the condensate extraction pumps with the rest of the boiler feedwater, this is to avoid the cold composite curve changing when targeting the required amount of extraction steam. This will provide extraction steam turbines marginally higher than returning the condensate without subcooling as the approach temperature for direct contact exchangers is 0°C compared to the global ATmin used in this study.

5.2. Non-integrated CCS plant - case 2

This case is the existing power plant with FGD and CCS attached to the plant without any regards to potential heat integration. As the MEA reboiler temperature is 120°C the next available steam extraction point available with a temperature greater and without turbine modifications is the HP exhaust steam which is at 177°C. The reboiler therefore requires 101kg/s of steam which is extracted from the HP exhaust as well as the existing steam extracted for the dearator and boiler feed water heaters. The additional extraction steam halves the flow of steam through the LP turbine and reduces the amount of gross electricity output to 172MW provided the efficiency of the LP turbine remains constant. The net electrical power produced is reduced further by the increase in auxiliary power and the

CO2 compression to 125MW providing an energy penalty of 39%. It is anticipated that in addition to the new CCS equipment, at the rate of extraction steam required, modifications would be required to the LP turbine to enable it to maintain the existing efficiency.

5.3. Integrated CCS plant - case 3

For case 3 all hot and cold streams within the power plant and the CCS unit have been considered except the hot gas used in the pulverising mill, as this is seen as an essential requirement of the existing boiler. The composite curves for the plant with CCS are shown in figure 2 for a ATmin of 3°C. The pinch point changes from the condenser for the base case to a hot stream temperature of 116.6°C. The effect of altering the ATmin on the amount of extraction steam required and the amount of gross electricity that is produced is shown in table 3. There is less than 1% reduction in power generated for ATmin changes between 3°C and 10°C, but this increases to greater than 6% for a minimum temperature difference of 20°C. For this study a very optimistic ATmin of 3°C is used for all cases. In reality the economic ATmin for each type of process will be different, flue gas is likely to require a ATmin of at least 20°C, whilst condensing steam may be between 5 and 10°C and drain coolers less than 3°C. This will be incorporated into future work with variable minimum temperature driving forces allowed for different processes.

Table 3 - Effect of ATmn on the required extraction steam flow and gross electricity production

ATmin(°C) HP Steam (177°C) LP Steam 1 (110°C) LP Steam 2 (84°C) Gross Electricity (MW)

3 54 0 0 205

5 55 0 0 204

10 53 7 0 203

15 68 4 0 196

20 81 0 0 192

The integrated CCS plant has an energy penalty of 24%, which is a 15% point improvement on the non-integrated case. Although this study is primarily intended as a targeting exercise, the heat exchanger network for this design is likely to involve heat exchange between the streams detailed below and is therefore likely to involve extensive modifications to the existing plant and require novel heat exchangers to achieve the target that has been determined;

• Solvent stripper reboiler and flue gas / steam,

• Air preheat and CO2 compressor intercoolers / flue gas / steam,

• Boiler feed water and CO2 compressor intercoolers / flue gas / steam,

• Deaerator and flue gas / steam.

5.4. CCS & drying - case 4

The fourth case involves pre-drying the coal, the composite curves are shown in Figure 3. The pre-drying case results in a slightly improved energy penalty in comparison to the integrated CCS case without pre-drying by 2%. With coal pre-drying included the air preheat is removed entirely to reduce the maximum combustion temperature. The theoretical flue gas temperature with no air preheat still increases the theoretical flame temperature by just over 110°C, therefore the level of pre-drying that is able to be achieved is likely to be limited by the constraints of the existing boiler.

There are two pinch points for this case at hot stream temperatures of 104°C and 120°C. The increased efficiency can be attributed to the decreased process pinch point temperature (104°C) which can be attributed to the increased temperature of the flue gas and the removal of the air- preheat. The introduction of a second pinch point (120°C) is a result of some low pressure extraction steam being able to be used rather than requiring entirely HP exhaust steam. The air preheat in a power plant is used to increase the thermal efficiency of a plant by increasing

the energy difference between the combustion temperature and the flue gas exhaust temperature. When an MEA CCS plant is added to a power plant, the flue gas is cooled down much further than a power plant without CCS or FGD, therefore the impact of air preheating becomes less significant on the thermal efficiency of a plant. Therefore it is envisaged that removing the air preheat in a fully integrated power plant with CCS may increase the power plant efficiency. The cold composite curve will have less duty with the removal of the air-preheat, however this will be traded against a shallower hot composite curve. From this study where pre-drying of the coal is used, removal of the air preheat from the plant to allow increased levels of drying up to the boiler temperature limitations is considered to be beneficial.

