• 0 Coal and gas fired power plants are the main contributors of CO2 emissions. CAPSOL technology offers a competitive solution for the efficient post-combustion CO2 capture. (Public Power Corporation, Agios Dimitrios Power Plant)…
  • 1 CAPSOL incorporates state-of-the-art thermodynamic property prediction and Computer Aided Molecular Design for advanced solvents and blends. (Source : Imperial College - London)…
  • 2 CAPSOL technology utilizes multi-level design and selection of validated solvent-process schemes with optimum economic and controllability features. (Papadopoulos A.I., and P. Seferlis, “A framework for solvent selection based on optimum separation process design and controllability properties”,Computer Aided Chemical Engineering, 26, 177-182, 2009.)…
  • 3 CAPSOL aims at optimum design of absorption/desorption equipment and column internals through advanced modelling and experimentation (Kenig, E.Y. (2008), Chem. Eng. Res. Des. 86, Part A, 1059–1072)…
  • 4 CAPSOL aims at sustainable CO2 capture technology through the Environmental Performance Strategy Map (De Benedetto L., Klemeš J., 2009. J. Clean. Prod., 17(10), 900-906)…
  • 5 CAPSOL targets plant level (resources) integration of CO2 emitting and capture plants through total-site and plant-wide optimization analysis (Varbanov, P., Perry, S., Klemeš J.,Smith, R., (2005), Applied Thermal Engineering, 25, 985-1001)…

CAPSOL Heat Integration Achieves Significant Savings in Energy Demands


CAPSOL Heat Integration
Achieves Significant Savings in Energy Demands


Peng Yen Liew1, Petar Sabev Varbanov1,
Jiří Jaromír Klemeš1, Aggelos Doukelis2, Igor Bulatov3, Panos Seferlis4



1Centre for Process Integration and Intensification – CPI2, Research Institute of Chemical and Process Engineering - MŰKKI, Faculty of Information Technology, University of Pannonia, Veszprém, Hungary.

2Laboratory of Steam Boilers and Thermal Plants, National Technical University of Athens, Athens, Greece

3Centre for Process Integration, School of Chemical Engineering and Analytical Science, The University of Manchester, Manchester, United Kingdom

4Department of Mechanical Engineering, Aristotle University of

Thessaloniki, 54124 Thessaloniki, Greece


The power generation industry very much relies on fossil fuels. In order to meet the CO2 emission reduction targets of the European Union for the coming years, these processes need to limit their net CO2 releases to the environment. Carbon Capture and its following sequestration is one of the investigated options. However, these additional processes tend to decrease the power output and the profitability margin for the industry because of the internal energy consumption posed by them.

One of the ways of increasing the energy efficiency of the CO2 capture processes and their combination with the core power plants is to apply Heat Integration techniques based on thermodynamic analysis – and Pinch Analysis in particular. Such work has been performed as part of project CAPSOL, where the designed CO2 capture process units have been integrated with the power plant designs and the process integration options for the combined plants have been investigated. Utilisation of waste heat has been pursued, in order to increase the energy efficiency of the overall integrated process. The integration of the capture process into the power plants has also considered the use of fans, coolers and compressors. The high grade heat of steam extraction in power train is also examined in this study for ensuring proper heat utilisation is done.

Based on the studies performed during the CAPSOL project, the current document provides a summary of the methodology, the considered cases and the obtained optimisation results. As the main achievement of the study can be outlined that the identified integration options have been able to overcome completely and in some cases to even surpass the utility cost penalty introduced by the CO2 capture unit, making the resulting integrated plants more cost efficient than the initial benchmarks in terms of running cost, while at the same time also eliminating about one-third of the power penalty of the CO2 capture.


Global warming and carbon emission issues have increased the awareness of industry of the importance of CO2 capture processes. In the year 2011, fuel combustion in the energy industry emitted a total of 31,342 Mt of CO2. The emissions keep increasing with the increase of world energy demand. As a result, governments and authorities world-wide are committed to international agreements for lowering carbon emissions throughout all economy sectors and industries. To avoid financial and administrative penalty, industrial efforts for carbon emission reduction have become essential for meeting the targeted emission reductions.

Carbon Capture and Storage (CCS) is one of the considered alternatives to decrease the emissions of greenhouse gases by 19 % in energy generation processes which involve fuel combustion. There can be several types of carbon capture processes depending on their sequence with regard to the main energy conversion and the principle of operation. Some example types are post-combustion capture, pre-combustion capture, oxyfuel combustion and chemical looping combustion. Post-combustion carbon capture process is one of the most promising types for industrial implementation due to the lower implementation complexity expected. Several types of CO2 separation process from flue gas could be used in post-combustion a carbon capture facility. There can be use of chemical absorption (amine absorption, aqua ammonia absorption, dual alkali absorption, and absorption with sodium carbonate slurry), adsorption (zeolites, activated carbon, amine functionalized adsorbents, and metal organic frameworks) and membrane separation.

