A Unified Control Scheme for Coal-Fired Power Plants with Integrated Post Combustion CO 2 Capture

A Unified Control Scheme for Coal-Fired Power Plants with Integrated Post Combustion CO 2 Capture Friedrich Gottelt Kai Wellner Volker Roeder Johannes Brunnemann Gerhard Schmitz Alfons Kather XRG Simulation GmbH, 21079 Hamburg, Germany (e-mail: gottelt@xrg-simulation.de, brunnemann@xrg-simulation.de). Hamburg University of Technology, Institute of Thermo-Fluid Dynamics, Applied Thermodynamics, 21073 Hamburg, Germany (e-mail: kai.wellner@tu-harburg.de, schmitz@tu-harburg.de) Hamburg University of Technology, Institute of Energy Systems, 21073 Hamburg, Germany (e-mail: roeder@tu-harburg.de, kather@tu-harburg.de) Abstract: Within the DYNCAP project, a unified control scheme for coal-fired power plants with integrated CO 2 capture cycle is developed. For seamless integration into existing power plant technologies, the German technical guideline VDI3508 for conventional thermal power plants is taken as starting point. Interactions between steam cycle and post-combustion carbon dioxide capture cycle are identified and communication interfaces between its control units are defined. An according extension of VDI3508 is implemented on the computer using the library ClaRaCCS written in Modelica. By direct computer simulation the validity of the novel control scheme is demonstrated under transient operation of the power plant coupled to the carbon capture cycle. The simulation results are discussed and recommendations for further improvement of the scheme are given. Keywords: Power System Control, Steam Plants, Dynamic Modelling, Computer Simulation, CCS, Post-Combustion Capture, Modelica, Model-Based Control 1. INTRODUCTION To avoid serious climate change the IPCC (Intergovernmental Panel on Climate Change) recommends a reduction of CO 2 emissions of 80% until 2050 compared to 1990, see Metz et al. (2007). Although the part of renewable energies is growing significantly, fossil fuels such as coal will remain central to the worlds energy supply during the next decades. It is therefore necessary to evaluate power plant technologies appropriate for a significant reduction of CO 2 emissions already in the short term. One technologically available solution is the direct capture of carbon dioxide from es and its storage into underground caverns (CCS). In order to embed this technology into a future energy mix with a large proportion of renewable energies the need for a flexible operation of power plants under rapid load changes arises. Being a technical challenge on its own, the integration of a carbon capture cycle demands a unified control scheme for such power plants. In this paper an according control scheme is developed and implemented in a joint computer simulation of the water steam cycle coupled to a post-combustion CO 2 capture process. 2. DYNCAP PROJECT AND CLARACCS LIBRARY As a part of COORETEC, an initiative of the German Federal Ministry of Economics and Technology, the project DYNCAP aims at studying the dynamic behaviour of steam-power processes with carbon dioxide capture in order to provide balancing energy. The main objective of DYNCAP is the dynamic analysis of the sub-processes that can be summarised as follows: Water-steam cycle of the power plant Flue gas side of the power plant Post-combustion CO 2 capture process Oxyfuel process CO 2 compression process For this purpose the Modelica library ClaRaCCS (Clausius Rankine with CO 2 Capture and Storage) is being developed, see Brunnemann et al. (2012) and Dietl et al. (2011) for a short overview. Modelica (2011) is an object-oriented, acausal and non-proprietary modelling language which is used for dynamic simulations of complex physical systems and is hence suitable for carrying out these studies. The library ClaRaCCS targets to develop flexible and robust models and will be freely available under the terms of the Modelica License by 2014. 3. POST-COMBUSTION CO 2 CAPTURE In a post-combustion CO 2 capture (PCC) carbon dioxide is separated from the of a conventional coal-fired

steam power plant The reduction of the CO 2 emission is accompanied by a significant loss in the power output and a related net efficiency penalty of 8-12 %-pts. 3.1 Process description Figure 1 shows the detailed PCC process, figure 4-c shows its coupling to the water-steam-cycle. The of the steam generator (StG) passes through the treatment (FGT), where it is cleaned, and then enters the CO 2 capture unit (CCU). The cleaned and cooled is led into the absorber column at its bottom. In this component the CO 2 is absorbed by a counter current solution flow. The treated gas is released to the atmosphere, while the rich (CO 2 -loaded) solution leaves the absorber at the bottom. After the absorber, the rich solution is pumped through the rich-lean heat