Simulation of a Subcritical Power Plant using a Boiler Following Control sequence

Simulation of a Subcritical Power Plant using a Boiler Following Control sequence Carbon Capture and Storage networks Ricardo Miguel Ferreira Fernandes Dissertation for the degree of Master of Chemical Engineering President: Supervisor: Co-Supervisor: Vogal: Juri Prof. Dr. Sebastião Manuel Tavares da Silva Alves Prof. Dr. a Carla Isabel Costa Pinheiro Engr. José Alfredo Ramos Plasencia Dr. Vitor Manuel Vieira Lopes Dr. Javier Rodriguez October 2012

Simulation of a Subcritical Power Plant using a Boiler Following Control sequence Carbon Capture and Storage networks Ricardo Miguel Ferreira Fernandes Dissertação para grau de Mestre em Engenharia Química Presidente: Orientador: Co-Orientador: Vogal: Júri Prof. Dr. Sebastião Manuel Tavares da Silva Alves Prof. Dr. a Carla Isabel Costa Pinheiro Engr. José Alfredo Ramos Plasencia Dr. Vitor Manuel Vieira Lopes Dr. Javier Rodriguez Outubro 2012

Anyone who has never made a mistake has never tried anything new. Albert Einstein

Acknowledgments I would like to thank Prof. Dr. Carla Pinheiro and Engr. Alfredo Ramos, my supervisors, for all the availability and readiness to help during the internship and thesis development. To Dr. Adekola Lawal, my direct supervisor, I also want to give a special thanks for the help he gave me during the work for the thesis. For all the gccs team I want to say thank you for the close cooperation on the development of the flowsheets and library models during the 7 months of progress, because without a team like that the thesis would be even more hard working. For all the PSE people in general, I want to say that I appreciated the reception and sympathy. To finish, I would like to thank my family, specially to my girlfriend and mother, for all the support given to me for being far from home. iii

Abstract The objective of this work is to model a pulverized coal power plant and some of its component units and to apply control based in the boiler following control approach, in order to analyse the control system and the power plant performance at different operational conditions. The ETI-CCS project comprises the modelling of the several components of the carbon capture and storage chain, starting with the pulverized coal power plant, the basis of the thesis. The modelling is developed in gproms and consists building some units to be added to the power plant library. Some of the models are grabbed from this library to be connected and to represent a pulverized coal power plant. The building of a flowsheet like the PCPP is a challenge, since the number of recirculations, between the great number of units, is great. By controlling the system, it was possible to represent, for example, the typical behaviour of the key variables of the system in load changes, representing the daily cycle. From the performance study it was concluded that for lower loads the power plant s efficiency decreases, consuming more resources per MW, and that the LHV of the coal and the efficiency of the turbines increase the net efficiency. Keywords Boiler Following Control, Pulverized Coal Power Plant, Carbon Capture and Storage, Modelling, gproms v

Resumo O objectivo do trabalho é modelar uma estação termoeléctrica de carvão pulverizado, e algumas das suas unidades, e aplicar controlo utilizando o modo boiler following, de forma a analisar o controlo do sistema e a performance da estação termoelétrica a diferentes condições operacionais. O projecto ETI-CCS inclui a modelação dos diversos componentes da linha de captura e armazenamento de CO 2, iniciando pela estação termoeléctrica de carvão pulverizado, a base da tese. A modelação é desenvolvida em gproms e consite em construir algumas unidades para serem adicionadas à biblioteca da power plant. Alguns dos modelos desta biblioteca são conectados entre si de forma a representar a estação termoelétrica em causa. A construção do flowsheet é um desafio, uma vez que o número de recirculações entre as inúmeras unidades é bastante elevado. Ao controlar o sistema foi possível, por exemplo, representar o comportamento típico das variáveis chaves do sistema em alteracões de load, representando um ciclo diário. Do estudo de performance foi concluído que para menores loads a eficiência do sistema baixa, consumindo dessa forma mais recursos para obter a mesma potência, e que o LHV do carvão e a eficiência das turbinas aumentam a eficiência líquida. Palavras Chave Controlo Boiler Following, Estação Termoeléctrica de Carvão Pulverizado, Captura e Armazenamento de CO 2, Modelação, gproms vii

Contents 1 Introduction 1 1.1 Motivation and Objectives................................... 3 1.2 State of The Art......................................... 3 1.3 Original Contributions..................................... 4 1.4 Thesis Outline......................................... 4 2 Background 5 2.1 Pulverized Coal Power Plant................................. 6 2.1.1 Steam Cycle...................................... 7 2.1.1.A Boiler..................................... 10 2.1.1.B Governor Valve............................... 12 2.1.1.C Steam Turbine................................ 13 2.1.1.D Generator.................................. 13 2.1.1.E Heat Transfer Cycle............................. 14 2.1.2 Flue Gas Treatment.................................. 17 2.1.2.A Electrostatic Precipitator.......................... 18 2.1.2.B Selective Catalytic Reduction........................ 18 2.1.2.C Air Pre - Heater............................... 19 2.1.2.D Gas - Gas Heater.............................. 19 2.1.2.E Flue Gas Desulfurization.......................... 19 2.1.2.F Blower.................................... 20 2.2 Pulverized Coal Power Plant Control............................. 21 2.2.1 Boiler / Turbines System Control........................... 22 2.2.1.A Boiler Following Control........................... 22 2.2.1.B Turbine Following Control.......................... 22 2.2.1.C Coordinated Boiler Turbine Control..................... 22 2.2.1.D Integrated Boiler Turbine - Generator Control............... 22 2.2.2 Boiler Control...................................... 23 2.2.2.A Superheat and Reheat Steam Temperature Control........... 23 2.2.2.B Boiler Drum Level Control.......................... 24 2.2.3 Heat Transfer Cycle Control.............................. 25 ix

2.2.3.A Condenser Control............................. 25 2.2.3.B Feedwater Heater Control.......................... 25 2.2.3.C Deaerator Control.............................. 26 2.3 Carbon Capture and Storage................................. 26 2.3.1 Post - Combustion................................... 27 2.3.1.A Absorption.................................. 27 2.3.1.B Adsorption.................................. 28 2.3.1.C Membranes................................. 28 2.3.2 Pre - Combustion.................................... 28 2.3.2.A Chemical Absorbents............................ 29 2.3.2.B Physical Absorbents............................. 29 2.3.2.C Other Options................................ 30 2.3.3 Oxy-combustion.................................... 30 2.3.4 Interaction With PCPP................................. 31 3 Modelling PCPP components 32 3.1 Deaerator............................................ 34 3.1.1 Inlets.......................................... 34 3.1.2 Outlets......................................... 34 3.1.3 Variables........................................ 34 3.1.4 Equations........................................ 35 3.1.5 Degrees of freedom.................................. 35 3.2 SCR (Selective Catalytic Reduction)............................. 36 3.2.1 Inlets.......................................... 37 3.2.2 Outlets......................................... 37 3.2.3 Parameters....................................... 37 3.2.4 Variables........................................ 38 3.2.5 Equations........................................ 38 3.2.6 Degrees of freedom.................................. 41 3.3 Blower.............................................. 42 3.3.1 Inlets.......................................... 43 3.3.2 Outlets......................................... 43 3.3.3 Parameters....................................... 43 3.3.4 Variables........................................ 43 3.3.5 Equations........................................ 44 3.3.6 Degree of freedom................................... 44 3.4 Controller............................................ 45 3.4.1 Inlets.......................................... 45 3.4.2 Outlets......................................... 45 x

3.4.3 Variables........................................ 46 3.4.4 Initial Conditions.................................... 46 3.4.5 Equations........................................ 46 3.4.6 Degree of freedom................................... 47 3.5 Drum.............................................. 48 3.5.1 Inlets.......................................... 49 3.5.2 Outlets......................................... 49 3.5.3 Parameters....................................... 49 3.5.4 Variables........................................ 49 3.5.5 Initial Conditions.................................... 50 3.5.6 Equations........................................ 50 3.5.7 Degree of freedom................................... 51 4 Modelling a PCPP 53 4.1 Design Mode.......................................... 55 4.1.1 Model description................................... 55 4.1.2 Results and Discussion................................ 58 4.2 Operational Mode....................................... 60 4.2.1 Model description................................... 60 4.2.2 Results and Discussion................................ 60 4.3 Control Mode.......................................... 61 4.3.1 Model description................................... 61 4.3.2 Results and Discussion................................ 62 4.3.2.A Controller Calibration............................ 62 4.3.2.B Daily Cycle.................................. 64 4.3.2.C Disturbances................................. 69 4.4 Sensitivity Analyses...................................... 70 4.4.1 Heating Value of the Coal............................... 70 4.4.2 Steam Turbine s Efficiency............................... 71 5 Conclusions and Future Work 73 5.1 Conclusions........................................... 74 5.2 Future Work........................................... 75 Bibliography 77 Appendix A gccs Model Library A-1 A.1 BoilerSubcritical........................................ A-2 A.1.1 Ports structure..................................... A-2 A.1.2 Ports specifications.................................. A-2 A.1.3 Specification Dialog.................................. A-3 xi

A.2 GovernorValve......................................... A-4 A.2.1 Ports structure..................................... A-5 A.2.2 Ports specifications.................................. A-5 A.2.3 Specification Dialog.................................. A-5 A.3 SteamTurbineStage...................................... A-6 A.3.1 Ports structure..................................... A-6 A.3.2 Ports specifications.................................. A-6 A.3.3 Specification Dialog.................................. A-7 A.4 Generator............................................ A-7 A.4.1 Ports structure..................................... A-8 A.4.2 Ports specifications.................................. A-8 A.4.3 Specification Dialog.................................. A-8 A.5 BoilerSteamCondenser.................................... A-8 A.5.1 Ports structure..................................... A-8 A.5.2 Ports specifications.................................. A-9 A.5.3 Specification Dialog.................................. A-9 A.6 FeedWaterHeater....................................... A-9 A.6.1 Ports structure..................................... A-10 A.6.2 Ports specifications.................................. A-10 A.6.3 Specification Dialog.................................. A-10 A.7 PumpUtility........................................... A-11 A.7.1 Ports structure..................................... A-11 A.7.2 Ports specifications.................................. A-11 A.7.3 Specification Dialog.................................. A-12 A.8 ElectrostaticPrecipitator.................................... A-12 A.8.1 Ports structure..................................... A-12 A.8.2 Ports specifications.................................. A-12 A.8.3 Specification Dialog.................................. A-12 A.9 FGD............................................... A-13 A.9.1 Ports structure..................................... A-13 A.9.2 Ports specifications.................................. A-13 A.9.3 Specification Dialog.................................. A-13 A.10 GGH............................................... A-14 A.10.1 Ports structure..................................... A-14 A.10.2 Ports specifications.................................. A-14 A.10.3 Specification Dialog.................................. A-14 A.11 ControlValve.......................................... A-15 A.11.1 Ports structure..................................... A-15 A.11.2 Ports specifications.................................. A-15 xii

A.11.3 Specification Dialog.................................. A-15 Appendix B Source data B-1 xiii

List of Figures 2.1 Pulverized Coal Power Plant blocs diagram.......................... 6 2.2 Steam cycle flowsheet..................................... 8 2.3 Rankine cycle flowsheet and T-S diagram........................... 8 2.4 Rankine cycle with reheat flowsheet and T-S diagram.................... 9 2.5 Regenerative Rankine cycle flowsheet and T-S diagram................... 10 2.6 Combined reheat and regenerative Rankine cycle flowsheet and T-S diagram....... 10 2.7 Combustion gas concentrations at percent of the theoretical combustion air........ 12 2.8 Typical flue gas treatment line................................. 17 2.9 One element feedwater control................................. 24 2.10 Two element feedwater control................................. 25 2.11 Three element feedwater control................................ 25 2.12 Post-Combustion capture diagram............................... 27 2.13 PCC s absorption flowsheet................................... 27 2.14 Pre-Combustion capture diagram............................... 29 2.15 Pre-Combustion capture absorption flowsheet (AGR).................... 29 2.16 Oxy-Combustion capture diagram............................... 30 2.17 Interaction between MEA and PCC.............................. 31 3.1 Deaerator model in gproms................................. 34 3.2 SCR model in gproms..................................... 37 3.3 Blower model in gproms................................... 43 3.4 Controller model in gproms.................................. 45 3.5 Drum model in gproms.................................... 48 4.1 Design flowsheet model in gproms.............................. 56 4.2 Control flowsheet model.................................... 62 4.3 Megawatt load change and throttle pressure deviation.................... 63 4.4 Load and pressure responses to different tunings...................... 63 4.5 Grid and power plant s load curves............................... 65 4.6 Power load and governor valve stem position......................... 65 4.7 Superheated steam pressure deviation from SP and coal flowrate deviation from 100% load............................................... 65 xv

4.8 Boiler feedwater flow and governor valve s outlet pressure deviation from 100% load.. 66 4.9 Heated feedwater temperature and steam flow deviations from 100% load, in the Heater2. 66 4.10 Condenser s pressure and cooling water flowrate deviations from 100% load....... 67 4.11 Deaerator s and condenser s tank level deviations from SP................. 67 4.12 Condensate valve s stem position............................... 68 4.13 Power load and governor valve stem position......................... 69 4.14 Superheated steam pressure and coal flowrate deviations from 100% load........ 70 A.1 BoilerSubcritical model in gproms.............................. A-2 A.2 GovernorValve model in gproms............................... A-4 A.3 SteamTurbineStage model in gproms............................ A-6 A.4 Generator model in gproms................................. A-7 A.5 BoilerSteamCondenser model in gproms.......................... A-8 A.6 FeedWaterHeater model in gproms............................. A-10 A.7 PumpUtility model in gproms................................. A-11 A.8 ESP model in gproms..................................... A-12 A.9 FGD model in gproms..................................... A-13 A.10 GGH model in gproms.................................... A-14 A.11 ControlValve model in gproms................................ A-15 B.1 Flowsheet of the modelled Pulverized Coal Power Plant s Steam Cycle.......... B-2 xvi

List of Tables 1.1 Electricity market share (%)................................... 2 2.1 Steam conditions in the different power plant critical types.................. 7 3.1 Variables of the Deaerator model............................... 34 3.2 DOF analysis to the Deaerator model............................. 35 3.3 Parameters used in the SCR model.............................. 37 3.4 Variables of the SCR model.................................. 38 3.5 Case to distinguish modes in thescr model......................... 39 3.7 Case to distinguish ammonia types in the SCR model.................... 41 3.8 DOF analysis to the SCR model................................ 42 3.9 Parameters used in theblower model............................. 43 3.10 Variables of the Blower model................................. 43 3.11 DOF analysis to the Blower model............................... 44 3.12 Variables of the Controller model............................... 46 3.13 Set Point assignment modes in the Controller model..................... 46 3.14 Action (Manipulated-Controlled) in the Controller model................... 46 3.15 DOF analysis to the Controller model............................. 47 3.16 Parameters used in the Drum model.............................. 49 3.17 Variables of the Drum model.................................. 49 3.18 DOF analysis to the Drum model............................... 51 4.1 Key models used in the flowsheets............................... 54 4.2 Control models used in the flowsheets............................. 55 4.3 Auxiliary models used in the flowsheets............................ 55 4.4 Key specifications in design mode............................... 57 4.5 Average and maximum of the absolute stream deviations from Alstrom (relative deviation). 58 4.6 Flue gas composition compared to Alstrom (relative deviation, in %)............ 59 4.7 gproms key performance indicators compared to Alstrom (relative deviation, in %)... 59 4.8 Key models used in the flowsheets............................... 60 4.9 Average and maximum of the absolute steam deviations from design (relative deviation). 61 4.10 Parameters used in the control system............................ 64 xvii

4.11 Average and maximum of the absolute stream deviations from operational (relative deviation, in %).......................................... 64 4.12 Part-load key performance indicators compared to full-load (relative deviation, in %)... 68 4.13 Errors in the final steady-state (relative errors, in%)..................... 70 4.14 Key performance indicators compared to the normal LHV (relative deviation, in %).... 71 4.15 Key performance indicators compared to the normal efficiency (relative deviation, in%). 72 B.1 Steam cycle data from Lawrence................................ B-2 B.2 Key performance indicators from the Alstrom report..................... B-3 B.3 Coal ultimate analysis from the Alstrom report........................ B-3 B.4 Flue gas composition from the Alstrom report......................... B-3 B.5 Boiler s streams conditions from the Alstrom report..................... B-3 xviii