The power penalty in a coal-fired power plant from introducing post-combustion carbon capture has been studied by Goto et al. Cormos et al examined the efficiency and the power penalty for two different types of Carbon Capture facilities with a super-critical coal-based power plant. Post-combustion carbon capture with gas-liquid absorption and calcium looping cycle are considered in that study. Berstad et al suggested a process design with low temperature pre-combustion carbon capture with coal derived syngas for an IGCC plant. Damartzis et al proposed a generalised methodology for designing an optimal post-combustion Carbon Capture process. Liew et al analysed the Process Integration opportunity of monoethanolamine (MEA)-based carbon capture process and a natural gas power plant. They suggested integration for satisfying the heat requirement of stripper reboiler with the energy excess in the low pressure steam condenser. However, exit temperature of the low pressure steam condenser is not allowing heat exchange with the stripper reboiler. The exhaust pressure of low pressure turbine is suggested to be increased to enable the heat exchange between these equipment items. The power penalty is one of the main indicators evaluated and investigated in that study. In this report, a similar investigation is described for a MEA-based carbon capture process, providing a detailed example of the procedure on a lignite fired power plant. The Process Integration options between the processes are examined.


Process Integration can be identified using Pinch Analysis and Mathematical Programming. Pinch Analysis is generally performed using graphical (Composite Curves - CCs and Grand Composite Curve - GCC) and numerical (Problem Table Algorithm) procedires. Process energy utilisation is analysed by Pinch Analysis. The methodology used to identify Process Integration options in this study is summarised next:

STEP 1: Data Extraction

Stream data of the plant and the carbon capture process is extracted from the process flow diagram. It is essential to obtain several specifications of the process streams. These are the mainly the source temperature, target temperature, flow rate and specific heat capacity. These properties are usuallyderived from the temperature measurements and the heat duties of existing heat exchangers, condensers, heaters and coolers.

STEP 2: Pinch Analysis

The energy requirements of the process are targeted using the Composite Curves and the Grand Composite Curve based on the stream data extracted. These represent the theoretical minimum energy requirements, which also represents the maximum energy recovery in the system.

STEP 3: Process Modification and Integration Options Identification

Besides the steam generation process from flue gas, Process Integration and modification options should be identified for minimizing energy consumption of the process. The design of steam turbine in the turbine island is also examined for maximum power generation. The use of re-heater/ heat pump also considered for upgrading heat sources at low temperature to integrate with heat sink at high temperature.

STEP 4: Pinch Analysis: Reassessment

The optimum operating condition is determined after the processes modification options identification. The effects of the process modification are analysed. The CCs and GCC are constructed for the retrofit design to evaluate the improvement of process energy consumptions.

STEP 5: Heat Exchanger Network Design

The Heat Exchanger Network for the process is designed using Grid Diagram for maximising the energy recovery in the process. The process integrated flowsheet is then drawn based on the Grid Diagram.

STEP 6: Economic Analysis

The gross profit of the integrated process is analysed for preliminary cost saving assessment from the process modifications. Detailed calculation is also essential for accounting other energy consuming equipment, as well as the investment cost, for confirming the economical potential of the modifications suggested.



STEP 1: Data extraction

Data extraction has been performed. Table 1 summarises the extracted steam data for both lignite-fired power plant and carbon capture unit. Figures 1 and 2 show the Grand Composite Curves for the lignite-fired power plant alone and that of the power plant with carbon capture unit added.



Figure 1: Grand Composite Curve for lignite power plant

STEP 2: Pinch Analysis

The lignite-fired power plant theoretically does not require external energy supply because has been designed to generate steam for power generation by burning fuel (Figure 3). The turbine condenser is the only equipment unit in the power plant which requires utility – for cooling, at 341.2 MW.

The effect of adding the carbon capture unit on the plant’s energy demand has been analysed next. The first step is thermodynamic analysis via Pinch Analysis. The minimum temperature difference has been set to 15 C. The Grand Composite Curve for the combined processes (power plant with carbon capture) is shown in Figure 2. The hot and cold utility requirements of the combined process are 443.3 MW and 971.7 MW, while the hot and cold Pinch temperatures are located at 100.5 C and 85.5 C. What is woth noting is that here appears the need for hot utility (in addition to the fuel burned in the standalone plant) and at the same time a sizeable increase of the cold utility demand.


Table 1: Stream data for lignite-fired power plant and carbon capture unit



STEP 3: Process modification and integration options identification

Several process modification options have been identified for the considered lignite-fired power plant with carbon capture. The stripper’s condenser is suggested to integrate with the air preheater (Scheme 1), while the inter-coolers of the CO2 compression train are integrated with the condensate return heating (Scheme 2). The use of steam extraction from the low pressure steam turbine is found to be the best heat source for the reboiler heating (Scheme 3).