exchanger, heated up and enters the desorber column at the top. In the desorber the absorbed CO 2 is stripped from the rich solution. The required heat duty is provided by a reboiler in which steam from the power plant is condensed. From the bottom of the desorber, the lean solution is pumped to the entrance of the absorber, passing the rich-lean heat exchanger where it is cooled and preheats the rich solution and the solution cooler where it is cooled down to a certain temperature. The captured CO 2, nearly pure, is compressed and pumped to the storage. A more detailed explanation of the process can be found in Oexmann (2011). An overview of this process is given in Rochelle (2009). from FGT washing section absorber to atmosphere blower cooler to water conditioning or FGT rich-lean HX solution pump (CO 2-rich) make-up water overhead condenser solution cooler solution pump (CO 2-lean) desorber intercooled compression to CO 2- storage to makeup water system steam/ condensate from/to reboiler power plant Fig. 1. Schematic flow sheet of the PCC process cf. Oexmann (2011) 3.2 Coupling to the power plant The main interface quantities between power plant, CCU, and CO 2 -compressor that affect the net power are: the heat needed for solution regeneration in the desorber of the CCU the electrical duty of pumps and blowers within the CCU and of the CO 2 compressor the auxiliary power of additional cooling water pumps due to the large amounts of cooling water needed in the capture and compression process. These quantities are independent of the solvent and the process configuration. The electrical power for the CCU can easily be provided by the power plant, but it reduces the net power output. The heat duty is commonly provided by extracting low-pressure steam from the IP/LP crossover section in the water-steam-cycle of the power plant. As the pressure in the IP/LP crossover is reduced by the steam extraction, a pressure maintaining valve (PMV) is placed downstream the branch to the reboiler, upstream the LP turbine, to preserve a constant steam pressure and thus to maintain the temperature level in the reboiler as required by the capture process. The condensate from the reboiler is forwarded to the feed water tank in the water-steamcycle. A throttle valve is located in the steam branch to the reboiler to provide steam in the right quantity and quality. In figure 4-c the coupling of the PCC to the power plant process is shown. Depending on the process configuration and on the solvent nearly half of the steam is extracted from the IP/LP crossover before entering the LP turbine leading to a significant reduction of the power output P G of the plant. This has to be taken into consideration for power plant control, see Kather et al. (2010). 3.3 Identification of significant control quantities The major task of a CCU is the reduction of the CO 2 - emission by a certain value (i. e. 90 %). Thereby, the CO 2 capture rate depends on the amount of solution, which needs to be circulated in the process between absorber and desorber, the solvent concentration in the aqueous solution, the working capacity of the solution, which is the different between the CO 2 rich solution at the end of the absorber and the lean solution at the end of the desorber ( α = α rich α lean ), where α is the loading of the solution (amount of substance CO 2 per amount of substance solvent). Assuming a constant solvent concentration (i.e. 30 wt.-% Monoethanolamine - MEA) and a constant capture rate, the only process parameters that can be varied are the working capacity and the solution circulation rate: L/G 1/ α where L is the solution mass flow rate and G is the flue gas mass flow rate. From this correlation, it can be seen that a lower working capacity of the solution corresponds to a higher solution circulation rate in order to achieve the desired capture rate. From figure 2 it can be seen, that the solution rate and the cycling capacity directly influences the heat duty and thus the power output of the overall process. For this reason it is absolutely essential to optimise the solution circulation rate (L/G) and other interface quantities with respect to the integrated overall process. The solution circulation rate can be adjusted by the pump of the lean solution and controlled by the rotational speed of the solution pump as actuating variable. For the different loads the L/G can be adjusted to minimise the net efficiency penalty. The lean loading can be controlled by the reboiler temperature T rbl, thus the throttle valve position which influences the steam flow and therefore the heat duty to the reboiler can be used as actuating variable. The CO 2 content x CO2, which is used for determination of the CO 2 capture rate, and the temperature of the solution in the reboiler can be measured and used for controlling the process.

