Available online at www.sciencedirect.com Applied Thermal Engineering 28 (2008) 1039–1046 www.elsevier.com/locate/apthermeng Integration of power plant and amine scrubbing to reduce CO2 capture costs Luis M. Romeo *, Irene Bolea, Jesús M. Escosa Centro de Investigación de Recursos y Consumos Energéticos (CIRCE), Universidad de Zaragoza, Centro Politécnico Superior, Marı́a de Luna, 3, 50018 Zaragoza, Spain Received 6 November 2006; accepted 21 June 2007 Available online 13 July 2007 Abstract Due to security, sustainability of supply, strategic and energetic dependence reasons, it is well accepted the necessity to continue using coal as main fuel for producing electricity from power plants. In order to reduce CO2 concentrations in the atmosphere, it is essential to develop carbon capture and storage technologies that lead to zero emissions fossil fuels power plants. Absorption by chemical solvents combined with CO2 long-term storage appears to offer interesting and commercial applicable CO2 capture technology. However, the high regeneration energy requirements make necessary a process optimization in large-scale power plants. Although actual CO2 capture cost remains around 55 €/ton CO2, the target is to maintain this cost below 25 €/ton CO2. This paper proposes different possibilities to overcome the energy requirements by means of amine scrubbing integration into a commercial power plant, and presents a technical and economical analysis of the performance of these approaches. Although some schemes show small efficiency penalties, it becomes essential to calculate specific cost per ton CO2, the main aim is to chose the proper configuration to implement large-scale cost-effective schemes that leads to CO2 capture demonstration projects. Ó 2007 Elsevier Ltd. All rights reserved. Keywords: MEA scrubbing; CO2 capture; Power plant; Energy integration; Capture costs 1. Introduction Today, fossil fuels produce over 60% of the world’s electricity. Coal is the most abundant fossil fuel, playing an essential role as fuel for power plant operation and contributing to about 38% of the total electricity generation [1]. For the coming decades it is expected to continue as a prominent fuel for electricity production [2]. However, CO2 has the greatest negative impact on the observed greenhouse effect, causing approximately 55% of the global warming [3]. As a consequence, European National Allocation Plans have considered an important reduction in the utilization of coal, especially in power plants. In order to maintain the increasing rate of electricity production based on coal is necessary the development of * Corresponding author. Tel.: +34 976 762570; fax: +34 976 732078. E-mail address: [email protected] (L.M. Romeo). 1359-4311/$ - see front matter Ó 2007 Elsevier Ltd. All rights reserved. doi:10.1016/j.applthermaleng.2007.06.036 clean fossil fuels power plants. The development of zero and near zero emissions power plant technologies is gaining importance worldwide and large demonstration projects are expected in the coming decade for new plants [3]. But if drastic reductions are requested in the medium term, it is also necessary to support and study technologies that could be able to capture any percentage of CO2 from existing power plants. In a post-combustion capture, CO2 is directly isolated from a stream of flue gases once combustion is completed; then, a recovery process is applied to the CO2 captured. Among those methods, CO2 absorption by amine derived chemical solvents appears to offer an interesting and practical alternative from combustion flue gases at power stations. Besides absorption technology is commercially applicable, there are a lot of experiences with a conventional chemical solvent, like monoethanolamine, and research projects are planned to be executed for new plants 1040 L.M. Romeo et al. / Applied Thermal Engineering 28 (2008) 1039–1046 during the next years [4,5]. The main disadvantage of amine scrubbing is the cost, which is perceived too high to be economically attractive. A practical research objective is the analysis of the CO2 capture process integration with a view towards minimizing the cost of implementation, operation and the cost per ton of CO2 avoided. Obviously intensive research is necessary to reduce its current cost