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Abbreviations Abbreviation AGR ASU AUSC BFW CCGT CCS DCA DOF DFGD EDF E.ON ESP ETI EU FD FG FGD FWH gccs GGH gproms GQCS HP ID IP IGCC KPI LHV LP LSFO MDEA MEA MSD OSTG P PCC PCPP PI PID PSE RH SCR SH TTD UK USC WFGD xx Description Acid Gas Removal Air Separation Unit Advanced Ultra Supercritical Power Plant Boiler feedwater Combined Cycle Gas Turbine Carbon Capture and Storage Drain Cooler Approach Degrees of freedom Dry Flue Gas Desulfurization Electricite de France E.ON Energy Limited Electrostatic Precipitator Energy Technologies Institute European Union Forced Draft Flue Gas Flue Gas Desulfurization Feedwater Heater CCS system modelling toolkit, based on gproms Gas-Gas Heater gproms ModelBuilder Combustion/Heat Transfer/Gas Quality Control System High Pressure Steam Turbine Induced Draft Intermediate Pressure Steam Turbine Integrated Gasification Combined Cycle Key performance indicators Lower Heating Value Low Pressure Steam Turbine Limestone Forced Oxidized Methyl Diethanolamine MonoEthanolAmine Model Specification Dialog Once-Through Steam Generation Proportional Controller Pos Combustion Capture Pulverized Coal Power Plant Proportional plus Integral Controller Proportional plus Integral plus Derivative Controller Process Systems Enterprise Reheat Steam Selective Catalytic Reduction Superheat Steam Terminal Temperature Difference United Kingdom Ultra Supercritical Power Plant Wet Flue Gas Desulfurization

List of Symbols Latin Symbols Variable Description Units B Bias D Diameter m E Error F Mass flowrate kg/s g n Gravitational constant m/s 2 H Level (tank) m H Head (compression) J/kg h Mass specific enthalpy J/kg I Integral term W K Gain M Mass hold-up kg M V Measured variable N Number of streams n Polytropic index Occ Occupation percentage % OP Manipulated variable P Power W P Proportional term (controller) W p Pressure Pa p ratio Pressure ratio across the unit Q Heat duty W r Reaction mole consume mol/s ratio i,j Ratio between i and j SP Set Point T Temperature K t R Residence time s U Energy hold-up J V Volume m 3 v Velocity m/s M Molecular weight g/mol W Work W w Mass fraction x Mole fraction z Height m xxi

Greek Symbols Variable Description Units α Kinetic coefficient Γ Mole percentage % γ Isentropic index (Blower) γ i,j Stoqueometric coefficient of the component i in the reaction j γ Mass concentration mg/nm 3 Differential h r,i Specific enthalpies of reaction i p Pressure drop or pressure increment η Efficiency % ρ Mass density kg/m 3 τ I Reset time s φ bleed Bleed fraction Subscripts Variable E fluid I i ideal in is iso L lim MAX MIN out P,pol real swt V Description External Fluid Inlernal Component i Ideal Inlet stream Isentropic Isothermal Liquid phase Limit Maximum Minimum Outlet stream Polytropic Actual Switch Vapour phase Superscripts Variable Description BF W Boiler feedwater dry Dry basis j Stream j NH 3 NH 3 stream N Normal Steam Steam Deviation xxii

1 Introduction Contents 1.1 Motivation and Objectives................................ 3 1.2 State of The Art...................................... 3 1.3 Original Contributions.................................. 4 1.4 Thesis Outline....................................... 4 1

On the first three decades of the 21 st century the global energy demand is projected to grow about 1.7% per year. Between the energy investments, the electricity production represents 60%, against oil (19%), gas (19%) and coal (2%). This shows the electricity importance in the energy market. [1] In terms of world s electricity itself, the demand is expected to duplicate from 2000 to 2030, growing at an annual rate of 2.4%. Although, it is expected loss of market share by the coal (essentially to gas), in 2030 it continues to be the main electricity source in the world. The natural gas power plants have higher efficiency than the coal ones, but the coal has the advantage to be more abundant in many parts of the world and to have a more stable price. Other conclusion is that the fossil fuel power stations dominate the electricity sector [1]. Table 1.1: Electricity market share (%) [1]. Electricity source 2000 2010 2020 2030 Coal 38.9 35.6 35.5 36.8 Oil 8.1 6.7 5.4 4.2 Natural Gas 17.4 24.7 30.1 31.5 H 2 fuel cells 0 0 0.1 1.1 Nuclear Energy 16.8 14.4 9.6 8.6 Hydro Energy 17.2 15.9 14.9 13.5 Other Renewable Energies 1.6 2.6 3.4 4.4 Losses 1.5 1.5 1.5 1.5 Between the fossil fuel power stations, the most common are: Pulverized Coal Power Plant - PCPP. Integrated gasification combined cycle - IGCC. Combined Cycle Gas Turbine - CCGT. In the Kyoto Protocol, in 1997, the EU countries committed themselves to reduce the greenhouse gases emissions by at least 5% below 1990 levels until 2008-2012. However this target was redefined to a reduction of 80% until 2050 [2] [3]. Since the CO 2 is the main concern gas between the greenhouse gases, it is imperative to improve technologies to reduce the CO 2 emissions. This will pass for increasing renewable energies and implementing carbon capture and storage (CCS) in the fossil power plants, because the power plants are responsible for around 25% of the global emissions. CCS is an important option in the portfolio of available solutions to combat this problem, because it allows to reduce the CO 2 emissions from fossil systems, significantly [4]. The most important technologies to apply CCS in fossil power plants are: Post Combustion Capture - PCC Pre Combustion Capture Oxy-Combustion Because the coal is fossil fuel most widely used in power plants, and the most unclean, it is especially important to develop the carbon capture and storage in the pulverized coal power plants (PCPP). 2

Although the CCS reduces the efficiency in the energy production in the power plants, investments must be done in this area to improve the technologies and achieve the CCS objective without compromising the electricity sector. At the current state of technology, units retrofitted with carbon capture would suffer a decrease around 12% in the efficiency and an increase between 20 and 30% in the coal consume to supply the same electricity output [5] [6]. Due to this panorama, in September 2011, ETI (Energy Technologies Institute), responsible for projects to improve the energy sector, founded the CCS project to study this problem and to accelerate the carbon capture and storage in UK, a technology that will become increasingly important because the emissions capital penalty will reach the CCS investment and efficiency penalty in applying capture. 1.1 Motivation and Objectives PSE integrated the ETI-CCS project in September 2011 with the objective to build the gccs toolkit in collaboration with important stakeholders in this area, such as E.ON, EDF and Rolls Royce. This tool incorporates the modelling in gproms of power generation and CO 2 capture, compression, transmission, injection and storage. The final tool will be important to study this new theme. For example, it will allow to design, to simulate, to control and to optimize the full chain. The models flexibility and robustness is really important to let the all chain respond to different consumers demands as quick as possible. Since the gccs project is in the pulverized coal power plant (PCPP) modelling phase, this thesis is incorporated in the construction of a pulverized coal power plant modelling kit, the most problematic power plant in terms of CO 2 emissions. The thesis objective is to design a power plant with operational data and to simulate the operation of the designed power plant, with control incorporated. It is used operational data from a subcritical PCPP s steam cycle ([7]), it is implemented one of the different types of control (boiler following control) and the simulations consist in set point changes (daily cycle, e.g.) and disturbances to the system. To do the final flowsheet several gccs models are required. Some of the models that need to be developed to the gccs library are done in the scope of the thesis: Deaerator, SCR, Blower, Controller and Drum. 1.2 State of The Art A lot of work has been developed in the scope of power plant modelling. Lots of reports focused in performance studies to the different kinds of power plants have been done. In these studies the performance of power plants when connected to the several CCS technologies is commonly analysed, both for retrofit and for newly built. An example of this kind of study applied to a PCPP is a report done by the US Department of Energy. Using test data, it was developed a steady-state model for the boiler of an existing power 3

plant, and it was used to study the base case (power plant without capture) and three capture concepts [8]. Also developed by the US Department of Energy and inserted in the problem of CO 2 capture, is the study of cost and performance of a power plant with and without capture, using for it the ASPEN Plus modelling program. For example, PCPP with different technologies and conditions were target of this study [9]. In terms of power plant control modelling one interesting work was developed is the University of Rostock. The dynamic model was focused on the water/steam circuit, the combustion chamber and the coal mills. It s based on a real 550 MW power plant (Rostock), and it was develop using a non-commercial Modelica library ThermoPower [10]. Another case found is the modelling and control of a supercritical coal fired boiler, where it is applied the coordinated control system to control the steam generation s system [11]. By way of conclusion, the power plants have been the target of several modeling projects and the most recent developments have been in the framework of CCS. The gross of the models done for power plants are linked to the study of performances, but there is also some work done in dynamic modelling with control to simulate shut-down, start-up and load changes. 1.3 Original Contributions The thesis presents the modelling of a pulverized coal power plant and some of its units, using the gproms as modelling program, a work never done before in this software. Besides that, the thesis is inserted in an innovative project in the framework of CCS. It was modeled some models that compose the power plant, which were connected together to represent the real power plant. The main objective of this thesis is to simulate dynamic control and to study the performance at different operational conditions (different loads, e.g.), something never done before nor in the scope of the ETI-CCS project nor in gproms. 1.4 Thesis Outline This thesis is organised in the following way. It is presented, in the Chapter 2, the background on the subject, describing the pulverized coal power plant and its equipments, as well as its control system. It was also done a brief description of the CCS technologies. The next Chapter (3) consists in the mathematical description of the several developed component models. In the chapter 4 is presented the main objective of the thesis. Here are explained the flowsheet models for design, operational and control modes and submitted the results. To finish this chapter it s done some sensitivity analyses to the system. The conclusions and future work are summarized in the 5. 4

2 Background Contents 2.1 Pulverized Coal Power Plant............................... 6 2.2 Pulverized Coal Power Plant Control.......................... 21 2.3 Carbon Capture and Storage............................... 26 5

2.1 Pulverized Coal Power Plant Pulverized Coal Power Plant is a thermal power plant that uses the chemical energy of the coal to produce electric energy. It starts by converting the chemical energy of the coal (heat of combustion) into thermal energy (steam), then converts the thermal energy into mechanical energy (turbines rotation) and finishes producing electric energy in the generator using the mechanical energy [12]. The Pulverized Coal Power Plant is one of the most used methods to produce energy, and has the following advantages [12]: High efficiency (table 2.1) Lower capital cost Adaptability to burn every types of coal Technologies to clean the flues gas are established Low consume of water (closed cycle minimizes the mass lost) Easy and reliable access to coal in many parts of the world Energy efficiency (same as net efficiency) of a power plant is the useful work output over the heat input. The heat input is the coal chemical heat and the useful work is the electrical power produced, deducting the electrical power used (e.g., pumps and refrigerating tower). The thermal (or gross ) efficiency does not take into account the power spent for own use [6]. This type of power plant must have the following units (figure 2.1): Figure 2.1: Pulverized Coal Power Plant blocs diagram [12]. Regarding the current technologies, the power plant can be subcritical, supercritical, advanced supercritical or ultra supercritical. In the first case the steam conditions are bellow the critical point (374 C and 220bar), while on the other three types of power plants the steam is above those conditions. On the following table (2.1), it is presented the typical steam conditions, efficiencies and CO 2 emissions for the four cases: 6

Table 2.1: Steam conditions in the different power plant critical types [6] [13] [14] [15]. Critical Type T ( C) p (bar) Efficiency LHV (%) gco 2 /kwh Subcritical 455 <220 38-40 900 Supercritical 538-566 >220 40-42 740 Ultra Supercritical (USC) 593-624 593-621 43-46 600 Advanced Ultra Supercritical (AUSC) 700-760 375-380 >45 N/A The turbine cycle efficiency is improved with high temperatures because this will reduce the coal consumption, gas emissions and capture costs, which is especially important when CCS is applied. However, the steam generator, turbine and piping system must be of nickel-based alloys materials, and that s why the supercritical power plant is the most used until now [13]. Another advantage of the advanced ultra supercritical power plants is the opportunity to apply double reheat system, due to the high pressure steam. However, this idea is also in study for now. Obviously, efficiency is dependent on other factors, and the coal type is an example. A plant operating with high-moisture and high-ash coal can t have the same efficiency of one using low-ash and low-moisture coal. Carbon capture also decreases the efficiency (the penalty is 12%) [6]. The progress in the ultra supercritical projects will be very important to allow the power plants to maintain the efficiencies when the CCS is applied. The heat integration cycle is also a key factor to improve the efficiency, because it interferes on the coal and condenser utility consumes. 2.1.1 Steam Cycle In figure 2.2 a typical flowsheet of the power plant steam cycle is represented. The steam drawoffs from the turbines enter a heat transfer cycle, where their heat is integrated, and where they are mixed to enter in the boiler as boiler feed water. The boiler feed water enters boiler to produce the superheated steam, that is used in the High Pressure turbine. Furthermore, there is a reheat cycle that consists of a recirculation of a high pressure exhaust steam (cold reheat steam) to the boiler be heated into hot reheat steam, which is used in the Intermediate Pressure Turbine. Part of the IP turbine last draw-off is used in the Lower Pressure turbine. 7

Figure 2.2: Steam cycle flowsheet [16]. There are some applicable types of steam cycles to the pulverized coal power plant. The basic cycle is the Rankine cycle, with the following flowsheet and respective T-S diagram (figure 2.3): Figure 2.3: Rankine cycle flowsheet and T-S diagram [17]. The ideal basic steps are: Isentropic expansion of superheat steam (3) in a turbine, decreasing its pressure and temperature (4). Condensation of the turbine s exhaust steam (4) to saturation point (1). Isentropic Compression from low (1) to high pressure (2). Vaporization and heat of the high pressure liquid (2) at constant pressure in the boiler to superheat conditions (3). It is better to apply this cycle in the power plant instead of the Carnot Cycle, because avoids water 8

in the pump and in the turbines (1 and 4). When steam reheat (4 to 5) is added to the cycle, it is named Rankine cycle with reheat and the main objective is to have the condenser at lower pressures avoiding, or reducing, liquid droplet formation in the turbine (6 in spite of 4 ). So, it is possible to achieve lower pressures in the last turbine and produce more work. Although the thermal efficiency isn t significantly increased because the heat spent in the boiler will also increase. The flowsheet and its thermodynamic diagram for this cycle is (figure 2.4): Figure 2.4: Rankine cycle with reheat flowsheet and T-S diagram [17]. The regenerative cycle insertion (Regenerative Rankine Cycle) avoids the need to condensate all the steam, saving energy in the condenser. This amount of saved energy is used to integrate the draw-offs (draw-off 6 heats the condensate 2), heat the boiler feedwater (3) and use less coal in the boiler. Because of the draw-offs, the work output is decreased but even this way the cycle thermal efficiency increases, because the condenser cooling duty and the boiler coal flowrate are reduced. Generally, the more feedwater heaters, the higher the efficiency. In figure 2.5 the flowsheet and T-S diagram are represented. Combined Reheat and Regenerative Rankine Cycle is the best and the most widely used cycle, and is illustrated in the figure 2.6. In the steam turbines the inlet superheated steam (6) and the hot reheat steam (8) undergo isentropic expansions that generate saturated or superheated steam (a, b). The last stage is an exception, since the exhaust steam (9) may have a vapor fraction greater than 85-90% [18]. The last turbine stage exhaust steam (9) is condensed in the condenser at constant pressure until the saturation point (1), while the other draw-offs (a, b) are integrated with the condensate in the feedwater heaters to heat the boiler feedwater (5). In this process, the isentropic compressions in the pumps also takes place (2, 4). Both the superheat (6) and reheat steam (8) are heated at constant pressure (5, 7), and are then sent to the expansion turbines. It is in the condenser that the heat is removed(q L ) using a cold fluid and the provided heat come 9

Figure 2.5: Regenerative Rankine cycle flowsheet and T-S diagram [17]. Figure 2.6: Combined reheat and regenerative Rankine cycle flowsheet and T-S diagram [17]. from the coal (Q H ). There is also the work produced in the turbines (W T ), converted to electric power in the generator, and the work spent in the pumps (W P 1 and W P 2 ). 2.1.1.A Boiler The steam is generated in the boiler, using the heat generated by burning coal. In the most used steam cycle (with regenerative and reheat cycles), superheated and hot reheat steam are generated, which are high pressure and intermediate pressure steams, respectively [19]. Water Side The superheated steam is produced by heating and boiling the boiler feed water above the saturation temperature. The water-steam mixture comes from the boiler wall tubes and is separated in a steam drum (partial steam generation), which consists of a large cylindrical vessel. The steam is 10

then heated in the superheater(s), and the water recirculates to the boiler tubes by natural or forced circulation. The wall tubes increase the transfer heat and help to avoid the furnace material to high temperatures. In spite of a steam drum, the OTSG system can be used ( once-through steam generation ), which has a coordinated control of the water flow and of heat input to assure that no water leaves with the steam. Futhermore, the boiler includes an economizer that pre-heats the boiler feed water, before entering the boiler wall tubes, using waste heat that remained in the flue gas. This flue gas is typically between 180 and 260 C, and most of the economizers are able to raise the feedwater temperature from 11 to 17 C. The flue gas cooling is limited by the dew point, around 163 C, to avoid condensation and formation of corrosive acids (mainly carbonic acid and sulfuric acid) [20]. The hot reheat steam is obtained by heating the cold reheat steam in the reheater. The superheaters and reheater consist of bundles of tubes, with steam passing inside the tubes and flue gas passing outside, and the heat is transferred by convection. Flue Gas Side The boiler heat comes from the combustion of pulverized coal with air, in the furnace. In the furnace, the flue gas evaporates the feedwater in the wall tubes, and then it passes to the convection zone, where the flue gas contacts with the superheaters, the reheater and the economizer heat surfaces. When it leaves the boiler, it passes through the air pre-heater. An important variable is the coal s LHV (Lower Heating Value), that measures its specific combustion energy. In the furnace, pre-heated hot air and burners are used to burn the pulverized coal. The air is classified as primary or secondary air. The primary air is 20-30% of the total air, and is used to dry and pneumatically transport the coal to the burners, while the remaining air (secondary air) is directly mixed in the burners with the coal/primary air mixture. To burn pulverized coal the type of furnace used is a chamber fired furnace and the type of burners are chosen according to the conditions [12]. The following picture (figure 2.7) illustrates the influence of the excess air in the combustion process. 11