heat duty / (MJ th / kg CO2 ) reboiler temperature / C CO 2 loading / (mol CO2 / mol MEA ) 0,5 0,4 0,3 0,2 3,8 3,7 3,6 3,5 a) b) rich loading lean loading working capacity 3,4 115 2,5 3,0 3,5 4,0 4,5 5,0 L/G reboiler duty reboiler temperature Fig. 2. Process parameters: influence of the L/G on loadings and reboiler heat duty at a solvent concentration of 30 wt-% MEA, a desorber pressure of 2 bar and a capture rate of 90 % cf. Oexmann (2011) 4. A NOVEL UNIFIED CONTROL SCHEME The task of the unit control is to coordinate the operation of the steam generator and the turbine generator in an effective and wear-preventing manner. When further processes, such as the post combustion capture, are coupled to the power plant process the unit control has to be enhanced in an appropriate way. To cope with this task a superordinate view of the different sub-processes and its interactions is required instead of independently handling the sub-processes e.g. using simple feedback controllers. The Association of German Engineers (VDI) and the German Association of Electrical Engineering and Information Technology (VDE) provide a technical guideline for the unit control of thermal power plants VDI3508 (2003) which is to be taken as authoritative for German power plant projects. This guideline applies a model-based control approach and shall be used as a starting point for the unified control of the power plant with post-combustion CO 2 capture. The general idea of the model-based control is illustrated in figure 3 and will be discussed briefly for an arbitrary control quantity. The desired target value X tar is used to generate a feed forward value of the manipulated variable Y F F. This feed forward value is given to both, the process itself and a simplified process model, referred to as the predictor in the following. The process is controlled Feed Forward Control Process Model ("Predictor") Process Feedback Control Fig. 3. General principle of the model-based control approach as used in VDI3508 (2003) 125 120 in open-loop so far and the input leads to an actual (and measured) value of the controlled quantity X. The predictor calculates a corresponding expectation value X assuming the feed forward input. Thus, the predictor generates a reference value of the actual process output, referring to an ideal process behaviour. However, the real process will be disturbed e.g. by fouling of heating surfaces which leads to a deviation between the ideal and the real process. This deviation X is input to a feedback controller that corrects the feed forward value of the manipulated variable ( Y ). Applying this concept the process will be controlled in open loop as long as the process reacts as predicted. The feedback controller acts as a corrective with minor input only. In the following the described model-based control concept shall be applied to the unit control. For the sake of simplicity we focus on the turbo generator output at the conventional water steam side and on the reboiler temperature and the carbon capture rate at the post-combustion side (as controlled variables X). As manipulated variables Y the fuel mass flow ṁ F, the tapping valve aperture and the rotation speed of the lean circulation pump y T V n LP are considered. The control of the feedwater mass flow is implemented in an open-loop manner applying the predictor value of the steam production. This approach differs from the VDI/VDE guideline 3508 which defines the feedwater control as subordinate. Other subordinate controllers are either implemented in a simplified way (e.g. the condensate pump control) or neglected (e.g. the live steam temperature control). The integrated unit control is sketched in figure 4. Herein, three sub-figures may be distinguished, starting from top to bottom we find the unit feed forward control and the process predictors in sub-figure a), the feedback controllers in sub-figure b) and the process itself in sub-figure c). Quantities that link the three blocks together are called interfaces, where dashed lines denote for measurement values, dash-dotted lines are for actuator values and solid lines represent intern values of the unit control. Elements that are specific to the power plant with trailing postcombustion capture are marked grey. In the topmost sub-figure 4-a we find the feed forward controller of the steam cycle which is enhanced in comparison to the VDI/VDE guideline 3508 by a feed forward of the pressure maintenance valve that ensures a sufficient heating steam flow in the reboiler, also at part load. Furthermore, a map-based correction of the required fuel mass flow is introduced to reflect the load-depending efficiency loss due to the capture process. This feed forward block takes the target generator power, defined by the load distributor, as input and generates a load-depending feed forward value for the firing power Q F/F F applying loaddepending, static and dynamic limits. This reference firing power is input to the feed forward control of the capture unit (positioned next to the steam cycle feed forward). Based on a desired target capture rate, this block defines the load-depending rotation speed of the lean solution pump n LP/F F and the aperture of the steam tapping valve y T V/F F.