from 40 to 70 €/ton CO2 [2] to values well under 25 €/ton CO2. CO2 absorption by amine scrubbing has been extensively studied by many researchers but studies are mainly focused on chemical reaction mechanism, mass transfer, gas/liquid equilibrium, and other related aspects of CO2 absorption [6–9]. Nevertheless, one of the main problems is related to the large quantities of heat required to regenerate the amine solvent within the CO2 capture process. A typical range is between 0.72 and 1.74 MWt per MWe generated in a coal-fired power plant [10]. The economical cost of this energy requirement, mainly in the stripper reboiler and CO2 compression, is usually higher than capital cost. Outstanding studies have analyzed different alternatives to reduce the heat duty on the reboiler and the thermal integration requirements on the power cycle [11–15]. These studies have been focused in the location of steam extraction at steam turbine and the re-injection of condensate from stripper to steam cycle. It seems evident that the optimal option is to extract saturated steam midway through the low pressure section of the turbine [11–14] with a pressure between 1.8 and 2.8 bar using the lowest quality steam available to fit with the reboiler requirements [14]. Most of the steam turbines do not have an extraction at this pressure range, as a consequence, perfect integration is only possible when steam cycle is designed taking into account a future amine scrubbing installation. For existing power plants, researchers have analyzed different options to integrate amine scrubbing with a small efficiency reduction in the original power plant performance. Power reductions around 17% has been reported, for a 900 MW coal-fired power plant, [11], where 611 t/h of CO2 are captured and compressed, using 737 t/h of steam, which is the 54% of the steam leaving the boiler. Other studies increase the power reduction up to 26%, with a reduction in power plant efficiency of 11.6 points for a 320 MW coal-fired power plant [12]. In this case 335.2 t/h of steam were extracted at 5 bar, in low pressure turbine stage, 33% of the steam leaving the boiler, to capture 213.1 t/h of CO2 and the condensate was re-injected into the deaerator. A novel strategy to reduce the efficiency losses is based on an extraction from an IP/LP crossover pipe and an expansion through a new auxiliary turbine [14], to get the adequate conditions for the steam to the reboiler. In this case, 79% of the steam is drawn-off from a 450 MW power plant. Finally, some researchers [15] have increased the complexity of the installation adding an auxiliary gas turbine and natural gas boiler for the stripper energy requirements. In this case, CO2 avoided was reduced due to emissions from these equipments, which were not captured. In order to completely analyze the amine capture process the CO2 compression installation, the cooling equipment must be taken into account. Power reduction due to compression could represent around 10% of the electrical power and refrigeration necessities could increase up to 60%. In spite of these data and some studies [12,15] that have considered the compression necessities, there is still a lack of information and studies that include the integration of the heat from the compression stages into the steam cycle in order to reduce the cooling requirements and the efficiency penalty into the steam cycle. Generally, neither the CO2 compression power nor the cooling equipment and its effect on power plant performance are taken into account, in the way of improving the power plant performance, once the capture system is included. The objective of this paper is to compare the power plant performance, with special attention on the power output and efficiency penalty, and investment cost and specific price of CO2 when MEA scrubbing is integrated with the steam cycle. Different alternatives to provide heat and power have been evaluated in order to minimize the cost of CO2 avoided and the cost of electricity, after adding the capture process to the power plant: Reboiler heat duty provided by an external auxiliary steam boiler, by a steam turbine extraction or even by heat provided by a gas turbine that also satisfies the power requirements for CO2 compression. Finally, cost calculations have been developed taking into account the total annual costs of each configuration and the total CO2 avoided, in order to achieve a specific value, price per ton of CO2 avoided, to be able to compare the different alternatives. 