The integration of stripper’s condenser and air preheater is labelled as Scheme 1. The stripper’s condenser has heat available from 100 C down to 40 C, while the combustion air needs heating up from 19 to 341 C. It is beneficial if both streams could be integrated for heating air up to 80 - 85 C, while the remaining energy could be supplied by flue gas exits from the steam generation process.



Figure 2: Grand Composite Curve for combined lignite power plant and carbon capture process


The integration of intercoolers and condensate return heater has been considered as Scheme 2. There are a total of 85.3 MW of heat sources to from intercoolers in the CO2 compression train, initially served by cold utility. The condensate return exit from the condenser is has to be preheated to reach the supercritical de-aerator at 151 C. The integration of these streams helps reducing the power penalty due to the reduced need for stream extraction from the LP turbine for condensate return heating.

The modification of steam extraction condition for the stripper’s reboiler is Scheme 3. The stripper’s reboiler (120-121 C) needs heating and this is done initially by extracting steam from the LP turbine. The optimum steam extraction pressure should be determined by selecting pressure with its saturated temperature is just above the allowable heat transfer temperature (Treboiler + ∆Tmin = 135 C). The amount of steam extracted should enable providing sufficient amount of heat to the reboiler by its latent heat (Heat duty of reboiler/ heat of condensation = 475,404 kW / 2156.03 kJ/kg = 220.5 kg/s). However, the steam extracted is required to be desuperheated (34,846 kW) by a heat sink before heating the reboiler. The condensate is then required to be heated (14,190 kW) to achieve the condition required by the de-aerator.

STEP 4: Pinch Analysis: Reassessment

The suggested heat integration schemes are reassessed using Pinch Analysis. The stream data is updated based on the process modifications and new GCC is plotted (Figure 3). The parasitic hot utility demand from Figure 2 has been eliminated, while the cold utility requirement has a slight increment to 927.7 MW.

Figure 3: Grand Composite Curve for the lignite power plant and carbon capture after process modification.

STEP 5: Heat Exchanger Network Design

The streams involved in the process modification are next combined for the Heat Exchanger Network design, which is shown in Figure 4, while the flowsheet for condensate system (Scheme 3 - Figure 5) and inter-coolers in CO2 compression train (Scheme 2 - Figure 6) are drawn.

Figure 4: Heat Exchanger Network design



Figure 5: Flowsheet for Integration Scheme 3


Figure 6: Flowsheet for Integration Scheme 2


STEP 6: Economic Analysis


The suggested integration schemes are required to be assessed from an economic point of view. The merge of the power plant and the capture unit by supplying steam to the stripper’s reboiler from turbine extraction, without other process integration options, is used as the base case of this study (Case A). The newly suggested network incorporating the heat integration options is termed as Case B.


The recommended integration options have been analysed from operating cost viewpoint. The cost of cooling water supply has been specified at 0.35 €/m3. Break-even electricity selling price is used to calculate the equivalent power penalty due to the integration option. Sensitivity analysis of the electricity price is also done in the same analysis, which the electricity price is assumed at 0.05, 0.075 and 0.1 €/kWh. The gross power generation and utility cost is used for calculating the profit. Table 2 shows the analysis result of the operating cost at different electricity selling prices versus turbine exhaust pressure. The plant configuration of non-integrated power plant and CO2 capture unit is used as the basis (Case A). There the reboiler is satisfied by steam extraction from the LP turbine, while there is no other integration in the plant. The process in this case consumed relatively larger amount of energy for cooling proposes. Case B has more power generation opportunity and lower utility cost.


Table 2: Power lost and utility cost comparison for all integration options





The Process Integration options for super-critical lignite coal-fired power plant and MEA-based carbon capture process have been illustrated in this paper. The hot and cold utility requirements of integrated power plant and carbon capture unit before process modification are 475 MW and 972 MW. The heat exchange between stripper’s condenser cooler and air pre-heater is suggested to be implemented. The air coolers in CO2 compression train is suggested to provide energy for condensate return heating, instead of using steam extraction from LP turbine. The stripper’s reboiler duty is conventionally satisfied by extracting steam from the LP steam turbine. The steam extraction pressure should be determined by selecting pressure with its saturated temperature at just above the allowable heat transfer temperature. The quantity of steam extracted should be able to provide sufficient amount of energy to the reboiler by its latent heat. The process modification for integrating the carbon capture unit has improved the power penalty caused on the power generation system and the utility cost is also reduced by € 19 x106 /y.


The process integration options identified in the study provide a significant reduction of the power penalty and financial revenue recovery. For all considered plants the utility cost penalty from introducing CO2 capture is virtually completely eliminated and in the case of the gas power plant the utility demand of the integrated plant with CO2 capture performs even better than the original benchmark plant (100-110 % reduction of the utility penalty).




The authors gratefully acknowledge the financial support from the EC FP7 project “Design Technologies for Multi-scale Innovation and Integration in Post-Combustion CO2 Capture: From Molecules to Unit Operations and Integrated Plants” – CAPSOL, Grant No. 282789.




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