target power output target capture rate FEED FORWARD STEAM CYCLE FEED FORWARD CARBON CAPTURE UNIT Fuel PMV Solution Flow c) Process b) Unit feedback control a) Unit feed forward control Correction due to PCC coal feed Fuel mass flow control raw FGT StG HP preheat 4 PREDICTOR STEAM CYCLE Predictor Power Generation SH 1 HP RH IP Correction due to PCC Output Controller 5 Predictor Flue Gas Path 4 Steam Tapping LP PMV G absorber 1 treated Predictor Post Combustion Capture (see fig. 5) 2 3 rich-lean HX Tapping Controller to carbon dioxide treatment desorber 2 TV 5 3 Solution Flow Controller to water-steam-cycle FWP FWT LP CP preheat solution pump (rich) solution pump (lean) Fig. 4. Model-based unit control for the operation mode steam generator in control, sliding perssure. Control functionality necessary for the integration of the PCC are displayed in grey. Solid lines, dashed lines and dash-dotted lines denote for internal control variables, measurement values and actuator values, respectively

The feed forward values are passed to the unit feedback controller (figure 4-b) and to the process predictors (lower half of figure 4-a). The steam cycle predictor is enhanced by a map-based power output reduction due to excessive steam tapping between IP-turbine and LP-turbine. Hence, the power station with CCS generates considerably less power P G as without CCS at equal coal input. To get a realistic behaviour of the carbon capture unit the time response of the side is added as a transfer function of second order, thus providing a reference value for the mass flow ṁ F G that is input to the CCU predictor. The predictor of the post-combustion capture provides reference values for the CO 2 content x CO2 and the reboiler temperature T rbl. As this block is of major importance and quite complex compared to the other blocks, it will be explained in more detail, see figure 5. The relevant expectation values are passed to the feedback control in figure 4-b and are then taken as references for the measurement values. The difference of reference and measurement feeds the corresponding feedback controllers, namely the output controller, the tapping controller and the solution flow controller. Finally, the outputs of the feedback controllers correct the matching feed forward values and compose in this way the manipulated variable of the fuel mass flow ṁ F, the tapping valve aperture y T V and the lean circulation pump n LP, respectively. In this control scheme all feed forward controls apply a specific characteristic map and are additionally overdriven using a derivative element to cope with the storage effects of the sub-processes. behaviour appropriate transfer functions and delays are applied to the separation columns, whereas the influence of the heat exchangers and pumps has been neglected. 5. SIMULATION RESULTS To test the unified control scheme a coal fired power plant with a retro-fit CO 2 capture unit is modelled. Although no existing power plant is reproduced the model of the conventional part is based on the power plant located in Rostock, Germany. The carbon capture unit has been designed and dimensioned such that the target capture rate is attained at any load. The process is modelled as stated in figure 4-c. Although the steam cycle definition is strongly simplyfied compared to a state-of-the-art power plant, the main characteristics are captured, including preheating, storage capacities in tanks, and component interactions of a closed cycle. For every individual power plant model the characteristic lines of the feed forward controller have to be established. Here this has been done such that the desired target values for the generated power and the carbon dioxide capture rate are achieved in every load case. For correction simple PIcontrollers are applied. The figures below depict the transient process between two steady states with a step of the generator power at t=0.5 h. For the sake of simplicity all values are plotted in per unit. Figure 6 shows the response to the above mentioned step for the generated power and the predicted value as well as target and set value for the power generation and the value for the feed forward of the heating. Absorber. m rich α CO2 / rich Desorber/ Reboiler + + Valve α CO2 / lean. Q steam Fig. 5. Signal flow diagram of the predictor model for the post-combustion capture A more detailed representation of the predictor for the post-combustion capture is shown in figure 5. The predictor is based on characteristic fields that capture the part load performance. In order to represent the transient Fig. 6. Power values of feed forward and feedback control and actual value The target value for the generator output is fed as a step into the feed forward block of the steam cycle. There it is transformed into the set value for the generator power, taking the maximum speed of load change into account. The offset of the target and set values at steady-state operation is due to the losses induced by the retrofit of the PCC unit. It can be seen that the actual value of the generated power follows the predictor value very well. In figure 7 the carbon capture rate of the process is shown. The desired capture rate for steady state operation is 90%. It is evident that the target capture rate of 90% is maintained prior to as well as after the step. This is a strong indicator for a well-tuned feed forward control of the PCC unit. During the load change, almost no deviation