2. Case study The simulated power plant arranges three similar pulverized coal-fired units with a 350 MWe reheat steam turbine featuring six stages of regenerative preheating, three low pressure, two high pressure and deaerator. At base load, the steam conditions at the turbine admission valves supplied from each of the three fired boilers are 311.2 kg/s of live and reheat steam at 168 bar/540 °C and 39 bar/ 540 °C respectively. The net efficiency of such units amounts to 36.93% (LHV). The combustion of coal supplied to each fired boiler produces 982.89 MWt at base load and yields approximately 630.0 kg/s (1,990,000 Nm3/ h) of flue gas being 96.3 kg/s of CO2 (194,224 Nm3/h, 9.76 %v). This emission CO2 values is low compared to regular flue gases from coal firing but the coal used for calculations was a low-rank Spanish lignite with low carbon content (40%C, 20%H2O, 25%ash). A power plant simulation has been developed to provide a base case and essential information on coal consumption, thermal efficiency, net plant efficiency and electricity output. Simulations can also provide the quality and quantity of steam throughout power cycle as well as the emission rate, temperature, and composition of the flue gas. L.M. Romeo et al. / Applied Thermal Engineering 28 (2008) 1039–1046 3. Capture plant simulation Initial condition of the simulation has been to capture between 60% and 65% of CO2 produced, owed to economical reasons. In a medium-age power plant (typical for the majority of installation in Europe) a high investment in CO2 capture cost could not be cost-effective. In these situation seems reasonable to reduce the capture rate just to fulfill National Allocations Plans for each installation. The hypothesis considered has been that medium-age power plants are forced to reduce a maximum of 60% of CO2 emissions. It is used a pure 30%w MEA aqueous solution. An absorber packed column could treat a maximum volume flow rate around 300,000 m3/h [12], so that the equipment sizing becomes technical and economically feasible. Four trains of 10 m diameter each absorber were used [15] to treat 1,284,371 m3/h. With these values four separate absorption/regeneration column trains were necessary, treating one sixth of the gases flow each one (331,600 m3/ h). Flue gas, with a mass flow of 105 kg/s (331,666 Nm3/ h) is drawn-off after desulphurization unit at 55 °C and 1 atm. It is assumed no pollutants in flue gas such NOx and SOx. A purge of 5% of degraded MEA will be also included within the model. Absorption process flowsheet is shown in Fig. 1. CO2 capture is modeled using chemical-absorption with MEA. The ASPEN PLUS block [16] used for the simulations, Aspen RadFrac, is a rigorous model for simulating multistage vapor–liquid fractionation operations, in particular: absorption, reboiled absorption, stripping and reboiled stripping. It has been assumed no pollutant in 1041 the flue gases and an adiabatic absorption process. Main simulation variables and results are shown in Table 1. Electricity and heat consumption per ton of CO2 captured are calculated with ASPEN and values are comparable but slightly lower than those reported by other authors [11– 13]. Total energy requirements, electricity and heat consumption, amounts approximately 4.0 GJ/t CO2 with an electricity consumption of 112 kW h/tCO2 and heat required similar to [13]. The discrepancy with the value of 2.76 is due to the use of KS-1 solvent in [11]. Although the heat for stripper reboiler can be reduced using different amines and blends, the objective of present work is to minimize its effects in the power plant performance. Total compression energy required to CO2 conditioning for transport, 140 bar and ambient temperature, is 70.5 MWe, which represents about 7% of the power plant energy output. The compression process requires intercooling stages, to reduce compression requirements and to avoid excessive CO2 temperature. 