Figure 2.7: Combustion gas concentrations at percent of the theoretical combustion air [20]. To a low quantity of air (below 100%) the combustion is not complete and that is why the CO level is high, while when the theoretical air approximates 100%, the efficiency increases and the CO is converted rapidly to CO 2. However, the best level involves an excess of 15-20%, because the CO reaches ppm level, which means an optimal efficiency. In this range, the CO 2 level decreases due to dilution in the excess air [20]. For excess levels from 25 to 45%, the NOx formation increases, and for higher levels the temperature decreases and the NO x formation decreases [21]. In order to have a complete burn, the furnace must fulfill the following conditions [12]: The flame temperature must be enough to ignite the coal and air. The coal and the air must be thoroughly mixed. The needed residence time of the coal must be meet. The correct air fuel ratio must be achieved. The equipment must have means to hold and discharge the ash, discontinuously. The control system must be capable to regulate the coal feed flow. The gross of the ash is removed in the bottom grate of the furnace and since it is too hot, it s common to quench it with water. The dust that remains in the flue gas after the dust collector is fly ash, and is removed in the dust collector [12]. The unburnt carbon exits in the bottom ash, and may be from 80 to 98%, depending on the residence time of the coal in the furnace [8]. 2.1.1.B Governor Valve The Governor Valve is a key unit to control the power plant, being located in the superheated steam that leaves the boiler and goes to the first HP turbine stage. It operates the steam valve, adjusting the flow according to the control objectives. Besides the steam flow, the pressure drop changes too, which will modify the turbine rotor speed and, consequently, the power achieved. 12

This operation is a throttling process, since there occurs a pressure drop, the temperature decreases, but no energy change occurs (isenthalpic) [22]. 2.1.1.C Steam Turbine The steam turbine is an important equipment because it produces the mechanical energy. There is usually a high pressure (HP), an intermediate pressure (IP) and a low pressure (LP) steam turbine, each one with varied number of extraction points. The extraction points location is a function of the power plant optimization, since it will change the work produced and the integrated heat in the heat integration zone. The force applied in the turbine is proportional to the change of the momentum, so the principle of the turbine is to use the high velocity of the jet steam to impact the turbine s curve blades and to move them. The steam enters the turbine through a nozzle, where the pressure falls and is converted into kinetic energy, resulting in a high velocity jet [12]. The turbine is designed to maintain the steam velocity and not to produce power, if the blade is locked. On the other hand, if the blade is allowed to speed up the power increases and the outlet velocity decreases due to the momentum change that caused the force. The power reaches the maximum when the blade velocity is 50% of the steam velocity, at which the outlet velocity is near zero. The turbine includes a row of nozzles, a row of moving blades and the casing (cylinder). Nowadays, on the PCPP it s always used single pressure and reheat turbines. The single pressure is the most common (there is a single source of steam supply), and the reheat is used in the reheat cycle (the steam is taken from, reheated and returned to the turbine). In terms of heat rejection, regenerative and condensing turbines are used, the first to send draw-offs to the heat transfer cycle and the second to be used on the last stage. The condensing turbine has its exhaust pressure fixed by the condenser. If there is a capture plant, intermediate pressure draw-off is usually sent to its reclaimer. In an isentropic expansion there aren t energy losses due to friction or other thermodynamic losses, which means that the steam entropy doesn t change. This is a good assumption to calculate the ideal power (equation 2.1) [22]: W is = F (h in h is,out ) (2.1) To calculate the actual power, it s used the isentropic efficiency, which relates the actual work with the work obtained in the ideal case (equation 2.2)[22]: η is = W real W is = h in h out h in h is,out (2.2) 2.1.1.D Generator The generator is directly coupled to the steam turbine and converts the turbines rotating mechanical power into electrical power to supply to the grid. The generator rotor is magnetized and its rotation generates the electrical power in the generator stator. 13

2.1.1.E Heat Transfer Cycle The heat transfer cycle has the simplified objective of mixing all the turbine steam draw-offs, integrating their heat, and sending the material to the boiler as boiler feed water. It s also named the regenerative cycle, and it was described in section 2.1.1 [23]. Condensate is the water leaving the condenser and passing through the low pressure feedwater heaters, while the water leaving the deaerator and passing through the high pressure feedwater heaters is called boiler feedwater. In most of the modern heat cycles there are feedwater heaters, a condenser and a deaerator, which use extracted steam from the steam turbine. The turbines draw-offs have different temperatures and pressures, due to the different outlet pressure in each turbine stage. Because of this the draw-offs are used to heat the feedwater in different feedwater heaters. After the integration in the low pressure feedwater heaters line, the condensates are mixed in the deaerator. The deaerator s outlet is sent to the boiler, after being heated in the high pressure feedwater heaters line. Condenser The condenser is the single unit inside the heat integration cycle responsible of removing heat by an external utility. The amount of heat duty is crucial to the power plant operation to allow the heat integration and the draw-offs condensation in the consequents feedwater heaters, and that s why the saturated condensate pressure must be very low. The fact that the work output in the turbines and, consequently, the power plant efficiency, increase with lower exhaust temperatures is also a reason to lower the condenser pressure [12] [23] [24]. Usually the condensation heat removal is done using cooling water, and only in few occasions, when water isn t available, air is used as a cooler. If water is used it s advantageous to have a cooling water closed cycle to control water quality. The most common condenser type is a tube and shell heat exchanger, with the water passing through the tubes and the steam through the shell from the top downward, which is characterized as a surface condenser. Some of the advantages of this type of condenser are the possibility to use impure water because it doesn t contact the condensate, to use to condensate as boiler feedwater and to do high vacuum. Although it requires more space, the capital cost is larger and the maintenance and running cost is high. Another type of condenser is the jet condenser, which mixes directly the steam and the cooling water. Feedwater Heater The number of feedwater heaters depends mainly on the size of the turbines, on the inlet and exhaust steam conditions, on the overall plant size and on the economic considerations. Because the number of feedwater heaters influences the heat integration, it plays a key role and must be part of the design to optimize the plant efficiency [23]. 14

The feedwater heater must have water passing through the cold side (tubes) and draw-off steam passing for the hot side (shell), in counter current. Besides that, it can have one inlet as drains, which is the draw-off steam condensate from other feedwater heater (with higher pressure steam). In this case, the drain and the draw-off steam are mixed in the hot side, and the drain is vaporized due to the pressure decrease. In the feedwater heater the steam condensates in its chamber and the cold steam passes through the tubes. Along the unit there are three main zones [25]: Desuperheating: cooling of the superheated steam to the saturation point. Condensing: energy from the steam/water mixture condensation is used to preheat the boiler feedwater. Sub-cooling: used to capture additional energy from the liquid. It is possible to exchange the heat mixing all the streams ( open FWH). However, it s not advantageous because it will require another pump in the outlet. In the shell side it must be maintained a liquid level that optimizes the heat transfer from the steam to the boiler feedwater. The performance of the feedwater heater can be evaluated measuring the feedwater temperature rise, the terminal temperature difference (TTD) or the drain cooler approach (DCA). The first one is the temperature increase in the cold side, while the second one is difference between the draw-off steam saturation temperature and the cold side outlet temperature. DCA is the difference between the drains and the inlet cold side temperatures. Deaerator The main Deaerator s objective is to remove dissolved gases from the water, to avoid the accumulation due to gas leakage into the system. That s important because, for example, the excess oxygen and carbon dioxide increases the metal corrosion. To prevent corrosion (carbonic acid) volatile neutralizing amines are usually used to adjust the ph. In order to remove oxygen sodium sulfite, Hydroquinone Hydrazine, Diethylhydroxyamine and/or Methyl ethyl ketoxime are used [20] [23] [24] [26] [27]. Besides the gas removal, it s also usual to remove the hard salts here. The hard salts deposit in the surfaces ( scale ) and decrease the heat transfer quality in the heat exchangers, preventing and adequate flow the tubes and forcing blowdown in the boiler. Calcium and magnesium bicarbonate form an alkaline solution ( alkaline hardness), and are easily removed by boiling ( temporary hardness). The most problematic are the calcium and magnesium sulfates, chlorides and nitrates ( non alkaline hardness) that must be removed with reagents (Polyphosphates and Sodium Meta Phosphate). The secondary purposes of this unit are to accumulate water to feed the boiler (usually 5 minutes of feedwater content), and to provide proper suction conditions for the boiler feed pump. It receives the condensates to be treated, that come from the condenser and/or feedwater heaters, and a steam stream (turbine or boiler draw-off). The deaerator is composed by three sections: the heat section, 15

the vent condenser and the storage section. The gases are removed by two mechanisms that occur in the heating section. On the first one, the water is heated in the heater section, in direct contact with the steam. This decreases gases solubility in water due to reduction of gas partial pressure in the gas phase; On the second mechanism, the water enters the deaerator head through a nozzle (spray type deaerator) and contacts with the rising steam to increase the mass and heat transfer rate, in order to remove the gases from the water to the steam, to achieve the saturation point and to condensate the majority of the steam. The same principle can be achieved passing the water through a set of layers in counter current with the steam (layer type deaerator). In the vent condenser the incoming condensates pass through the tubes of a heat exchanger mounted on the top of the deaerator to condensate part of the steam that escaped through the vent. The heated and deaerated condensate, along with the condensate steam, falls to the storage section located below the deaerator. This last section has the purpose of accumulating feedwater. The steam that escapes with the gases is compensated with make-up water, which has to be externally treated. Pump The pump is used to transport the water in the heat cycle. Usually it s only needed one pump to pump the condensate and another to pump to the feedwater, through the FWH tubes. This is not true if there is any open feedwater heater which requires a pump on its outlet. Pumps increase the velocity, the pressure, the mechanical energy, or all of them. The most used pumps are positive-displacement and centrifugal pumps. The first applies pressure by a reciprocating piston or rotating member in a chamber, which is alternately filled and emptied of liquid. The centrifugal one uses rotational high velocities and convert the kinetic energy into pressure energy. The work delivered to the fluid is calculated from the mass flowrate and the head development (equation 2.3) [28]: W fluid = F H p (2.3) Power supplied to the pump is calculated with the efficiency (equation 2.4) [28]: W real = W fluid η (2.4) The head comes from the Bernoulli equation and is(equation 2.5) [28]: H p = p ρ + g nz + α v2 2 (2.5) The pumps represent a large fraction of the auxiliary power consumed in the plant, since their flows are very big and the boiler feedwater pump pressure increase is from low to high pressures. Water make-up [20] Although the steam cycle is a closed cycle, there are material losses due to, for example: 16

Boiler blowdown Deaerator steam vent losses Unreturned condensate (lost in the vacuum system) Leakage Because of these losses a water make-up is performed in the condenser tank. This make-up water must be chemically treated. 2.1.2 Flue Gas Treatment The flue gas coming from the boiler is treated before being sent to the capture plant (with CCS) or to the stack (without CCS). In the power plant, the ash, the NO x and the SO 2 flue gas content are all removed to a concentration below the limit. Ash is mainly coal s non-combustible matter and is partially removed in the bottom of the furnace (bottom ash). The ash leaving the furnace in the flue gas is named fly ash. SO 2 emissions are due to the coal s sulphur, while NO x appears from the air s N 2 combustion at high temperatures. The first one can be controlled limiting the allowable sulphur content in the coal, and the second one by manipulating the combustion. The other major pollutants are CO 2 and CO. The first is removed in the CCS process, while for the second one the ammount is minimized by manipulating the combustion process. The carbon monoxide in the flue gas must be in the range of 0 to 400 ppm, and is a measure of the combustion s efficiency. For the flue gas treatment in the power plant side it is used a SCR (Selective Catalytic Reduction), an ESP (Electrostatic Precipitator) and a FGD (Flue Gas Dessulfurizer). In the gas line there is also an air heater, a gas-gas heater and a blower. The following picture (2.8) is an example of a configuration of the flue gas treatment line. Figure 2.8: Typical Flue Gas treatment line [19]. 17

2.1.2.A Electrostatic precipitator The flue gas that comes from the furnace has particulate matter that has as majority component fly ash, which must be collected. To this end, a Electrostatic Precipitator (ESP), Fabric Filters (Baghouses), mechanical collectors and venture scrubbers are employed. The most used is the dry electrostatic precipitator [19]. Dry Electrostatic Precipitator The ESP creates an electric field (between CEs - positive polarity - and DEs - negative polarity) where the flue gas passes, and the particulates are electrically charged. The negatively charged ash particles migrate toward the CEs. Depending on the particles size, the electrification may be easy to perform and the flue gas velocity is a key factor to the particles have enough residence time to be charged and collected. Plates are installed to collect the ash layer, and this particle layer must be discontinuously removed (by raping) to prevent the ash to reenter in the flue gas. The ash falls from the plates to hoppers. 2.1.2.B Selective Catalytic Reduction Because the NO x contributes to acid rain and ozone formation and to health concerns and because the NO x emissions are very tied to combustion processes, the NO x must be removed from the flue gas. SCR is the most effective process, allowing to reduce the levels by 90% or greater. The NO x is converted into water vapor and nitrogen, in a catalytic gaseous reaction, reacting with ammonia. The predominant reactions are [19]: 4NO + 4NH 3 + O 2 4N 2 + 6H 2 O NO + NO 2 + 2NH 3 2N 2 + 3H 2 O (2.6a) (2.6b) The flue gas NO content is much greater than the NO 2 content, and the NO 2 is preferentially converted (greater selectivity to NO 2 than to NO) [29] [30]. For a good operational performance it s important to consider the factors: Reaction temperature range Residence time (space velocity) Degree of mixing between the reagent and the flue gas Catalyst activity, selectivity and deactivation Pressure drop across the catalyst NH 3 /NO x Stoichiometric ratio and ammonia slip The reagents most commonly used (ammonia) are anhydrous ammonia, aqueous ammonia and urea, being in all the cases diluted with air (95% of air), in a mixing chamber. The catalyst used can be metal catalysts or zeolites. The most common is a mixture of TiO 2, V 2 O 5, WO 2 and MoO 3 ( titania - 18

vanadia ). Usually the reactor is a vertical vessel with fixed catalyst layers, but can also be a fluidized bed. The optimal temperature depends on the catalyst and on the flue gas composition, but for most of the used catalyst (metal oxides) the optimum temperature is between 250 and 427 C. At temperatures below the optimal range the activity is low, NO x is not efficiently removed and ammonia passes through the SCR (ammonia slip). On the other hand, for temperatures above the optimum the selectivity is limited and the catalyst is deactivated. Depending on the localization of the unit, it can be called: Hot Side/High Dust: The NO x treatment is done between the boiler and the ESP, taking advantage of the flue gas temperature Hot Side/Low Dust: In units with hot side ESP the SCR can be located between the ESP and the air heater avoiding problems of the ash in the catalyst Cold Side/Low Dust: When the SCR is installed in retrofit and there is no other way, the SCR can be installed between the air heater and the FGD. Because of the low temperatures, the unit must include a method to increase the flue gas temperature: high pressure steam heat exchanger, gas-to-gas air heater and / or duct burners. The advantage is that this conformation allows a constant temperature when the boiler load changes, what makes the SCR control easier 2.1.2.C Air Pre - Heater Because the temperature of the flue gas leaving the SCR is still quite high,the flue gas is cooled in the air heater, where the air is pre-heated before entering the furnace. The air and the flue gas exchange heat in counter current [20]. It s also important to heat the air because it s necessary to dry the coal and increases the boiler efficiency. The most used is the regenerative type, which has a rotative cylinder that transfers heat from the flue gas to the air. The major operating problem is the air leakage to the flue gas side that is between 5 and 15%. Because the air passing through the boiler is fixed, the flue gas will increase and with it the energy costs in the flue gas blower. 2.1.2.D Gas - Gas Heater The gas-gas heater (GGH) is used to integrate the heat between the flue gas that enters and the flue gas that exits the FGD unit, using the exothermic heat of the desulphurization reactions. It s really important to control the temperature entering the unit, because it s a key variable. 2.1.2.E Flue Gas Desulfurization Another important impurity to be removed from the flue gas is the SO 2. This can be done either by wet flue gas desulfurization (WFGD) or by dry flue gas desulfurization (DFGD), being the first one the main technology (around 85% of installed capacity) [19]. The most used reagent in WFGD is limestone, but other alkaline reagents can be used. The process can be non-regenerable or regenerable, with the difference of renewing the reagent and pro- 19