Fig. 7. CO 2 capture rate during load change from the target value is apparent. Both, predictor and process value show a similar behaviour, which leads to minor intervention of the feedback controller, only. In figure 8 this is indicated by the very small deviations between the lean pump s feed forward and actual volume flow rate. In addition, the progression of the respective curves shows an expected behaviour: by reducing the generated power also the amount of decreases which leads to a lower amount of solution needed in order to maintain the same capture rate. Fig. 8. Relevant values of process The slope of the live steam temperature in figure 8 indicates a well-tuned feed forward control of the feed water pump, because the same temperature is achieved prior to and after the load change. Even in transient operation the temperature behaves in a good manner since the oscillation is within a range of only 6 K. 6. SUMMARY AND OUTLOOK In this paper a novel unified control scheme for coal-fired power plants extended by a CO 2 capture cycle has been presented. The control scheme has been realised within an extended power plant model including a CO 2 capturing process. The model has been created in Modelica using the ClaRaCCS library, which is currently being developed within the DYNCAP project. By simulation of the CO 2 post combustion process, the validity of the developed control scheme has been demonstrated: The CO 2 capture rate stays close to its target value even if the power plant is at at highly transient operation. The results obtained so far give a robust starting point for numerous further enhancements of the presented control scheme. A promising direction for future research is the inclusion of a feedback controller for the feedwater pump. At the current state of implementation a strong coupling of the different feedback controllers must be stated resulting in a limited controllability of the reboiler temperature. This issue may be overcome by introducing decoupling elements to the set-up in the future. Also the optimal design of the sub-processes and here in particular the interaction and dimensioning of the tapping valve and the pressure maintaining valve will be of interest. Ultimately optimisations of the net efficiency of a complete power plant process coupled to the CO 2 capture unit at a given control scheme will be an outcome of the project DYNCAP. ACKNOWLEDGEMENTS The research project DYNCAP is supported by the German Federal Ministery of Economics and Technology (number 03ET2009). REFERENCES Brunnemann, J., Gottelt, F., Wellner, K., Renz, A., Thüring, A., Roeder, V., Hasenbein, C., Schmitz, G., and Eiden, J. (2012). Status of ClaRaCCS: Modelling and Simulation of Coal-Fired Power Plants with CO 2 Capture. In 9th Modelica Conference, Munich. Accepted for publication. Dietl, K., Joos, A., and Schmitz, G. (2011). Dynamic analysis of the absorption/desorption loop of a carbon capture plant using an object-oriented approach. Chemical Engineering and Processing: Process Intensification, 52, 132 139. Kather, A., Oexmann, J., Liebenthal, U., and Linnenberg, S. (2010). Using overall process simulation to minimize the energy penalty of post-combustion co 2 capture processes in steam power plants. In 35th International Technical Conference on Clean Coal & Fuel Systems. Clearwater, FL, USA. Metz, B., Davidson, O., Bosch, P., and Dave, R. (2007). Climate Change 2007: Mitigation. Contribution of Working Group III to the Fourth Assessment Report of the Intergovernmental Panel on Climate Change. IPPC, Cambridge, United Kingdom and New York, NY, USA. Modelica (2011). Version 3.2, https://modelica.org/. Oexmann, J. (2011). Post-Combustion CO 2 Capture: Energetic Evaluation of chemical Absorption Processes in Coal-Fired Steam Power Plants. Ph.D. thesis, Technische Universität Hamburg-Harburg. Rochelle, G.T. (2009). Amine scrubbing for co 2 capture. Science, 325, 1652 1654. VDI3508 (2003). VDI/VDE Guideline 3508: Unit control of thermal power stations. Association of German Engineers (VDI) / German Association of Electrical Engineering and Information Technology (VDE).