4. Integration of power plant and MEA scrubbing CO2 capture process requires a great amount of supplementary energy to avoid excessive power output penalty. For amine scrubbing, thermal energy is needed for amine regeneration, electricity consumption for CO2 compression and cooling necessities for refrigeration. An important consideration to select steam quality for the stripper is the steam pressure. The consensus is that the reboiler temperature must not overcome 122 °C, value above which degradation of MEA and corrosion becomes intolerable. Assuming 10 °C as hot side temperature approach in the Q COOL REGABS REGCOLD GASOUT MIXSOL B4 CO2 B3 SOL SOLIN ABSORBER DESORBER LIQHOT W LIQ2 REG5 GASIN1 REG QREB WPUMP Q LIQ1 REG2 PUMP SPLIT MIX2 REG3 PURGA Fig. 1. MEA absorption process flowsheet. REGENERA PURGA1 1042 L.M. Romeo et al. / Applied Thermal Engineering 28 (2008) 1039–1046 Table 1 Main simulation parameters comparison Base plant net generation Base plant efficiency (LHV) Flue gases CO2 concentration Technology CO2 flow rate captured CO2 captured Electricity consumption per CO2 captured Heat consumption per CO2 captured Units This paper Mimura [11] Desideri [12] Bozzuto [13] MWe % %v 1069 36.9 9.7 MEA 689.6 65 111.93 3.57 900 321 31.1 13.2 Fluor Daniel 203.6 86.5 91.50 3.95 434 36.7 15.0 Kerr-McGee 378.8 98 118.84 – t/h % kWh/tCO2 GJ/tCO2 reboiler, the steam conditions of the saturation temperature amounts to 132 °C [14]. Saturation pressure at this temperature is 2.8 bar. This thermal energy can be supplied from either an auxiliary boiler, or from a power plant steam extraction. Finding the optimum way to extract this steam becomes essential in order to get the less power plant energy penalty. Before the compression process, it is required to dry the captured CO2 stream, cooling it down until around 30 °C. A valuable heat stream is produced cooling down the stream in a first stage to 50 °C and in a second stage to 25 °C. Such stream could be integrated into the low pressure steam cycle lowering the heating requirements. Two low-pressure heaters could be eliminated from steam cycle and the extraction steam mass flow feeds the LP steam turbine to increase electricity production. This fact will be taking into account along the different configurations simulated. Some researchers have considered in their analysis to maintain the power plant original output to the grid [15], resulting that a considerable amount of supplementary energy must be supplied for the CO2 separation processes using gas turbine or natural gas boilers. The drawback is that CO2 generated by the combustion of natural gas used in these systems is not captured, consequently the CO2 avoided is reduced and the capture cost per ton of CO2 is increased. In this study it is assumed a power plant output reduction owes to steam de-rate and compression electricity requirements. In order to supply this energy and minimize the impact on power output, efficiency and capture cost, three possible options are simulated and integrated into the original power station for comparison, Fig. 2: – The first one uses a natural gas auxiliary boiler to produce steam for the absorption process avoiding the negative effect in original plant steam cycle efficiency and power output. – The second one is integrating the absorption process into the original power plant optimizing the overall efficiency, but also reducing power output. – Finally, supplementary energy is generated using a gas turbine in partial repowering of the power plant. Results show the power plant performance for one power plant unit. 13.3 KS-1 611.0 90 119.00 2.76 CO2 emitted Flue gas CO2 absorption and compresion Reference Plant MWe MWe CO2 captured Auxiliary boiler MWt Natural Gas Flue gas Reference Plant CO2 emitted CO2 absorption and compresion MWe MWe y MWt CO2 captured Optimization Flue gas CO2 emitted CO2 absorption and compresion Reference Plant MWt MWe MWe CO2 captured Auxiliary gas turbine Natural Gas Flue gas Fig. 2. Integration using a natural gas auxiliary boiler, internal energy flows, natural gas auxiliary gas turbine. 