ducing a byproduct (e.g., elemental sulphur) in the second case. The most popular is the Limestone forced oxidized (LSFO), which is a non-regenerable one. Limestone forced oxidized (LSFO) This process uses limestone as reagent and is composed of four steps: reagent preparation, SO 2 absorption, slurry dewatering and final disposal. The reagent is slurry of limestone and the unit to do the absorption and SO 2 removal is an absorber where the ascending gas reacts with the descending reagent slurry in perforated trays. Hydrociclones and vacuum filters separate the water from the gypsum being possible to obtain a cake with 10% moisture. The water can be reutilized to prepare the reagent stream. In terms of chemistry, an acid-base reaction takes place in aqueous environment, forming mainly calcium sulfate dehydrate (CaSO 4.2H 2 O) and calcium sulfite hemi-hydrate (CaSO 3.1/2 H 2 O), which represent the gypsum. 2.1.2.F Blower The blower compresses a gas in order to transport it through the downstream units, and it s also named fan. In the PCPP it is usual to have Forced Draft (FD) blower in the air stream that feeds the furnace, while in the flue gas it s often used an Induced Draft (ID) Blower. Typically the ID Fan controls the furnace air flow and FD Fans controls the furnace pressure[19]. If the compression isn t isothermal, the temperature rises, which has a number of disadvantages. The work increases with the temperature and excessive temperatures lead to problems with materials of constructions and lubricants. This temperature rise increases with the pressure ratio. However, since the pressure ratio in blowers is typically small, the adiabatic temperature rise is not large and no special provision is made. Because the mechanical, kinetic and potential energies don t change appreciably and assuming that the compressor is frictionless, the ideal work can be calculated by (equation 2.7) [28]: W ideal = pout p in dp ρ (2.7) To calculate the actual power it s used the blower efficiency, which is between 80 and 85% to reciprocating blowers and up to 90% to centrifugal blowers. Isentropic compression For ideal gases the relation between the density and the pressure between the inlet stream and a general point is given by (equation 2.8) [28]: p ρ γ = p in ρ γ in (2.8) 20

Using the equations 2.8 and 2.7, the ideal isentropic work equation becomes (equation 2.9) [28]: [ (pout ) 1 1/γ p in γ W is = 1] (2.9) (γ 1)ρ in p in Isothermal compression With complete cooling in order to maintain the temperature, the relation between the pressure and density is (equation 2.10) [28]: p ρ = p in ρ in (2.10) Substituting the density into the equation 2.7 it s obtained the isothermal work (equation 2.11)[28]: W iso = p ( ) in pout ln (2.11) ρ in Polytropic compression p in In large compressors the path of the fluid is between the isentropic and isothermal compression. The relation between the density and pressure is (equation 2.12) [28]: p ρ n = p in ρ n in (2.12) With the polytropic index being (equation 2.13) [28]: n = ln(p out/p in ) ln(ρ out /ρ in ) The polytropic work equation is (equation 2.14) [28]: p in n W pol = (n 1)ρ in [ (pout p in ) 1 1/n 1] (2.13) (2.14) For a blower it s possible to have a pressure increase of 1bar [31]. Because the pressure increases are low, there isn t cooling and because of that the better compression to describe he blower is the isentropic one. 2.2 Pulverized Coal Power Plant Control Control strategies are vital for the power plant to be able to have a robust and quick response to the energy demands, maintaining a high efficiency. It s also very important to operate in safe conditions. On the flue gas side control has the objective of maintaining the optimal conditions on the furnace and of achieving the proper removal efficiency on the treatment units. However this side s control isn t detailed in the thesis because it was only implemented control on the water cycle. For the steam cycle a superficial study was carried out for all the systems and unites. 21

2.2.1 Boiler / Turbines System Control The boiler and turbines must be controlled as a coordinated system, to optimally achieve the power requirement, maintaining a stable pressure and temperature in the boiler. As the most popular control modes there is the boiler-following control and the turbine-following control. There are also the coordinated boiler turbine control and the integrated boiler turbine-generator control, which are more complex control systems[19]. This system has the purpose to control the electric power and the superheated steam pressure leaving the boiler, using for it the firing rate (coal flowrate valve) and the governor valve to manipulate them. 2.2.1.A Boiler Following Control In this mode the boiler responds to turbine operating changes. The power plant load demand is responsibility of the throttle pressure control system, which changes the turbine valves positioning. The changes in the valve(s) will change the boiler s load that will be reposed by modifying the boiler firing rate. This system has the advantage of being quicker, but it s more unstable. In fact, the boiler stored energy allows to achieve rapidly the energy demand. However, the firing rate will take time to replace the pressure in the boiler (the coal handling units have very slow dynamics), what will unsettle the steam pressure and temperature. 2.2.1.B Turbine Following Control In turbine following control the turbines follow the boiler control system. The energy load is accomplished by changing the firing rate in the boiler, while the boiler pressure is maintained by the throttle pressure control system. This operating mode is slower because the energy will be steadily changed in parallel with the slow firing rate dynamic. However it has the advantage of stabilizing the boiler pressure because the turbines will follow the slow firing rate changes, adjusting the valves to the load. 2.2.1.C Coordinated Boiler Turbine Control This system combines the boiler following control and turbine following control in order to take advantage of their advantages and minimize their problems. 2.2.1.D Integrated Boiler Turbine - Generator Control The integrated boiler turbine-generator control controls several pairs of controlled inputs, using ratio control. 22

2.2.2 Boiler Control The steam outlet temperatures, the steam drum level and the boiling pressure (equivalent to the superheat pressure) are controlled in the boiler. The temperatures and level controls are explained in this chapter, while the pressure is controlled in the boiler/turbines system (section 2.2.1). 2.2.2.A Superheat and Reheat Steam Temperature Control The steam temperature maintenance is also important, for example, for a safe and efficient operation in the turbines. This variable is disturbed for the load changes, for example. To control the temperature there are two distinct strategies: water side or gas side.[19] [32] Water side control In this strategy the operation consists in decreasing the steam temperature in a desuperheater that can be located between two superheaters or in the last superheater outlet. Desuperheaters are contact or spray type, while the attemperator is a non contact shell type heat exchanger. There are the following options: Desuperheater - spraying cold water: injection water is used as manipulated variable to cool the steam and control its temperature. The injection water is a draw from the main feedwater stream, before it enters the economizer or before it enters the feedwater heaters. Attemperator - Diverting part of the steam: part of the superheated steam is diverted and cooled in an attemperator. The amount of steam diverted is the manipulated variable, to control the main stream temperature. Attemperator - Diverting part of the feedwater: part of the feedwater is diverted to an attemperator where it cools the superheated steam, and controls its temperature. For the water side one stage and two stages are possible. In the first case, a simple feedback controller is applied, while for the two stages there are two controllers in series, one for each desuperheater. For large size boilers, it s usual to split the total saturated steam, to control them with a two stage system, and then join them together. Fire side control This methodology consists in changing the flue gas conditions, either the flowrate or the temperature. There are the following options: Excess air control: The excess percentage of air is manipulated in order to control the steam temperature, changing the heat transfer. The heat transfer changes due to the combustion efficiency dependence with the air. Flue gas by-pass control: with the flue gas by-pass it s manipulated the quantity of flue gas passing through the superheaters. 23

Adjustable burner or burner tilting control: the burners are tilted up or down, changing the flue gas temperature entering the superheater. 2.2.2.B Boiler Drum Level Control One-Element Feedwater Control In single element control, the level is controlled changing the water flow. The only measured variable is the level and the controller is usually a proportional controller. This system performance is affected by swell and shrink phenomena.[19] [33] The swell is the decrease of the density of the water/steam mixture in the drums, and is caused by the increase of the steam flowrate which reduces the pressure. The shrink is the opposite of swell. These phenomena are problematic is when rapid steam demand change occurs, because the level measurement will provide the contrary indication of the water flow demand. For example, if the steam flowrate increases much, the water is supposed to increase. However, because the density decreases ( swell ), the level may increase and the flowrate of water provided would be lower. Due to this problem, this control system is usually only used in small boilers, where the load changes are small. Figure 2.9: One element feedwater control. [32] Two-Element Feedwater Control The two-element control uses the steam flowrate measurement in addition to the level measurement, to avoid the swell and shrink problem. The two variables are usually controlled using feedforward-plus-feedback cascade control. Variations in the steam flow will adapt the feedwater flow and the level is measured to changes caused by discrepancies in the flows. 24

Figure 2.10: Two element feedwater control. [32] Three-Element Feedwater Control In the three-element control it s measured the feedwater flowrate, in parallel with the level and the steam flowrate. The steam flowrate is compared with the feedwater flowrate in order to equal both. In this system it s possible to change the water and steam speed, by changing the steam set point Figure 2.11: Three element feedwater control. [32] 2.2.3 Heat Transfer Cycle Control 2.2.3.A Condenser Control The crucial control is the pressure control because it will be the key factor to allow the integration cycle and to fix the last turbine exhaust conditions. The cooling water flowrate acts as manipulated variable [34] [35]. That s also important to control the condenser tank level, in order to assure the condensate flow. This control is done manipulating the make-up water feed to this tank. 2.2.3.B Feedwater Heater Control The most important control aspect in the feedwater control is a precise and reliable level control to all operating conditions. For example, if the level increases and the tubes become submerged, heat is transferred to the condensate rather than the tubes, resulting in poor heating efficiency. On the other side if the level decreases and there is no drain, steam blows through and the FWH doesn t condense the turbine draw-offs[36]. For this control, historically, it has been used mechanical displacement type level systems with mechanically driven pneumatic controllers. To eliminate density problems, the drains temperature can be measured and taken in account in this control system to eliminate the errors caused by density variations [37]. 25

2.2.3.C Deaerator Control The most important variables to be controlled are the level and the pressure. The level control is very important to ensure that the deaerator has a reserve capacity to the boiler, and the pressure is fundamental to work in the right temperature range to efficiently remove the gases [34]. The major level disturbance is the variation of lost steam in the vent gases, and the control is done adjusting the condensate flowrate coming from the condenser. The pressure is controlled manipulating the steam admitted to the deaerator. It s usual to extract stream from another point or to decrease the pressure s set point, if the steam s pressure is lower than the deaerator s operating pressure. This happens usually in part-load operations. Besides that, it s controlled the water chemistry to dosage the right quantity of the treatment reagents. 2.3 Carbon Capture and Storage CCS is composed by CO 2 capture, compression, transportation and injection. The implementation of CCS reduces the power output which leads to a negative effect on the power plant economical efficiency of the project, because the same costs are spread over less energy. Although the most important contribution to increase the efficiency comes from the power plant improvement, the carbon capture technologies development is also very important [38] [39] [40]. For carbon capture in fossil power plants the main technologies are [5]: Post-combustion capture (PCC) Pre-combustion capture Oxy - combustion The CO 2 coming from capture is wet and has some contaminants. The first compression line has typically three compressors with intercoolers and knock-out-drums between stages. The water is condensed and removed in the knock-out-drums after cooling and compression. After these stages the flue gas passes through a dehydrator, where the remaining moisture is removed. The water removal is extremely important to avoid problems in the pipeline. In the second compression line the CO 2 is compressed to the pressure required. CO 2 transportation can be done by pipeline or by ship in the following conditions: Gas Phase Dense phase Supercritical Phase The storage is usually done injecting the CO 2 in geological storages at depths around 800m or more, in oil and gas reservoirs or saline aquifers. 26

2.3.1 Post - Combustion Post-combustion capture (PCC) can be implemented to newly designed plants or to retrofitted power plants, and the absorption processes are the most advanced currently. In this technology CO 2 is captured from the flue gas that comes from the combustion of the fossil fuel with air, like is shown in the figure 2.12, after being submitted to treatments to remove the Ash (ESP), NO x (SCR) and SO 2 (FGD). Figure 2.12: Post-Combustion capture diagram [5]. There are three main types of capture in PCC: absorption, adsorption and membranes. These three techologies are described in the subsections 2.3.1.A, 2.3.1.B and 2.3.1.C. 2.3.1.A Absorption In the absorption methods the CO 2 is captured into the bulk phase of another material, which generally contains a reagent that selectively reacts with it. All the near-term PCC are absorption based, using an absorber-stripper configuration (showed in figure 2.13). In almost all the cases it s used either aqueous pure amine or aqueous blend of amines as absorbent. Figure 2.13: PCC s absorption flowsheet [41]. The process consists of doing the absorption in a typical gas-liquid contactor, where the CO 2 rich solution leaves through the bottom and is pumped to the stripper (regenerator vessel). In the stripper the CO 2 is liberated by heating and the lean solution is recirculated to the absorber. The CO 2 stream goes to drying, compression and transportation. 27

The most common technology uses 30wt% aqueous monoethanolamine (MEA), which increases the cost of electricity around 60-90%. New solvents are currently being investigated, to reduce the regeneration energy that is the main contributor to the energy penalty. Generically, the PCC drops the efficiency from about 38 to 27%. All of the near-term technologies require SO 2 concentrations no higher than 10ppm to minimize solvent degradation. 2.3.1.B Adsorption Adsorption consists in capturing the CO 2 onto the surface of another material, passing the flue gas through a packed or fluidized bed containing the adsorbent. To regenerate the adsorbent and liberate the CO 2 the pressure is lowered and/or the temperature is increased. In packed bed the flue gas is diverted to a second vessel while the regeneration is done in the first one, while in fluidized bed the sorbent is circulated between an absorber vessel and a regenerator vessel. This technology has the advantage of requiring less energy to the regeneration, because the heat capacity from the solid sorbent is lower than from the solvent. However there are potential disadvantages like particle attrition, handling the sorbent and thermal management of the vessels. This technology is still in kw range tests. 2.3.1.C Membranes In this capture process the CO 2 is selectively permeated through the membrane material. The CO 2 migration only occurs if its partial pressure is higher on the flue gas side than on the CO 2 side, what can be obtained by pressurizing the flue gas, applying vacuum on the other side, or both. This technology has the potential to be a low energy process. However few data exists on membrane systems for PCC and some issues are yet to be resolved at laboratory scale. The major challenge is to avoid fouling on the membrane surface and the uncertainty of performance/cost of large scaled vacuum pumps and compressors required in this operation. 2.3.2 Pre - Combustion Pre-combustion appeared relatively recently and its main application is on gasification based power plants, namely IGCC. Its objective is to convert the gas from gasification to hydrogen and CO 2 (water gas shift reaction) and to remove the CO 2 from syngas before the combustion in the gas turbine. On the following scheme (figure 2.14) it s represented the application of pre-combustion in IGCC. The efficiency penalty is around 7-8%. 28

Figure 2.14: Pre-Combustion capture diagram. The capture is accomplished at high pressures in an acid gas removal (AGR) process that consists in an absorption operation in a solvent, followed by regenerative stripping. The process be classified in two types according to the solvent: chemical (section 2.3.2.A) and physical (section 2.3.2.B). A flow diagram is shown in figure 2.15. Figure 2.15: Pre-Combustion capture absorption flowsheet (AGR) [5]. The process is composed by two absorber/stripper sections, the first to remove a H 2 S rich stream (sent to Claus Unit to recover elemental sulphur) and the second to remove CO 2. 2.3.2.A Chemical Absorbents Acid gases are removed by reacting with chemical absorbents (e.g., MDEA) and are released by heating. These processes have, typically, lower capital costs but use more steam in the solvent regeneration. 2.3.2.B Physical Absorbents In this process the acid gases are removed by dissolution in physical absorbents (e.g., Selexol and Rectisol processes) by increasing the pressure, and are removed from the solvent by increasing the temperature or decreasing the pressure. The steam required is significantly lower than in chemical absorbent processes. 29