1200 1000 _ 800 600 400 200 0

Figure 1 - Base plant

800 Q (MW)

Figure 2 - Balanced composite curves - case 3

1600 1400 1200 1000 £ 800 600 400 200

Figure 3 - Balanced composite curves - case 4

Figure 4 - Balanced composite curves - case 5

Q (MW)

5.5. CCS / drying / increased steam production - case 5

The fifth case considers that the coal is pre-dried as with case 4, however the increased energy from the boiler in this case is used to generate additional steam. It is assumed that the existing turbine is limited to the current steam production and that any additional steam that is produced is utilised in a new auxiliary turbine that is used to offset the power of the CO2 compressors and provide steam at the desired level to operate the solvent stripper reboiler. There is sufficient heat in the boiler flue gas to provide at least 20% additional steam, which will provide enough energy in the auxiliary turbine to offset the CO2 compression power. The composite curves for this case are shown in figure 4. The energy penalty for this case reduces to 14%, however this involves the addition of an auxiliary turbine in addition to the coal pre-drying equipment and the CCS facilities and requires maximum heat integration, therefore it is likely to have the highest capital costs of all the cases. This case is also subject to being able to increase the maximum temperature in the boiler and increase the amount of steam produced in the boiler.

6. Conclusion

Using pinch analysis there is a potential to reduce the energy penalty that occurs as a result of adding CCS to a power plant. By maximising heat integration the energy penalty from adding CCS reduces from 39% to 24% compared to having a completely stand alone CCS plant with no heat integration. This could be improved further by pre-drying the coal, generating extra steam and maximizing the heat integration which reduces the energy penalty to 14%.

Whilst the targeting work completed in this study shows there is a potential to reduce the energy penalty, more work is required to determine the heat exchanger network that is required to achieve these targets and to understand the limitations of the existing plant. Plant limitations in terms of existing equipment and plot space may constrain the achievable reductions that are suggested by this study. The outcomes from further work into these limitations and capital cost estimates to reach these targets will determine whether the targets identified are economically viable.

Further work is planned to perform a retrofit analysis to determine the most economical heat integration changes that improve the energy penalty, to investigate varying the solvent or solvent process and the potential for heat integration of other capture processes. The heat integration techniques applied in this study to an existing plant could equally be applied to new build plants and may in fact provide a greater opportunity for reductions in the energy penalty as new build plants are not constrained to many of the same limitations as a retrofit design.

7. Acknowledgements

This work has been conducted with support from the CO2CRC, International Power and the Victorian Government ETIS Brown Coal R&D Program.

8. References

[1] IPCC Special Report on Carbon Dioxide Capture and Storage. Intergovernmental Panel on Climate Change (2005)

[2] Aroonwilas A, Veawab A. Integration of CO2 capture unit using single- and blended-amines into supercritical coal-fired power plants: Implications for emission and energy management. Int. J. of Greenhouse Gas Control (2007) 1(2):143-50.

[3] Romeo LM, Bolea I, Escosa JM. Integration of power plant and amine scrubbing to reduce CO2 capture costs. App. Ther. Eng. (2008) 28(8-9):1039-46.

[4] Bozzuto CR, Nsakala N, Lilijedahl GN, Palkes M, Marion JL. Engineering Feasibility of CO2 capture on an exisiting US Coal-fired power plant. Final report for First national conference on carbon sequestration. (2001).

[5] Zachary J. Options for reducing a coal-fired power plant's carbon footprint: Part I. Power (2008) June 2008:5.

[6] Mimura T, Simayoshi H, Suda T, Iijima M, Mituoka S. Development of energy saving technology for flue gas carbon dioxide recovery in power plant by chemical absorption method and steam system. Energ Convers Manage (1997) 38 (SUPPL. 1).

[7] Desideri U, Paolucci A. Performance modelling of a carbon dioxide removal system for power plants. Energ Convers Manage (1999) 40(18):1899-915.

[8] IEA-GHG. CO2 Capture in Low Rank Coal Power Plants. IEA Greenhouse Gas R&D Programme (2006).

[9] Linnhoff B, Alanis FJ. A systems approach based on pinch technology to commercial power station design. The Winter Annual Meeting of ASME. San francisco, California. (1989)

[10] Dave NC, Duffy GJ, Edwards JH, Lowe A. Economic evaluation of capture and sequestration of CO2 from australian black coal-fired power stations. Fifth international conference greenhouse gas control technologies: GHGT-5, Cairns: 2001. (2001) p. 173 - 8.

[11] Rao AB, Rubin ES. A technical, economic, and environmental assessment of amine-based CO2 capture technology for power plant greenhouse gas control. Environ Sci Technol (2002) 36(20):4467-75.

[12] Leci CL. Financial implications on power generation costs resulting from the parasitic effect of CO2 capture using liquid scrubbing technology from power station flue gases. Energ Convers Manage (1996) 37(6-8):915-21.

[13] Davidson RM. Post combustion carbon capture from coal fired plants - solvent scrubbing. IEA Clean Coal Centre Report (2007) CCC/125.

[14] Aspen technology Inc. Rate-Based Model of the CO2 Capture Process by MEA using Aspen Plus (2008).