4.1. Auxiliary boiler A natural gas boiler has been modeled to supply heat requirements to the stripper boilers. Compression energy and other auxiliary equipment are driven by the original steam turbine. Table 2 shows a comparison between the base case without capture and the use of a natural gas boiler for thermal energy requirements in stripper boiler. As expected, there is a drop of 10 points in the power plant global efficiency, due to the rise of fuel thermal energy. Net power output decreased 23.6 MWe, because the compression energy requirements are provided by the steam turbine generator. Although 60% of CO2 is captured, the boiler flue gases increase the specific value of emissions per kWh up to 0.469 kg/kWh. 4.2. Power plant internal flows integration Integration based on power plant internal streams, depends upon the plant configuration. Ideally, best results L.M. Romeo et al. / Applied Thermal Engineering 28 (2008) 1039–1046 1043 Table 2 Integration results summary Base plant Auxiliary N.G. boiler From LP1 extraction From IP2 extraction Gas turbine HP and IP heaters bleed reduction Gas turbine and extra steam generation Steam turbines output (MWe) Aux. electric. consump. (MWe) N.G. energy requirements (MWt) Net output (MWe) Global efficiency (LHV) Specific CO2 emmited (kg CO2/ kWh) 362.98 362.98 320.50 314.71 394.18 19.92/3 90.69/3 89.82/3 90.18/3 19.92/3 – 306.6/3 – – 137/3 356.34 332.75 290.57 284.65 320.04 36.93% 26.18% 30.11% 29.50% 33.27% 0.969 0.469 0.451 0.460 0.467 398.76 20.40/3 137/3 324.46 33.70% 0.464 would be obtained from an extraction at the pressure of 2.8 bar, at which saturation temperature is 130 °C. Most of existing power plants will not have this condition in any extraction and should adapt them to the required conditions. Stripper boiler conditions can be achieved after first low-pressure turbine extraction, 2.8 bar and 208.5 °C. This flow needs to be cooled down until saturation temperature (130 °C), before getting into the desorber, because of degradation problems. It is proposed to mix this steam flow with condensate re-injection from reboiler in order to increase the mass flow to stripper and reduce the extraction mass flow necessary for regeneration. Thermal energy from the first compression intercooling in the compression stage is used also to improve the cycle efficiency. Two low-pressure heaters are eliminated from steam cycle as is shown in Fig. 3, reducing output penalty in low pressure turbines. The possibility of extracting steam from an intermediate pressure point has been also studied, Fig. 3, after medium pressure turbine, steam pressure is 7.3 bar. This flow is expanded down to 3 bar in an auxiliary steam turbine, generating 20 MWe and reducing compression power necessities. Saturated water is returned to the cycle through the deaerator. Results are also presented in Table 2. It is observed a reduction in steam turbine production (around 18.5%) caused by the steam de-rate in last turbine stages as well as the use of steam turbine generator output to provide electricity to the compression process. The first option results on a increased efficiency of 0.61 points more than the second one, but it is 6.8 points lower than the reference case. Specific CO2 emissions are reduced to 0.450–0.460 kg/ kWh 4.3. Gas turbine Adding gas turbines to existing steam power plants have been used to enhance their performance since gas turbines LP1 LP 2 ηLHV= 36.93% 311 ºC 206,8 ºC 7,3 bar 2,8 bar IP1 IP2 LP1 LP2 LP3 LP4 6 1 113.2 kg/s 8,3 kg/s 121.5 kg/s LP extraction REBOIL 267 MW Flue gases Boiler LP4 2 3 363 MWe HP LP3 Condenser 5 4 3 2 1 23 MW Deareator (from intercooler) COAL HEAT 845 MWt IP2 LP1 LP2 LP3 LP4 121,5 kg/s 20 MWe 1 2 PRESAT HP Exchangers LP Exchangers IP extraction Deareator REBOIL 264 MW 15,5 MW (from PRESAT) 23 MW (from intercooler) Fig. 3. Integration with internal flows. 1044 L.M. Romeo et al. / Applied Thermal Engineering 28 (2008) 1039–1046 Deareator Condenser Natural gas 6 Combustion Chamber 246ºC 5 4 210ºC 169ºC 3 118ºC 1 2 81ºC 56ºC 38ºC Wout= 67.5 MW Compressor Q1 Turbine Q2 Q3 Air in Flue gas 537ºC 240ºC 200ºC 111ºC Fig. 4. Using the heat from de gas turbine flue gas to minimize feed water heaters requirements. were introduced to electric utilities in 1949 [17]. Repowering projects have been both to increase capacity stations at higher efficiency and to reduce of mainly NOx and SO2 emissions in a cost-effective way. Presently, when carbon dioxide emissions seem to have an important role in our society, repowering concept adds another credit to be more attractive. In repowering arrangement, gas turbine exhaust gas could be used as combustion air for the