2.3.2.C Other Options Other options (not yet tested ate pilot plants) to remove the CO 2 in pre-combustion capture are: Membrane separation of H 2 and CO 2 Cryogenic processes Chilled ammonia 2.3.3 Oxy-combustion In this technology (figure 2.16) it s removed the nitrogen from the air to obtain a rich flue gas in CO 2. The flue gas CO 2 content will be about 90% (dry basis), which makes the CO 2 capture much easier. If the regulations permit the CO 2 can be stored after dehydratation, otherwise the impurities (O 2, N 2, Ar, essentially) may be removed by cooling the flue gas to a temperature at which the CO 2 condenses and the impurities do not. Figure 2.16: Oxy-Combustion capture diagram [5]. The main components in the oxy-combustion are: Air Separation Unit (ASU): separates O 2 from air by cryogenic distillation Combustion/Heat Transfer/Gas Quality Control system (GQCS): combustion products are cooled to recover heat and clean fly ash. There may be also units to remove impurities, nearly the same components for an air-fired plant. One important operational mechanism is the flue gas recycle that consists in recirculating the flue gas with oxygen to the combustor to simulate the combustion and heat transfer properties of the air. With this technique it s possible to use the design, control and operational knowledge in air fired equipments. From flue gas leaving the furnace, up to 80% is recycled and the net flue gas (not recycled) flowrate is 20-25% of the normal air-fired systems. However the disadvantage is the fact of the concentration of the impurities increases (SO 2, HCl, HF, moisture, fly ash), unless GQCS are employed inside the recycle loop to remove these components, which increases the costs because the flue gas flow is greater inside that outside the recycle loop. Fly ash is usually removed inside the loop, as well as SO 2, which must be maintained below the limit to avoid metal corrosion. Because the NO x production comes only from the fuel nitrogen SCR, it s unlikely to be needed, like in air-fired power plants. 30

2.3.4 Interaction with PCPP In pulverized coal power plant the most used technology to remove CO 2 from the flue gas is the post-combustion capture, using absorption process with MEA. The following picture (2.17) represents the integration of this technology on the power plant [5]. Figure 2.17: Interaction between MEA and PCC [38]. The orange boxes represent the additional items due to carbon capture, that represent the most used capture process (absorption with MEA) and the CO 2 compression line. The Plant efficiency decreases from around 38 to 27%, with a coal parasitic load between 20 and 30%. The greater efficiency penalty in a PCPP when capture is added refers to the energy loss in solvent regeneration and in CO 2 compression. The energy losses in the regeneration are due to the decrease of the work output, because of the steam losses in the stripper reboiler. On the other hand, the auxiliary power increases significantly due to the electricity used to compress the CO 2. 31

3 Modelling PCPP components Contents 3.1 Deaerator.......................................... 34 3.2 SCR (Selective Catalytic Reduction).......................... 36 3.3 Blower............................................ 42 3.4 Controller.......................................... 45 3.5 Drum............................................ 48 32

In this chapter there are the models developed by the author of the thesis: Deaerator (3.1), SCR (3.2), Blower (3.3), Controller (3.4) and Drum (3.5). All the models used to develop the final flowsheets are summarized in the tables 4.8 and 4.2. In the gccs project a standard and organized methodology was followed to develop each model the most reliably possible. To begin, for the models where relevant information is needed, it s done a background review concerning the unit that the model represent, to understand the relationships that describe it and the assumptions to make. In the next phase it s done a first scratch of the model, writing the equations, variables and parameters that express it. Knowing all the equations, variables and parameters it s possible to do the degrees of freedom, taking in account for it the model architecture, also done, to know what variables are assigned from the ports (inlet stream, e.g.). After the DOF analysis it s choosen the specification options, that are the variable(s) that the user has to specify to solve the problem. For example, the specification may differ either if is being done design or operation of the unit. To finish the building phase it s written the equations, variables and parameters and it s done the interface (ports that allow connecting the model with other ones), the specification dialog (interface where the user does the specifications) and the report (interface where the user can see the simulation results). The next phase is the test and validation that is done running the models to a wide range of conditions to debug the problems that may appear to make the model the most robust possible. It s also done a simulation to compare the results with real data. In parallel with the model development, it s created a Model Specification Document (MSD) that describes all the model details. An important detail on the models contruction are the variables on the connections. The material gccs connections transport the stream s mass flowrate, pressure, temperature, composition and enthalpy, and these are the variables that are possible to import to the model and required to export to the outlet connection. For example, if there is needed an inlet temperature it s obtained directly from the port or using a thermodynamics foreign object that relates the temperature with the pressure, enthalpy and composition. This is why it s equivalent to say that to solve a model is needed either the temperature or the enthalpy, because with one of them the other is obtained. In this chapter it s described each model structure (inlet and outlet ports), also the degree of freedom analysis and finally it s shown the specification options. To do the DOF analysis there are summarized the variables and the equations. A list of the parameters used in the equations is also presented with their meaning. In general all the model assumptions and special relations can be seen in the units description in the chapter 2.1. 33

3.1 Deaerator The Deaerator model is a steady-state model that assumes an adiabatic mixing of all inlet streams (one steam and any number of boiler feedwaters), with the outlet boiler feedwater and bleed steam streams at equilibrium and at saturation conditions, which determines the outlet temperature and outlet pressure. The flowrate of the bleed stream is given by the bleed fraction. gccs doesn t take account of oxygen and non-condensable gases in the water streams, what means that there isn t modelling of the deaeration operation. The model calculates the ammount of inlet steam to maintain the required operating pressure or calculates the operating pressure if the inlet steam mass flowrate is known. Figure 3.1 shows the model icon and connectivity in gproms. Figure 3.1: Deaerator model in gproms. 3.1.1 Inlets One array of UtilityFluid inlet ports representing the inlet boiler feedwaters (BFW s) to Deaerator. One UtilityFluid inlet port representing the inlet steam to Deaerator. 3.1.2 Outlets One UtilityFluid outlet port representing the outlet boiler feedwater (BFW ) from the Deaerator. One UtilityFluid outlet port representing the outlet bleed steam from the Deaerator. One ControlSignal outlet port representing the pressure measurement signal of the Deaerator. 3.1.3 Variables Table 3.1: Variables of the Deaerator model. Symbol Definition Units Array Size F Steam F BFW,j F Steam F BFW in Mass flowrate of the inlet steam kg s 1 in Mass flowrate of inlet BFW j kg s 1 Nin BFW out Mass flowrate of the outlet bleed steam kg s 1 out Mass flowrate of the outlet BFW kg s 1 T out Temperature of the outlet streams K p Steam in Pressure of the inlet steam Pa Continued on next page 34

Table 3.1 Continued Symbol Definition Units Array Size p BFW,j in Pressure of inlet BFW j Pa Nin BFW p out Pressure of the outlet streams Pa p Pressure drop Pa h Steam in Specific enthalpy of the inlet steam J kg 1 h BFW,j in Specific enthalpy of inlet BFW j J kg 1 Nin BFW h Steam out Specific enthalpy of the outlet bleed steam J kg 1 h BFW out Specific enthalpy of the outlet BFW J kg 1 φ bleed Bleed fraction 3.1.4 Equations Overall mass balance for the Deaerator: Nin BFW Fin Steam + j=1 F BFW,j in = F Steam out The Bleed Fraction equation calculates the bleed steam mass flowrate: Energy Balance for the Deaerator: Nin BFW Fin Steam h Steam in + j=1 [F BFW,j in φ bleed = F out Steam Fin Steam h BFW,j in ] = F Steam out + F BFW out (3.1) h Steam out (3.2) + Fout BFW h BFW out (3.3) The outlet specific enthalpies are calculated using a foreign object for water, with the assumption that the outlets temperature and pressure are equal. h Steam out = PhysProp.VapourEnthalpy(T out, p out, 1) (3.4) h BFW out = PhysProp.LiquidEnthalpy(T out, p out, 1) (3.5) Equilibrium equation to relate the pressure and temperature inside the Deaerator: p out = PhysProp.DewPressure(T out, 1) (3.6) Relation between the outlet pressure and the pressure drop: 3.1.5 Degrees of freedom p out = min j (p Steam in, p BFW,j in ) p (3.7) The number of degree of freedom is calculated in table 3.2 by counting the number of variables from the table 3.1 and the equations from the section 3.1.4. Table 3.2: DOF analysis to the Deaerator model. Number of variables Number of equations Degrees of freedom 11 + 3N BFW in 7 4 + 3N BFW in To solve the model the number of specifications must be equal to the DOF. The Deaerator model will include the following obligatory specifications: 35

1. Inlet Steam : temperature (or specific enthalpy) and pressure. 2. Inlet BFWs : temperature (or specific enthalpy), pressure and mass flowrate. 3. Bleed Fraction. Additional Specifications: One of the following options for additional specifications must be also specified: 1. With pressure specified: Any one of: Deaerator s pressure or pressure drop. 2. With pressure calculated: Inlet Steam : mass flowrate. 3.2 SCR (Selective Catalytic Reduction) The SCR model is a steady-state model to remove nitric oxide (NO) and nitrogen dioxide (NO 2 ) from the flue gas to a certain specification level of NO x or with a certain efficiency. The model estimates the reagent stream requirements that can be in the form of Anhydrous Ammonia, Aqueous Ammonia or Urea, and are always diluted with air. The following reactions will take place in the model: 4NO + 4NH 3 + O 2 4N 2 + 6H 2 O NO + NO 2 + 2NH 3 2N 2 + 3H 2 O (3.8a) (3.8b) The model doesn t take into account nor the reactions selectivity nor the kinetics, so some assumptions had to be made. The conversion is calculated based on the user performance specifications, and refers to the ammount removed of nitric oxide and nitrogen dioxide (NO x ). In basic mode, or can specify the outlet NO x content in the outlet flue gas stream or the unit efficiency. In advanced mode the user specifies the design temperature and the design efficiency, and the actual efficiency is calculated based on the difference between the temperature and the design temperature, which causes a decrease in the efficiency. In parallel, ammonia slip (ammonia in the outlet flue gas) occurs because the reagent requirement is calculated based on the design efficiency. First of all, because reaction 2 is faster than reaction 1, it is assumed that reaction 2 occurs first and, consequently, reaction 1 only occurs if all NO 2 is fully converted. Because the typical flue gas has much more NO than NO 2 and because in reaction 2 the stoichiometric coefficients for NO and NO 2 are both 1, it was assumed that if the quantity of NO x to be removed is greater than the ammout of NO x to complete reaction 2, it is possible to consume all of the NO 2 in reaction 2 and then reaction 1 takes place. Figure 3.2 shows the model icon and connectivity in gproms. 36

Figure 3.2: SCR model in gproms. 3.2.1 Inlets One ProcessFluid inlet port representing the flue gas inlet to the SCR. 3.2.2 Outlets One ProcessFluid outlet port representing the flue gas outlet from the SCR. 3.2.3 Parameters The values and the meaning of the parameters used in the model equations are summarized in table 3.3: Table 3.3: Parameters used in the SCR model. Parameter Definition Value Default units h r1 Specific enthalpy change of reaction 1-406868.0 J kg 1 h r2 Specific enthalpy change of reaction 2-756720.9 J kg 1 T standard Standard temperature 298.15 K p standard Standard pressure 101325 Pa A Parameter for design mode curve 0 B Parameter for design mode curve -0.0396 C Parameter for design mode curve 0.2044 D Parameter for design mode curve - 0.75 Γ 1 Mole percentage of O 2 in dry basis 21 % Γ 2 Mole percentage of O 2 in air 6 % ratio air,nh3 Air mole ratio in dilution of the ammonia stream 0.95 x Urea NH 3 Mole fraction of NH 3 in urea ammonia solution 0.3 x Urea CO 2 Mole fraction of CO 2 in urea ammonia solution 0.2 x Urea H 2O Mole fraction of H 2 O in urea ammonia solution 0.5 x Aqueous NH 3 Mole fraction of NH 3 in aqueous ammonia solution.2 x Aqueous H 2O Mole fraction of H 2 O in aqueous ammonia solution.8 ratio NOx,NH 3 Excess of NH 3 to NO x 1 cb 1 Curve Bound 1-47.5 % cb 2 Curve Bound 2 52.5 % ν i,j Stoqueometric coefficient of component i in reaction j M i Molecular Mass of component i Equation 3.46 g mol 1 Continued on next page 37

Table 3.3 Continued Parameter Definition Value Default units N C Number of compounds in the flue gas 3.2.4 Variables Table 3.4: Variables of the SCR model. Symbol Definition Units Array Size F in Mass flowrate of the inlet flue gas kg s 1 F out Mass flowrate of the outlet flue gas kg s 1 F NH3 Mass flowrate of the ammonia stream kg s 1 T out Temperature of the outlet flue gas K T NH3 Temperature of the ammonia stream K p in Pressure of the inlet flue gas Pa p out Pressure of the outlet flue gas Pa p NH3 Pressure of the ammonia stream Pa p Pressure drop Pa w in,i Mass fraction of the inlet flue gas - C w out,i Mass fraction of the outlet flue gas - C w NH3,i Mass fraction of the ammonia stream - C x out,i Mole fraction of the outlet flue gas - C x NH3,i Mole fraction of the ammonia stream - C h in Specific enthalpy of the inlet flue gas J kg 1 h out Specific enthalpy of the outlet flue gas J kg 1 h NH3 Specific enthalpy of the ammonia stream J kg 1 η Removal efficiency % w NOx Mass fraction of NO x in the outlet flue gas - x NOx Mole fraction of NO x in the outlet flue gas - γ NOx Concentration of NO x in the outlet flue gas mg Nm 3 x dry O 2 Mole fraction of O 2 in the outlet flue gas (dry basis) - ρ N out Normal density of the outlet flue gas kg m 3 η design Design NO x removal efficiency % T design Design Temperature K η deviation NO x removal efficiency deviation to design % T deviation Temperature deviation to design % r design,1 Rate of reaction 1, at design conditions moles s 1 r design,2 Rate of reaction 2, at design conditions moles s 1 r 1 Rate of reaction 1 moles s 1 r 2 Rate of reaction 2 moles s 1 3.2.5 Equations The following two equations calculate the efficiency deviation (3.9) and the temperature deviation (3.10), using the real and design temperatures and efficiencies. η deviation = η η design η design 100% (3.9) T deviation = T out T design T design 100% (3.10) There are two modes (Basic and Advanced) that differ in the use or not of the deviations to design calculations. 38

Table 3.5: Case to distinguish modes in thescr model. CASE: s Mode Basic η deviation = 0 (3.11) 100 if T deviation < cb 1 Advanced η deviation = ATdeviation deviation 2 + CT deviation + D if cb 1 T deviation cb 2 100 if T deviation > cb 2 (3.12) The reaction rates are calculated for the two conditions (reaction 1 and 2 taking place, or only reaction 2), depending on the flue gas content. If the required amount of NO x to be consumed is greater than the amount needed to convert all the NO 2 in reaction 2, both reactions occur; otherwise only reaction 2 takes place. To express the first condition the following if condition is defined: ( win,no η + w ) in,no 2 M i,no M NO2 If the restriction 3.13 is fulfilled the equations to be used are: > [γ NO,2 + γ NO2,2] w in,no 2 M NO2 (3.13) ηf in ( win,no M NO + w in,no 2 M NO2 η design F in ( win,no M NO + w in,no 2 M NO2 The equations mean that: F in w in,no2 M NO2 + γ NO2,2r 2 = 0 (3.14) ) r 2 = r design,2 (3.15) + (γ NO,1 + γ NO2,1) r 1 + (γ NO,2 + γ NO2,2) r 2 = 0 (3.16) ) + (γ NO,1 + γ NO2,1) r design,1 + (γ NO,2 + γ NO2,2) r 2 = 0 (3.17) Reaction 2 consumes all of the NO 2, so its real rate is equal to the flow of NO 2 in the flue gas (3.14) The design rate of reaction 2 is equal to the actual rate because the reaction is complete (3.15). The design rate and actual rate of reaction 1 are calculated using the design and actual removal efficiency (3.16 and 3.17). Otherwise, if the restriction 3.13 is not fulfilled, the following equations are applied to calculate the consumption rates: ηf in ( win,no M NO + w in,no 2 M NO2 η design F in ( win,no M NO + w in,no 2 M NO2 The equations for this case mean that: r 1 = 0 (3.18) r design,1 = 0 ) (3.19) + (γ NO,2 + γ NO2,2) r 2 = 0 (3.20) ) + (γ NO,2 + γ NO2,2) r design,2 = 0 (3.21) 39

The reaction 1 does not take place (3.18 and 3.19). The design and actual rate of reaction 2 are calculated using the real and design removal efficiency (3.20 and 3.21). The Ammonia stream flowrate is calculated with the design consumptions, because the amount of ammonia is based on ideal conditions, and taking into account the excess (ratio NOx,NH 3 ): F NH3 w NH3,NH 3 + (γ NH3,1r design,1 + γ NH3,2r design,2 ) M NH3 ratio NOx,NH 3 = 0 (3.22) Mass balance for the SCR unit for each component i: F in w in,i + F NH3 w NH3,i + [γ i,1 r 1 + γ i,2 r 2 ]M i = F out w out,i (3.23) Energy Balance for the SCR unit: F in h in + F NH3 h NH3 = F out h out + ( h r1 γ NO,1 r 1 + h r2 γ NO,2 r 2 )M NO (3.24) Definition of the several specification types: w out,nox = w out,no + w out,no2 (3.25) x out,nox = x out,no + x out,no2 (3.26) γ out,nox = w out,nox ρ N Γ 1 Γ 2 out Γ 1 x dry (3.27) out,o 2 Calculation of the O 2 concentration in dry air basis and of the normal density in outlet conditions, needed in the outlet NO x definition of dry basis mass concentration: x dry out,o 2 = x out,o2 1 x out,h2o (3.28) ρ N out = PhysProp.VapourDensity(T standard, p standard, w out ) (3.29) Because all the ammonia streams options are diluted with air in the same proportions, it s defined the mole fraction of O 2 and N 2 in the ammonia stream for all the cases: x NH3,N 2 = ratio air,nh3 (1 Γ 1 ) (3.30) x NH3,O 2 = ratio air,nh3 Γ 1 (3.31) The difference is on the other components, and that s why there is a case for this in table 3.7. 40

Table 3.7: Case to distinguish ammonia types in the SCR model. CASE: s NH3 type Anhydrous Aqueous x NH3,NH 3 = 1 ratio air,nh3 (3.32) x NH3,i = 0, i / {NH 3, O 2, N 2 } (3.33) x NH3,NH 3 = (1 ratio air,nh3 )x Aqueous NH 3 (3.34) x NH3,H 2O = (1 ratio air,nh3 )x Aqueous H 2O (3.35) x NH3,i = 0, i / {NH 3, O 2, N 2, H 2 O} (3.36) x NH3,NH 3 = (1 ratio air,nh3 )x Urea NH 3 (3.37) Urea x NH3,H 2O = (1 ratio air,nh3 )x Urea H 2O (3.38) x NH3,CO 2 = (1 ratio air,nh3 )x Urea CO 2 (3.39) x NH3.i = 0, i / {NH 3, O 2, N 2, H 2 O, CO 2 } (3.40) Conversion between molar and mass fractions for the ammonia and outlet flue gas streams: M i w out,i = x out,i i C (M, i C (3.41) ix out,i ) M i w NH3,i = x NH3,i i C (M, i C (3.42) ix NH3,i) Total composition restriction: x out,i = 1 (3.43) i C The specific enthalpies are calculated using the foreign object for the gases. The inlet flue gas specific enthalpy is known from the port, while the outlet flue gas and ammonia specific enthalpies are calculated by: h NH3 = PhysProp.VapourEnthalpy(T NH3, p NH3, w NH3,i) (3.44) h out = PhysProp.VapourEnthalpy(T out, p out, w out,i ) (3.45) The Molecular Mass is important to convert compositions between mass and molar mass: M i = PhysProp.MolecularWeight (3.46) Pressure drop equation to calculate the outlet pressure: p out = p in p (3.47) 3.2.6 Degrees of freedom The number of degree of freedom is calculated in table 3.8, by counting the number of variables from the table 3.4 and the equations from the section 3.2.5. 41

Table 3.8: DOF analysis to the SCR model. Number of variables Number of equations Degrees of freedom 26+5 N C 19 + 4 N C 7 + N C To solve the model the number of specifications must be equal to the DOF. The SCR model will include the following obligatory specifications: Inlet flue gas : temperature (or specific enthalpy), pressure, mass flowrate and mass fraction. Ammonia stream : temperature and pressure. Pressure Drop in the unit. Additional Specifications: One of the following options for additional specifications must be also specified: Basic mode: One of: NO x removal efficiency, outlet NO x mass fraction, outlet NO x mole fraction or outlet NO x concentration (in dry basis). Temperature deviation is set to 0. Advanced mode: Design NO x efficiency. Design temperature. 3.3 Blower The Blower model is a steady-state model of a one stage blower, and because there is no cooling (small compression) it is modeled as isentropic (equivalent to adiabatic compression). So, to calculate the power needed for the compression the isentropic efficiency and the ideal isentropic work are used. The efficiency is specified by the user and has a default value of 85%, a value in the range of centrifugal and reciprocating blowers. The user also specifies the pressure increase. The model is also modelled to take in account the maximum pressure increment of a blower (1 atm) and calculates the temperature increase during the compression. The model icon and connectivity in gproms is shown in figure 3.3. 42

Figure 3.3: Blower model in gproms. 3.3.1 Inlets One ProcessFluid inlet port representing the gas inlet to Blower. 3.3.2 Outlets One ProcessFluid outlet port representing the gas outlet from the Blower. One Power outlet port representing the Power of the Blower. 3.3.3 Parameters The values and the meaning of the parameters used in the model equations are summarized in table 3.9: Table 3.9: Parameters used in theblower model. Parameter Definition Value Default units p lim Pressure increment limit 101325 Pa N C Number of compounds in the gas 3.3.4 Variables Table 3.10: Variables of the Blower model. Symbol Definition Units Array Size F Mass flowrate of the gas kg s 1 T out Temperature of the outlet K p in Pressure of the inlet Pa p out Pressure of the outlet Pa p ratio Pressure ratio p Pressure increment Pa ρ in Density of the intlet kg m 3 ρ out Density of the outlet kg m 3 Continued on next page 43

Table 3.10 Continued Symbol Definition Units Array Size w i Mass fraction of the gas C h in Specific enthalpy of the intlet J kg 1 h out Specific enthalpy of the outlet J kg 1 η is Isentropic efficiency % P is Isentropic power demand W P Actual power demand W γ Isentropic index 3.3.5 Equations Energy balance for the Blower: F h in + P = F h out (3.48) Calculation of the isentropic power and of the total power: [ (pout ) 1 1/γ p in γ P is = F 1] (γ 1)ρ in p in (3.49) Isentropic index equation: P = P is η is (3.50) γ = ln (p out/p in ) ln (ρ out /ρ in ) Calculation of the outlet specific enthalpy and of the densities using a foreign object for gases: (3.51) h out = PhysProp.VapourEnthalpy(T out, p out, w) (3.52) ρ in = PhysProp.VapourDensity(T in, p in, w) (3.53) ρ out = PhysProp.VapourDensity(T out, p out, w) (3.54) Calculation of the pressure increment and of the pressure ratio, variables needed for the specifications: p ratio = p out /p in (3.55) p out = p in + p (3.56) 3.3.6 Degree of freedom The number of degree of freedom is calculated in table 3.11, by counting the number of variables from the table 3.10 and the equations from the section 3.3.5. Table 3.11: DOF analysis to the Blower model. Number of variables Number of equations Degrees of freedom 14+ N C 9 5+ N C To solve the model the number of specifications must be equal to the DOF. The Blower model will include the following obligatory specifications: 44

1. Inlet gas : temperature (or specific enthalpy), pressure, mass fraction and mass flowrate. 2. Isentropic Efficiency. Additional Specifications: The following options for additional specifications must be also specified: Any one of: outlet pressure, pressure increment and pressure ratio. 3.4 Controller The Controller model is a generic PI controller that can receive any kind of measured variable and send any kind of manipulated variable. This model may be transformed to a P controller. It s also important to note that this model is dynamic and that the control may be done automatically (SP specified by the user in the model) or by cascade (SP specified by another unit). Both the measured variable error and the manipulated variable are relative and this is done in order to have a gain defined around 1 with a good performance, because it does not need to account for the difference in order of magnitude between the measured and manipulated variables. To assure that the controller output lays within the upper and lower bounds, an anti windup reset algorithm is included in the model. If the bounds are violated, the time derivative of the integral error is set to zero and the controller output is clipped to the bounds. In this work, the controller model was adapted to proportional (level control) and proportionalintegral (power and pressure control) controllers. In the thesis it s explained the generic PI controller, and its adaptation to P because for the adapted controllers the differences are in small details, line variable types and units and default values in the specification dialog. It can be seen the model icon and connectivity in gproms in the figure 3.4. Figure 3.4: Controller model in gproms. 3.4.1 Inlets One Controlsignal inlet port representing the measured variable. One Controlsignal inlet port representing the external set point. 3.4.2 Outlets One Controlsignal outlet port representing the manipulated variable. 45

3.4.3 Variables Table 3.12: Variables of the Controller model. Symbol Definition Units Array Size K Controller gain τ I Controller reset time s B Controller Bias P Proportional Term I Integral Term Change s 1 I Integral Term D swt Anti wind up Switch ɛ Error SP I Internal Set Point SP E External Set Point SP User Set Point M V Measured variable MV MIN Minimum measured variable MV MAX Maximum measured variable OP MIN Minimum manipulated variable OP MAX Maximum manipulated variable OP C Calculated manipulated variable OP real Real manipulated variable 3.4.4 Initial Conditions For the PI controller, the initial integral term is equal to zero: I(0) = 0 (3.57) 3.4.5 Equations There is a selector to get the Set Point from either the user specification (3.58) or the external port (3.59): Table 3.13: Set Point assignment modes in the Controller model. CASE: s SP User SP I = SP (3.58) External SP I = SP E (3.59) The measured variable error, depending if the action is direct (3.60) or reverse (3.61), is given by: Table 3.14: Action (Manipulated-Controlled) in the Controller model. CASE: s Action Direct ɛ(mv MAX MV MIN ) = SP I MV (3.60) Reverse ɛ(mv MAX MV MIN ) = (SP I MV ) (3.61) 46

For a proportional-integral Controller the control equation becomes: OP C = K(P + I)(OP MAX OP MIN ) + B (3.62) With the proportional term: P = ɛ (3.63) In order to integrate the error in the PI controlller it s used the equation: To a P Controller the integral term is set to zero: di dt = ɛ τ I (3.64) I = 0 (3.65) The real manipulated value is constrained by its maximum and minimum values: OP real = max[op MIN, min(op MAX, OP C )] (3.66) The anti windup reset algorithm { consits in a selector that turns off and on the integral action: E I = τ I if OP MIN D sw > OP > OP MAX + D sw (3.67) 0 otherwise 3.4.6 Degree of freedom The number of degree of freedom is calculated in table 3.15, by counting the number of variables from the table 3.12 and the equations from the section 3.4.5. Table 3.15: DOF analysis to the Controller model. Number of variables Number of equations Degrees of freedom 18 9 9 To solve the model the number of specifications must be equal to the DOF. The Controller will include the following obligatory specifications: 1. Measured variable : signal. 2. Controller: Action : direct or reverse. Controller parameters : gain, bias, maximum and minimum input and maximum and minimum output. Additional Specifications: The following options for additional specifications must be also specified: 1. Proportional Controller: External Set-Point mode: 47

External Set-Point : signal. Controller parameters : integral term set to 0. User Set-Point mode: Controller : Set-Point. Controller parameters : integral term set to 0. 2. Proportional-plus-Integral Controller: External Set-Point mode: External Set-Point : signal. Controller parameters : reset time. StopIntegrator : active or inactive. User Set-Point mode: Controller : Set-Point. Controller parameters : reset time. StopIntegrator : active or inactive. 3.5 Drum The Drum is a model to store an ammount of water to stabilize the system and to assure that there is water to feed the downstream units. The model represents a vertically-orientated closed tank and because of that there is a liquidvapor equilibrium at saturation conditions. The hydrostatic pressure of the liquid in the drum is used to calculate the outlet pressure. In the model it s possible to do design mode to design the tank (design volume) giving the residence time and the oversizing factor (volume occupation) or operational mode to fix the drum size and to perform it at a desired level or residence time, with or without control. It s a dynamic model when in operational model and a steady-state model in design mode. It can be seen the model icon and connectivity in gproms in figure 3.5. Figure 3.5: Drum model in gproms. 48

3.5.1 Inlets One UtilityFluid port representing the inlet water to the Drum. 3.5.2 Outlets One UtilityFluid port representing the outlet water from the Drum. One ControlSignal port representing the level signal of the Drum. 3.5.3 Parameters The values and meaning of the parameters used in the model equations are summarized in the following table (3.16): Table 3.16: Parameters used in the Drum model. Parameter Definition Value Default units g n Gravitational constant 9.811 m s 2 ratio D,h Ratio Diameter/Height of the drum 1/3 3.5.4 Variables Table 3.17: Variables of the Drum model. Symbol Definition Units Array Size F in Mass flowrate of the inlet water kg s 1 F out Mass flowrate of the outlet water kg s 1 T out Temperature of the outlet water K p in Pressure of the inlet water Pa p out Pressure of the outlet water Pa p Drum Pressure of the drum Pa h in Specific enthalpy of the intlet water J kg 1 h out Specific enthalpy of the outlet water J kg 1 h L Specific enthalpy of the liquid phase in the drum J kg 1 h V Specific enthalpy of the vapour phase in the drum J kg 1 ρ L Density of the liquid phase in the drum kg m 3 ρ V Density of the vapour phase in the drum kg m 3 t R Residence time of the water in the drum s V L Volume of the liquid phase in the drum m 3 V design Total design volume of the the drum m 3 D Diameter of the the drum m h Height of the the drum m H L Liquid height (level) of the the drum m M Total mass hold-up kg M L Liquid mass hold-up kg U Total energy hold-up J Occ L Percentage of volume occupation by the liquid % 49

3.5.5 Initial Conditions Since there are two differential equations (3.75 and 3.78), two initial conditions are required. For design mode there is no dynamic, so the hold-ups don t change. For this reason the initial value for the hold-ups derivates are set to zero. In operational mode it s necessary to specify the initial values of: Liquid height. Any one of: Outler temperature or drum pressure. 3.5.6 Equations dm (0) = 0 dt (3.68) du (0) = 0 dt (3.69) The residence time equation calculates the residence time (in operational mode) or the liquid mass hold-up (in design mode): t R F out = M L (3.70) To design the tank (design mode) the first step is to oversize it. In operational mode the equation calculates the occupation by the liquid. V design Occ L 100% = V L (3.71) The diameter and height of the drum area calculated with the volume equation for a cylinder and the ratio between the two sizes: V design = hπ D2 4 (3.72) D = hratio D,h (3.73) The liquid mass hold-up is used to calculate the height of the liquid phase: V L = h L π D2 4 (3.74) Mass balance for the drum with dynamics: F in = F out + dm dt (3.75) The total mass hold-up is calculated summing the mass of the two phases: M = V L ρ L + (V design V L )ρ V (3.76) And the liquid mass hold-up is calculated by the volume of liquid: M L = V L ρ L (3.77) 50

Energy balance for the drum with dynamics: F in h in = F out h out + du dt (3.78) The total energy hold-up is calculated summing the energy of the two phases: U = V L ρ L h L + (V design V L )ρ V h V (3.79) The outlet pressure is taken with the hydrostatic pressure: p out = p Drum + ρ L gh L (3.80) The mass densities, specific enthalpies and temperature-pressure equilibrium relation are calculated with the foreign object for the water: ρ V = PhysProp.VapourDensity(T out, p Drum, 1) (3.81) ρ L = PhysProp.LiquidDensity(T out, p Drum, 1) (3.82) h V = PhysProp.VapourEnthalpy(T out, p Drum, 1) (3.83) h L = PhysProp.LiquidEnthalpy(T out, p Drum, 1) (3.84) h out = PhysProp.LiquidEnthalpy(T out, p out, 1) (3.85) T out = PhysProp.DewTemperature(p Drum, 1) (3.86) 3.5.7 Degree of freedom The number of degree of freedom is calculated in table 3.18m by counting the number of variables from the table 3.17 and the equations from the section 3.5.6. Table 3.18: DOF analysis to the Drum model. Number of variables Number of equations Degrees of freedom 22 17 5 To solve the model the number of specifications must be equal to the DOF. The Drum will include the following obligatory specifications: 1. Streams: Inlet water : temperature (or specific enthalpy) and pressure. Inlet or outlet water : mass flowrate. Additional Specifications: The following options for additional specifications must be also specified: 1. Design mode: Residence time. 51

Volume occupation. 2. Operational mode: Without level Control: Total volume. Residence time. With level Control: Total volume. Inlet or outlet water : mass flowrate (from control valve). 52

4 Modelling a PCPP Contents 4.1 Design Mode........................................ 55 4.2 Operational Mode..................................... 60 4.3 Control Mode........................................ 61 4.4 Sensitivity Analyses.................................... 70 53