coal fired power plant. This option would require excessively arrangements in the air–coal system and in the steam boiler. Moreover hot windbox repowering arrangement was not survey because of the lower oxygen concentration than ambient air and the increase of flue gas volume that could lead to erosion problems and different temperature profiles inside the boiler. Also gas turbine exhaust gas could be used to improve steam cycle efficiency. On this paper some possibilities have been simulated adding one Siemens V64.3 gas turbine to the three steam cycles. On feed water repowering, gas turbine flue gases are cooled down in three stages reducing steam turbine bleedings, Fig. 4. Also, a gas turbine heat steam recovery generator is used to supply reheat steam to the turbine. Power delivered by the gas turbine is used as auxiliary power for CO2 compression. Results, Table 2, show a small net output reduction of 9% (around 32 MWe) but specific emissions remains in values similar to those presented above due to natural gas combustion in gas turbines. Efficiency penalty is lower than previous configurations, almost 3.0 points over the steam cycle integration. Even if gas turbine results are showed a minimum efficiency and output penalty, it becomes necessary to value them into economical terms, in order to focus that configuration that minimize the capture cost and the increase of electricity cost. 5. Economic evaluation The target for the CO2 capture studies is to recover 60– 65% of the original emissions with the minimum cost per CO2 avoided. The target for this analysis is to capture around 60–65% of the original emissions with the minimum cost per CO2 avoided. It is evident that the majority of the studies raise this quantity up to 90%, [3], in a medium, long-term analysis this could be the objective. Nevertheless, a short-term option for power companies is to reduce CO2 emissions in order to carry out the National Allocations Plans without an important impact in their economic results. In this scenario, a less intensive capture process could be economically attractive. Capital costs were evaluated using different sources [16– 21]. It has been used the ‘‘six-tenth rule’’, broadly used and explained [20]. Assumptions used in the economic evaluation were: – Existing power plant is paid off. – 5% interest rate. – 20 year project life with zero salvage value at the end of the project. – No taxation or depreciation calculations were included in this study. – Electricity price, 5.29 €/MWh. – Cost of coal for power plant boiler and the auxiliary power unit, 2 €/GJ. – Cost of natural gas for auxiliary power units, 4 €/GJ. – Cost of natural gas (NG) auxiliary boiler, 75 €/kWh t. – Cost of gas turbine (GT) and heat recovery steam generator (HRSG), 265 €/kW. – Cost of the make-up water, 0.191 €/m3. – Cost of the make-up MEA, 981 €/ton. – The plant operates for 7500 h/year, which gives time for maintenance. – The maintenance costs are 2.2% of the fixed capital investment. – The final CO2 product will be provided at 25 °C and 139 bar. Equipment costs, Table 3, are the main contribution to the total cost as it was previously shown by [12,15]. O&M cost are also itemized in Table 3 for the absorption process. Total annual cost amounts to 49 million euros per year. This is not the unique contribution to the capture process, it is necessary to take into account the influences of the reduction of power output, extra fuel for auxiliary equipment and the gas turbine and heat recovery steam genera- L.M. Romeo et al. / Applied Thermal Engineering 28 (2008) 1039–1046 Table 3 Total annual costs (€) Capital costs (€) Blower Absorber Desorber Reboiler MEA plant and auxiliaries Regenerator Total capture equipment costs (€) Total compression equipment costs (€) Total equipment costs (€) Instalation cost (14%) Initial MEA Instrumentation and control (10%); piping (17%) Electrical equipment (8%); buildings and services (16%) Capture plant and compression total cost (€) Engineering and supervision cost (7%); process and project contingency (15%) Direct and indirect total cost (€) O&M fix cost Total maintenance cost Maintenance cost assigned to workers Administration cost 2.2% plant total cost 12% maintenance total cost 30% worker assigned cost Total O&M fix costs (€) 4,174,945 33,399,560 3,931,981 3,444,496 16,052,668 2,355,650 63,359,301 167,770,755 231,130,056 32,358,208 12,346,790 62,405,115 55,471,213 393,711,382 50,848,612 444,559,995 10,220,571 1,226,469 367,941 11,814,980 O&M variables cost MEA make-up Water make-up Total O&M variable cost (€) 837,810 1,188,628 2,026,438 Total O&M cost (€) 13,841,418 Total annual cost (€) 49,048,209 tor, auxiliary boiler or plant modifications. These quantities are shown in Table 4. Modifications of steam cycle for the stripper energy requirement is the cheaper option but, as it was shown in Table 2, have the maximum power output reduction and a loss of efficiency of 6.8 points. As no extra CO2 emissions are needed the CO2 avoided amounts 4.8 million tons per year with a cost of 25.3 €/ton CO2 avoided. This option seems to be the preferred choice. Gas turbine scheme shows a intermediate annual cost due to the size of GT + HRSG is substantially lower than NG boiler. Although is the option with the higher efficiency and power output, CO2 avoided is slightly lower than previous configuration. As a consequence, the cost increases up to 31.0 €/ton CO2 avoided. Finally, the equipment and operational cost of the auxiliary boiler option increase the total annual cost for this 1045 configuration. Moreover, the CO2 emissions decrease the CO2 avoided and increase the cost per ton CO2 avoided up to 60 €. If coal is used instead NG cost is reduced to 56 €. Despite expected steam turbine operational problems, the option of steam cycle modifications with integration of intercooling compression into the low-pressure steam cycle seems to be worthy compared with configurations including GT and/or steam generators. 6. Conclusions Amine scrubbing is a well-known method for CO2 capture. Chemical reaction mechanisms and solvent development have been studied in the last decade in order to reduce energy regeneration requirements. However, the optimum integration of capture process into the power plant has not been solved yet. The power output and efficiency penalties make that the efficiency optimization and the economical optimization do not agree. This paper has proposed different possibilities to overcome the energy requirements by means of amine scrubbing integration into a commercial power plant, and has presented a technical and economical analysis of the performance of these approaches. It should be noticed that regeneration requirements and its effect on power plant performance can also be reduced using different amines and blends. But in these cases, further research is needed in order to propose several integration schemes. Using a gas turbine to supply compression electrical energy requirements and extracting steam from the steam cycle is the optimum option with regard to the efficiency penalty on the power plant performance. Nevertheless, economic evaluation shows that GT operation reduces the CO2 avoided and increases the capture cost up to 6 €/ton CO2 with reference to a configuration with steam cycle modifications. These configurations have shown the best results according the capture cost, even if larger penalties in efficiency and power output are produced. Obviously, the less efficient and cost-effective option is the installation of new steam generator for the stripper energy requirements. Efficiency reduction amounts 10 points with reference to the base case, and a capture cost of 60 €/ton CO2 avoided for NG and 56 for coal operation. Although research is focused in the integration of capture process into the existing power plants, more research is needed in order to design new power plant with integrated CO2 capture process. Efficiency penalty would be reduced and a cost-effective process could be developed. Table 4 Specific CO2 prices, calculated for each configuration Gas natural boiler Internal flows Gas turbine Total annual costs (€) CO2 avoided (t/year) Price per CO2 ton (€/t) Global efficiency (LHV) 216,639,379 121,573,539 137,465,238 3,575,826 4,815,288 4,401,810 60.58 25.25 31.23 26.18% 30.11% 33.70% 1046 L.M. Romeo et al. / Applied Thermal Engineering 28 (2008) 1039–1046 Acknowledgements The authors are grateful for the financial support from the Spanish Government, without which, this work could not have been undertaken. 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