The main objective of the thesis is now addressed. This chapter describes the development of a pulverized coal power plant flowsheet with control (and shown the respective results), that starts with the design mode (4.1), passes to the operational mode (4.2) and finishes with the control mode (4.3).Sensitivity analyses are done in the section 4.4. The flowsheet models consist in connecting several models to represent the real power plant. The bigger challenge is to study the whole system and its several recirculations in the steam cycle to understand what to specify to do a correct simulation. For it, the author has to study, beyond his own models, all the remaining needed models, developed by the gccs team, and to do the DOF analysis to the whole system. Except the tank and controller models (developed specially to the control flowsheet), all the models are official models grabbed from the gccs library. Usually the development is done step by step that consists in putting the models one by one and verifying that the results are the expected. The steam cycle side was based on a subcritical power plant from now on referred to as Lawrence [7], using the data from the steam cycle s streams and the gross power output. So, from this source it was possible to model all the steam cycle. For the flue gas side, data from a report of a subcritical pulverized coal power plant were used, referred to as Alstrom [8]. More precisely, the coal, air and boiler outlet flue gas composition and flow were used. From this source were also used the efficiency and other key performance indicators to compare with the results of the model. Since the Allstrom power plant has nearly the same conditions in the boiler (appendixb) and the same number of feedwater heaters and turbine bleed steams, the overlap its data with the Lawrence is justified. The data used to create the model are in appendix B. For the remaining equipment, essentially the flue gas treatment line (SCR, ESP, Blower, GGH and FGD), was modelled taking into account the typical concentration limit of the NO X, Ash and SO 2 in the flue gas sent to the stack, the typical pressure drops in the units and the typical compression in the blower. The configuration that was adopted is similar to the one in figure 2.8, but with the air heater inside the boiler and the SCR as cold side/high dust (2.1.2.B), because the boiler was created this way [42]. The key models used and the units that they represent are in table 4.8. Table 4.1: Key models used in the flowsheets. Model Name Unit Chapter BoilerSteamCondenser Condenser A.5 BoilerSubcritical Boiler Subcritical A.1 Deaerator Deaerator 3.1 Drum Tank 3.5 FeedWaterHeater Feedwater Heater A.6 Generator Generator A.4 GovernorValve Governor Valve A.2 PumpUtility Pump A.7 SteamTurbineStage Steam Turbine A.3 Blower Blower 3.3 Continued on next page 54

Table 4.1 Continued Model Name Unit Chapter ElectrostaticPrecipitator Electrostatic Precipitator A.8 FGD Flue Gas Desulfurization unit A.9 GGH Gas-Gas Heater A.10 SCR Selective Catalytic Reduction unit 3.2 In control mode the models presented in table 4.2 were used. Some other auxiliary models were also used and are shown in table 4.3. Table 4.2: Control models used in the flowsheets. Model Name Unit Chapter ControlValve Control Valve A.11 PIDLevel Level P controller 3.4 PIDPower Power PI controller 3.4 PIDPressure Pressure PI controller 3.4 Table 4.3: Auxiliary models used in the flowsheets. Model Name Unit SourceAir Air Source SourceCoal Coal Source Stack Stack SinkWaste Ash Sink SourceUtility Water Source JunctionUtility Water Splitter SinkUtility Water Sink Recycle breaker base utility A description of the models not developed by the author is presented in appendix A, including how they have to be specified (specification dialog and ports) to understand how to connect them in the flowsheet. 4.1 Design Mode In design mode, the first step, since the equipment sizes were unknown, the power plant was designed to the conditions of 100% load, at steady state conditions. The design is not detailed but is representative (areas and efficiencies, e.g). A detailed description of how the model was built is given in the section 4.1.1, and the important results are presented and discussed in the section 4.1.2. 4.1.1 Model description It s represented the design flowsheet in gproms in figure 4.1. 55

56 Figure 4.1: Design flowsheet model in gproms.

The construction is done connecting the several models, but the major challenge is to specify the model in the right way. Some important details to choose the right specifications are: The last turbine stage exhaust pressure is fixed by the pressure of the condenser, so there is an extra equation that equates the two pressures. To specify the power plant energy production is equivalent to specify or the power produced or the ammount of water that is needed as boiler feedwater. For this flowsheet, the key specifications used in the key steam cycle models that compose the flowsheet (inputs) are summarized in table 4.4. Table 4.4: Key specifications in design mode. Model Boiler HPTurbine1 IPTurbine1 IPTurbine2 LPTurbine1 LPTurbine2 IPTurbine3 IPTurbine4 IPTurbine5 Heater1 Heater2 Heater3 Heater4 Heater6 Heater7 Condenser DEA5 Drum FW Drum Codensate Pump FW Pump Condensate RB FW Variables specified Superheated and hot reheat temperature Superheated pressure and reheat pressure drop Inlet design pressure Exhaust design temperature Inlet design pressure Exhaust vapour fraction Heated feedwater temperature Steam condensate temperature Condenser Pressure Minimum temperature difference Deaerator pressure Residence time Volume occupation by the liquid Discharge pressure Boiler Feedwater Mass Flowrate Since the exhaust pressure of the last turbine stage is known, all the turbines (except the last one) were specified in design mode, assigning the inlet design pressure and the outlet design temperature. So, the turbines calculate the outlet temperature and the inlet pressure and the superheat steam outlet pressure and the reheat steam pressure drop of the boiler are specified. The governor valve is specified in pressure known mode because the inlet and outlet pressure are known, from HPTurbine1 and Boiler. The assigned temperature and pressure of the SH steam leaving the Boiler were calculated before, to match the conditions to enter in the HPTurbine1 after passing the GovernorValve, because 57

there is pressure and temperature drop in the valve, even when it is fully opened. Analyzing again the turbines, the flow that passes through them is known because the boiler feedwater flow (RB FW ) is specified and because the FWHs calculate the extraction steam. This is because the feedwater heaters are specified in design mode with steam flowrate calculated. The condenser is specified in design mode. The Deaerator is specified in pressure specified mode, which also calculates the corresponding extraction steam flowrate, and in the pumps it is specified the discharge pressure. The drum was specified in design mode with a typical residence time of 5 minutes. Another important specification is on the last turbine stage, where, to achieve the correct gross power, the vapour fraction was specified in spite of the outlet design temperature ( two phase mode). This was done because the gross efficiency was too low without condensation in the turbine. So, the outlet vapour fraction was calculated by specifying the total gross power of the power plant. The vapour fraction obtained was 95.24%, which is on safety conditions [18]. So, with these specifications all the pressures and temperatures are expected to be achieved, except the pumps outlet temperatures and the outlet temperature of the LPTurbine5. Because the vapour fraction in the last turbine was replaced by the gross power, this is expected to be achieved. On the flue gas side, the correct variables in the boiler was assigned to satisfy the mass balance in the furnace and, consequently, the flue gas composition. Some of the variables were: ash splitting fraction, excess air and unburned carbon carried in the bottom ash. The boiler efficiency was also specified with a typical value of 88.13%, the same efficiency of the Alstrom subcritical boiler. 4.1.2 Results and Discussion Table 4.5 shows indicators of the deviation of the steam cycle s conditions. The deviations are relative, and for this specific case the reference is the Alstrom data from the literature. Table 4.5: Average and maximum of the absolute stream deviations from Alstrom (relative deviation). T (K) p (%) F (%) Average 0.03 0.00 0.49 Maximum 0.87 0.00 4.01 As it can be noted in table 4.5 the very small deviations in the temperatures and pressures are as expected. The flowrates have some deviations because they are calculated and the gccs models use a different tool to calculate the thermodynamic properties than that used by the Lawrence authors. On the flue gas side it is important to show the flue gas composition deviations obtained, when compared to Alstrom: 58

Table 4.6: Flue gas composition compared to Alstrom (relative deviation, in %). Compound w (%) CO 2-0.10 N 2 0.02 H 2 O 0.30 O 2 0.00 SO 2 0.00 Ash -0.19 Using the same coal and air conditions, the same flue gas composition was obtained (table 4.6), which shows that the mass balance in the boiler is correct. For the previous two analysis it s proved that the model is representing adequately the conditions wanted. To evaluate the modelled power plant, the deviations in the key performance indicators are also shown in table 4.7, compared with the Alstrom. Table 4.7: gproms key performance indicators compared to Alstrom (relative deviation, in %). KPI Deviation (%) Gross Efficiency (% LHV) 3.07 Net Efficiency (% LHV) 6.37 CO 2 emissions (g/kw.h) -2.39 Boiler s flue gas (g/kw.h) -1.47 Coal comsumption (g/kw.h) -1.98 Feedwater rate (g/kw.h) -7.32 Coal/FW (kg/kg) 5.76 The modelled power plant has a higher efficiency compared with the Alstrom power plant, with a value of 39.14%, which is well within the typical range for a subcritical power plant (table 2.1). The difference in the efficiency is because the Lawrence steam cycle is better optimized than the Alstrom one (steam extraction points, e.g.). The difference in the net efficiency is greater than in the gross efficiency, since the model is missing some auxiliary powers, namely for the coal handling and for the cooling water system, units that weren t modelled). The others KPIs are lower because the efficiency is greater, which decreases the need of coal and water circulating in the steam cycle per megawatt. The flue gas and CO 2 emissions are related to the coal consumption. To better understand the dramatic difference in the feedwater flow it the ratio of ammount of coal to ammount of water is calculated. Due to the greater value for the simulated power plant, it is concluded that the heat transfer from the coal to the water in the boiler is 5.76% greater for the gproms case, So, because the steam transports more energy it is expected a minor quantity need of water (- 7.32%). Taking into account the problems in calculating the auxiliary power in the model, these KPIs indicate that the modelled power plant is working using similar resources to the example of a real power plant and gives a similar typical efficiency. 59

4.2 Operational Mode In the Operational simulation mode the objective is to change the specifications to operational mode, replacing some specifications with the design variables obtained in the design simulation. The flowsheet is exactly the same as the used in design mode (figure 4.1) and the simulation refers, once again, just to 100% load. A brief description of the differences between the operational and the design model is done in the section 4.2.1, and the model is validated in the section 4.2.2. 4.2.1 Model description The model used is the same but with differences in the specifications that change the correspondent model specification mode (in general changed from design to operational mode). In the following table the specification differences are highlighted in bold. Model HPTurbine1 IPTurbine1 IPTurbine2 LPTurbine1 LPTurbine2 IPTurbine3 IPTurbine4 IPTurbine5 Heater1 Heater2 Heater3 Heater4 Heater6 Heater7 Condenser DEA5 Table 4.8: Key models used in the flowsheets. Variables specified Stodola s coefficient Efficiency Heat transfer area Terminal temperature difference Condenser Pressure Heat transfer area Pressure drop Drum FW Liquid level Drum Codensate Design volume RB FW Generator Gross power 4.2.2 Results and Discussion The key results to validate this model are presented in this chapter. The operational results match very closely the design ones, as expected. As an example, in the following table are shown the deviations of the steam cycle s streams compared to the design mode. 60

Table 4.9: Average and maximum of the absolute steam deviations from design (relative deviation). T (K) p (%) F (%) Average 0.00 0.00 0.02 Maximum 0.00 0.00 0.06 mode. The results obtained validate the model and it may be developed and simulated in the control 4.3 Control Mode In control mode, the objective is to implement the controls that are actually used in a real power plant to achieve the 100% load conditions and to simulate load changes and disturbances in the plant, in order to evaluate the performance of the control system and of the global power plant. At first some set point changes are made in order to analyse the control of the boiler/turbine system, tunning the controllers (4.3.1). Then an example of a daily cycle is presented (4.3.2.B) and some disturbances in the coal s LHV are done to see how the control system performs (4.3.2.C). The description of the model used to perform the control simulations is presented in the section 4.3.1. All the control simulations are shown in the section 4.3.2. 4.3.1 Model description The model includes the control of the boiler/turbine system, condenser and drums. With this system the boiler superheated steam s pressure, the power, the condenser pressure and the deaerator tank s level are controlled. The boiler following mode is used in subcritical boilers, because those boilers have steam drums with high hold-ups that are advantageous for this kind of control: the governor valve is opened and the energy and mass hold-up is immediatly utilised to quickly achieve the power requirement. Drums are used and controlled to represent the real power plant (the deaerator and condenser have tanks) and to accomodate the disturbances that occur in the upstream units. Because the steam cycle is closed (no make-up water) the control can not be done for the condenser drum. In fact, if the deaerator drum level is at the set point the condenser drum will also be, because these two models are the only ones in which the model accounts for hold-up. The way control is done in the real power plant is described in the section 2.2. On the other hand, for example, the level control of the feedwater heaters and boiler is not done because they are steady-state models and therefore do not have hold-ups. The deaerator s pressure can not be maintained in part-load operations because the inlet steam s pressure decreases below the deaerator s operating pressure. A real control was too complex to apply because it takes steam from an extraction point with greater pressure if the normal one is not enough, and this would interfere with the whole power plant and cause problems in the model. Besides that, the set point should vary in a complex and coordinated way to avoid the deaerator s temperature to 61

be above the temperatures in the higher pressure feedwater heaters in part-load (these temperatures decrease), and forbid heat exchange. Because of this, the pressure drop of the deaerator (difference between the steam and the deaerator s pressures) is assigned, giving the operating pressure. In the feedwater heaters the TTD (relation between temperatures) is set. So, when decreasing the power all the system s temperatures will decrease parallelly to be possible to do all the heat integration. Figure 4.2 shows the control flowsheet with the four controllers incorporated. All the controllers are PI, except for the drum s level controller where it s used a P controller. In terms of variable specifications, the location of the controlled variables is changed from the unit models to the controllers. So, the parameters are tuned in order to obtain a typical response in the system dynamics. Figure 4.2: Control flowsheet model. 4.3.2 Results and Discussion 4.3.2.A Controller Calibration In the first control simulation presented in the thesis, the objective is to adjust the control parameters of the boiler/turbine system, around a typical value, to get a similar response to that expected for boiler following control (figure 4.3). This manual tuning had to be done because the models are steady-state, so the dynamics of the responses are directly correlated to the controllers gains. To represent the coal handling units dynamics, the power set point is changed with a ramp with a typical rate of 4% of load per minute. This value was choosen because for a subcritical power plant it is normal to ramp between 3 and 5% [43]. The single source found to help in the first guess for the parameters was a modelling study of a supercritical power plant controlled by the coordinated control system [11]. Despite being a more complex control system and a diferent power plant, this source was used to have an idea of a proper reset time and gain for a system with similar dynamics in real life. The reset time used in the two controllers (pressure and power) was equal to the literature and the gain was adjusted, with the objective of choosing the most appropriate response. The response 62

Figure 4.3: Megawatt load change and throttle pressure deviation [19]. of the controlled variables, to a step change under different gains,are presented in figure 4.4. Figure 4.4: Load and pressure responses to different tunings. In the first test (gains equal to 0.015), the first plot of figure 4.4 shows that the response is not the expected, since the power control is slow and the pressure control does not oscilate. Because of this, the gain of the power controller is increased compared with the pressure one, to improve the power control, relegating the pressure. Analysing the other gains, it is concluded that when increasing the gain of the power controller, the control of the load becomes better, following the set point ramp more quickly, with a much smaller error. On the other hand, the pressure oscilates more. Since this type of control is known to be quick in terms of power achievement (gets rapidly close to the set point) and unstable in terms of pressure control, the increse of the power controler s gain, as expected, seems to improve the similarities between the simulation and the typical response. The chosen parameters were the intermediate ones (gains of 0.01 and 0.2) because for a gain of 1 the pressure oscilation is larger (around -5% / 8.3 bar). Since the set point changes are expected to be greater than 4%, the large pressure oscilation was taken into account. 63

Besides that, the stabilization time (time needed for the controlled variable converge within the stabilization range of ± 0,5% - black lines in figure 4.4) for the chosen parameters is 4,2 and 5,5 minutes for the power and for the pressure, respectively, what is closer to the example in the figure 4.3 than the other case. The other parameters result in a stabilization time of 2,0 and 2,8 minutes, which is too low. Because the minimum allowable pressure in the boiler is not know, this tuning was not done taking into account this condition. However, this is an imporant factor to consider and that is another reason why the intermediate gain was choosen. Analysing the dynamics in figure 4.4, can be seen that the responses are second order, which is due to the controller dynamics and to the ramping in the power that simulates the dynamics in the coal. For the remaining controllers the respective tuning was done by trial and error. The final selected parameters are: Table 4.10: Parameters used in the control system. Controller Gain Reset time (s) Power 0.2 7.5 Superheated pressure 0.01 7.5 Tank level 10 Condenser pressure 5 7.5 To prove that the control system is working, table 4.11 summarises the average and maximum deviations of the control simulation, with the operational simulation as reference. Table 4.11: Average and maximum of the absolute stream deviations from operational (relative deviation, in %). T (K) p (%) F (%) Average 0.10 0.10 0.14 Maximum 0.72 0.97 1.50 Analysing the previous table, the maximum deviations are high because the control system isn t perfect and the conditions, locally, may vary from the operational simulation. On the other hand, because the average deviations are around 0.1% it s concluded that the control flowsheet is well built and that the control of the system has a good performance for the final steady-state conditions. 4.3.2.B Daily Cycle The idea of the daily cycle is to simulate the operation of a pulverized coal power plant varying the load along the day to match the power that the power plant is supposed to send to the grid. The set point is changed, again, with a ramp with a rate of 4% of the load per minute. PCPPs are base-load power plants, which means that they produce energy at a constant rate. This means that the load of the plant does not change during the day to meet the grid responses, because this task is responsability of the peaking power plants (typically gas turbine power plants). However, a PCPP usually has two or three steps during the day to follow the grid load curve by 64

distance. The daily cycle was done adjusting the power plant load (green) to an example of grid power (pink). The load steps were choosen as 85, 92.5 and 100%. Figure 4.5: Grid and power plant s load curves. The key control variables of the boiler/turbine system, the boiler feedwater flow and the pressure after the governor valve have the following responses during the daily cycle: Figure 4.6: Power load and governor valve stem position. Figure 4.7: Superheated steam pressure deviation from SP and coal flowrate deviation from 100% load. 65

Figure 4.8: Boiler feedwater flow and governor valve s outlet pressure deviation from 100% load. As expected, an increase in the power load opens the governor valve (figure 4.6) to increase the flow and the pressure of the superheated steam to the first turbine (figure 4.8), which increase the power produced in the turbines. As result, the turbine requires additional energy in the form of superheated steam, and since the boiler is producing an energy level below the needed, the pressure begins to drop (figure 4.7). This energy need is compensated with the increase of the firing rate adjusting the coal flow, returning the pressure to its set point - figure 4.7. Obviously, all the rest of the system is now going to be affected because the boiler feedwater flow and the governor valve pressure drop are now different. To observe the effects on the rest of the system, more interesting variables are tracked: the temperature of the heated feedwater and the steam flowrate in one feedwater heater (figure 4.9) and the condenser pressure and the cooling water consumption (figure 4.10). Figure 4.9: Heated feedwater temperature and steam flow deviations from 100% load, in the Heater2. Since the pressure of the superheated steam that enters HPTurbine1 increases with the load, the temperatures and pressures of all the turbines exhaust steams increase as well. Because the heaters and deaerator have, respectively, the TTDs and the pressure drop fixed, the temperatures increase in the heat transfer zone, too. This is illustrated in figure 4.9. The steam flow also ramps up parallel to 66

the power and boiler feedwater flow. Figure 4.10: Condenser s pressure and cooling water flowrate deviations from 100% load. As expected, the cooling water consumption decreases in part-load operations, because there is less flow to be condensed, as can be seen in figure 4.10. The condenser pressure is well controlled, with a positive peak due to the increase in the steam to condensate, when the power load increases. The last controlled unit the Deaerator s tank, being shown in figure 4.11 along with the level of the condenser. The condensate valve s stem position is also shown in figure 4.12. Figure 4.11: Deaerator s and condenser s tank level deviations from SP. First of all, the deaerator s tank level is substantially disturbed by its outlet flow (boiler feedwater flow) when the governor valve acts under load changes. The condenser s tank is also disturbed by the same phenomenon since its inlet flow is related to the governor valve position. So, an increase in the load (and in the BFW flow) increases the level of the condenser s tank and decreases the level in the deaerator s tank. 67

Figure 4.12: Condensate valve s stem position. It is also observed that the control of the deaerator s tank is not perfect, and because of that the deviation of the level from the set point in the condenser s tank is not annulated too. The control isn t perfect because the controller is proportional and because of that it doesn t eliminate the error that was accumulate when the inlet flow and the outlet flow were different. Finally, its concluded that the error that occurs during the load changes is symmetric and because of that the level is the same in the two 85% load zones (at 0 and 24h). Since the tanks are the only models where there is mass hold-up, the volume that one looses the other gains, and this explains the symmetry between the two responses in figure 4.11. As conclusion, to produce less energy, the flows, pressures and temperatures decrease across the power plant. In addition, the deviations to 100% load are around the load change, for example, for the boiler feedwater flow, for the governor valve outlet s pressure and for the coal flow. The effect of the load in the global system s performance is analysed observing the key performance indicators for the different loads. The 100% load KPIs are equal to those obtained in design and operational mode and because of that they are not presented, while the part-load are presented in deviation from the full-load KPIs (megawatt basis). Table 4.12: Part-load key performance indicators compared to full-load (relative deviation, in %). KPI Power Load 92.5 % 85 % Gross Efficiency (%) -0.96-1.98 CO 2 emissions (g/kw.h) 0.97 1.99 Boiler s flue gas (g/kw.h) 0.97 1.99 Coal comsumption (g/kw.h) 0.97 1.99 Feedwater rate (g/kw.h) 0.27 0.56 Cooling water (g/kw.h) -5.05-8.81 Auxiliary Power (MW/MW) 0.38 0.85 Boiler feedwater temperature (K) -0.78-1.60 From table 4.12 it can be concluded that as the conditions deviate from full-load, the power plant performance worsens and that is because the power plant works in conditions different from the ones that designed the equipment (100% load). Two direct reasons are the decrease of the temperature of 68

the water to the boiler (the temperatures in the system decrease in part-load, as concluded before) and the increase of the feedwater flow per MW, that will increase the ammount of coal needed per MW. In addition, the flows of coal and flue gas and the CO 2 emissions decrease to produce less energy. In terms of deviation, it s almost symmetric to the efficiency deviation, because the coal changes to directly counter the efficiency change. The conclusion made for the coal (and flue gas and CO 2 ) can not be extended to the feedwater or to the cooling water because the conditions in the steam cycle, as shown in figure 4.9, change in part-load operations, so the gross efficiency is not directly proportional to the water flows because the system is extremely complex. Simplifying things, the feedwater flow per megawatt increases because the steam used in the turbines has lower pressures in part-load, and the cooling water decreases because the inlet streams to the condenser are colder. The auxiliary power consumption per MW of gross power increases because the same happens to the flows. The deviation (0.38 and 0.85%) is between the increase in the flue gas (0.97% and 1.99%) and the increase in the feedwater (0.27% and 0.56%), because the power of the auxiliary units is directly correlated with both of them. 4.3.2.C Disturbances This chapter presents the responses for the cases of disturbances to the coal s LHV in order to see how the control system reacts to mantain the desired conditions if the coal quality changes. The responses are analysed for the positive disturbances (+2.5 and +5%), since they are approximately symmetric for the negative ones. The variables shown are of the boiler/turbine system (figures 4.13 and 4.14). Figure 4.13: Power load and governor valve stem position. 69

Figure 4.14: Superheated steam pressure and coal flowrate deviations from 100% load. An increase in thelhv of the coal, as expected, increases the power produced and the superheated steam pressure, as can be seen in figures 4.13 and 4.14. To counteract this disturbance, the coal flow changes by roughly the same percentage as the LHV did, but in the opposite direaction, and the governor valve acts while its controlled variable (boiler pressure) is not at the set point. By the tim ethat the coal flow is correctly adjusted, the governor valve position has returned to the initial value because all the conditions in the steam cycle are the same. Basically, the control system adapts the coal to mantain the firing rate with the new LHV, and by that time all the rest of the power plant returns to the previous conditions. The changes in the new steady state occur only in the flue gas side (coal handling system, furnace and flue gas units), and the control system has a good performance, since the controlled variables (boiler/turbine system) stabilize at the set point, with the following errors (relative to the initial steady-state): Table 4.13: Errors in the final steady-state (relative errors, in%). Controlled variable LHV change +5 % +2.5 % -5 % -2.5 % Power Load 0.00 0.00 0.01 0.00 Superheated steam pressure -0.01 0.00 0.00 0.00 4.4 Sensitivity Analyses This chapter presents a sensitivity analysis on the power plant s performances, analysing the KPIs. It was changed the coal s LHV (4.4.1) and the steam turbine s efficiencies (4.4.2). 4.4.1 Heating Value of the Coal The sensitivities are calculated using deviations in the LHV if the coal of -5, -2.5, +2.5 and +5%, and the key performance indicators are presented in table 4.14, compared to the fulll load conditions with the normal LHV. 70

Table 4.14: Key performance indicators compared to the normal LHV (relative deviation, in %). KPI LHV change +5 % +2.5 % -2.5 % -5 % Gross Efficiency (%) 0.00 0.00 0.00 0.00 Net Efficiency (%) 0.04 0.02-0.02-0.04 CO 2 emissions (g/kw.h) -4.76-2.44 2.56 5.26 Boiler s flue gas (g/kw.h) -4.76-2.44 2.56 5.26 Coal comsumption (g/kw.h) -4.76-2.44 2.56 5.26 Feedwater rate (g/kw.h) 0.00 0.00 0.00 0.00 Cooling water (g/kw.h) 0.00 0.00 0.00 0.00 Auxiliary Power (MW) -1.04-0.53 0.56 1.15 Boiler feedwater temperature (K) 0.00 0.00 0.00 0.00 As it can be noted in the previous table a change in the LHV affects neither the gross efficiency nor the boiler feedwater flow. The first of these is maintained because the power and the firing rate remain approximately the same (the coal flow is adjusted according to its LHV ) and the second because all the steam cycle conditions are maintained, which can be seen by the deviation in the BFW temperature. The steam cycle conditions don t change because the conditions of the steam that leaves the boiler remain the same and because the only changes occur in the flue gas side, and this explains the deviation of 0% in the cooling water flowrate per MW. The coal, and consequently the flue gas and the CO 2, vary aproximately the same percentage of the LHV, with the opposite signal. This is because the firing rate is maintained (load and gross efficiency do not vary) and because the firing rate is the coal flowrate times the emphlhvof the coal. So if, for example, the LHV increases 5% the coal flowrate should be multiplied by a factor of -1/1.05 (-4,74%, in relative deviation), what really happens in the previous table. The auxiliary power variations are, in this case, correlated to the flue gas flow, and that is why the deviations are greater when the deviations on the flue gas increase. Obviously, the decrease in the auxiliary power increases the net efficiency. 4.4.2 Steam Turbine s Efficiency Changes of -2, -1, +1 and +2% in the efficiency of all the turbines were implemented. The power plant s aging, naturally, affects its performance. During the power plant s time the equipment efficiencies tend to decrease, and because of this the turbine s efficiencies were reduced to study their influence on the overall system performance. The same studies were done for increases in the efficiencies to take into account the development of the technologies and materials of the turbines. The KPIs obtained are presented in table 4.15. 71

Table 4.15: Key performance indicators compared to the normal efficiency (relative deviation, in%). KPI Efficiency change +2 % +1 % -1 % -2 % Gross Efficiency (%) 0.61 0.31-0.56-1.13 CO 2 emissions (g/kw.h) -0.60-0.31 0.57 1.14 Boiler s flue gas (g/kw.h) -0.60-0.31 0.57 1.14 Coal comsumption (g/kw.h) -0.60-0.31 0.57 1.14 Feedwater rate (g/kw.h) -0.95-0.48 0.77 1.55 Cooling water (g/kw.h) -2.34-1.20 2.26 4.62 Auxiliary Power (MW) -0.86-0.44 0.72 1.45 Boiler feedwater temperature (K) -0.11-0.06 0.08 0.17 When the efficiency increases the temperatures in the turbines and, consequently, in the heat integration zone decrease, as shown by the BFW s temperature. In fact, when the efficiency is greater the enthalpy of the inlet steam to the turbine is further exploited, decreasing more the exhaust temperature. The opposite happens with reduced efficiencies. Another phenomenon is the governor valve s action in the pressures of the system. For a higher efficiency the governor valve closes and the pressures in the turbines decrease. For a certain increase in the turbine s efficiency it is confirmed that the global efficiency increase, because less steam circulating is required, and consequently less coal, to achieve the same power. The flue gas flow and CO 2 emissions have once again a deviation equal to the coal because the excess air is the same. The cooling water consumption per MW is also correlated to the temperature variations. For example, it increases in response to negative disturbances because the temperatures of the condenser inlets are greater. The effect of the deviation on the auxiliary power is consistently between the flue gas and the water deviations. The differences in the KPIs are not symmetric between positive and negative deviations because the energy production is differently affected either if the pressure in the turbines increases or if it decreases, since the steam conditions vary in different proportions. 72

5 Conclusions and Future Work Contents 5.1 Conclusions........................................ 74 5.2 Future Work........................................ 75 73

5.1 Conclusions The main objective of this work is to develop a model of a subcritical pulverized coal power plant, to integrate with all the CCS chain in the future. Dynamic studies were performed to this power plant. Additionally, the power plant s performance under different operational conditions was analysed. The steam cycle and the flue gas side are based on information obtained from the literature [7] [8], and the gccs current library is used to build the compound model that represents the power plant. As additional work, some models that were missing were developed and added to the library. For full-load operations, the simulated power plant has a gross power output of 769.9 MW, resulting in a net power of 742.8 MW. Using a subcritical boiler with a typical efficiency of 88.1% [8], the gross efficiency obtained was 39.6 %. There are no data in the literature for the gross efficiency of the modelled power plant, but the value is in the typical range (38-40%). The boiler feedwater flow is 2839.8g/kWh. In terms of the flue gas side, the power plant emits 828.25 g CO 2 /kw.h to the atmosphere, a typical value without capture. This flue gas sent to the stack has a concentration of 20 mg/nm 3 of ash and 200 mg/nm 3 of SO 2 and has no NO x, since the furnace does not produce NO x in the boiler model. The flue gas emisson is 3870.6 g /kw.h and the coal consumption is 357.3 g /kw.h. The deviations from the data reported in the literature (Allstrom) are -2.4, -1.5 and -2.0% for the CO 2, flue gas and coal, respectively. Both the flue gas and CO 2 emissions and coal consumption are less than the example used from the literature, because the efficiency is greater, which reduces the material used per MW. It is concluded that for part-load conditions the gross efficiency decreases, which indicates that a pulverized coal power plant should work on the maximum load whenever possible. The gross efficiency is 39.2 and 38.8% for 92.2 and 85 % load, respectively, and the specific CO 2 emissions increased 1 and 2% (relative to 100% load) to 836.3 and 844.7 g/kwh. The coal consumption increased to 360.8 and 364.5 g/kwh and the flue gas emissions to 3908.1 and 3947.8 g/kwh, the same relative percentage than for the coal, because the CO 2 is direcly correlated with the coal and flue gas, since the flue gas composition is constant. This efficiency penalty is due to the boiler feedwater temperature decrease, which increases the coal needed per MW. For a coal with higher LHV, the gross efficiency is not affected, because the same firing rate is needed per gross power. In terms of net efficiency, the real efficiency to consider from the optimization point of view, a coal with a higher LHV improves the power plant, because the coal and flue gas quantities to handle, and consequently the auxiliary power, are lower. For an increase of 2.5 and 5% in the LHV, the flue gas (and CO 2 emissions) and the coal consumption decrease 2.4 and 4.8%,, respectively. On the other hand, upgrading the steam turbine s efficiencies increases both the gross and the net efficiency, because the resources in the steam cycle and in the flue gas side are lower to produce the same energy. For example, for an efficiency increase of 2% in the turbines, the gross efficiency increases 0.6%, 74

and for a decrease of 2% the penalty is around 1.1%. For the net efficiency, the advantage of a turbine system with higher efficiency will be greater because it accounts for the energy savings in all the auxiliary units. In fact, in the flue gas side the emissions change by -0.6 and +1.1% for each case, and in the steam cycle the boiler feedwater varies -1.0 and +1.6. It is also concluded that the improvement (for +2%) is lower than the penalty (for -2%) because the temperatures and pressures in the system vary differently with the turbine efficiencies. The sensitivity analyses show that the power plant performance is upgraded using a coal with higher LHV and with more efficient turbines. However, only an optimization study can answer whether the performance increase by the coal and turbinesis eventually beneficial, because there are some implications such as: The coal flow per MW is lower but its cost increases with the LHV. The investment in the steam turbines increases with increasing turbine efficiency. The lower flows in the system decrease the units size and, consequently, the power plant cost. In terms of control, it s concluded that changing the load at a rate of 4% per minute, the control applied to the models has a similar performance when compared to the literature, with quick responses and small errors. One limitation of the work is the accuracy of the auxiliary power, and that s why no values of net efficiencies are provided in the conclusions. Since the library models were all steady-state models, the control study is not reliable enought to draw strong conclusions.from the control point of view this is the main limitation. For example, the coal dynamics should be appplied because it has very slow dynamics, due to the fuel pulverization in the mill. These two limitations could be improved in future work. 5.2 Future Work There are some details to be taken into account in order to improve the work done in the scope of this thesis. Since the gccs project is at an early stage, the library used to develop the PCPP is in its first version. Because of this, several issues could be changed in the models, so as to improve the final conclusions. Actually, a lot of effort and time was spent testing the newly finished models and ensuring they work together, and because of that some simplifications were made to the models. As already concluded, the main issue in terms of control is the implementation of dynamics in some models to improve the reliability of the dynamic responses, and to allow to be used all the controls and operations that are practiced in the real power plant. As an example, the implementation of dynamics in the deaerator and in the feedwater heater would calculate the pressure according to the mass and energy hold-up in the equipment. The hold- 75

up would allow to control the level of these units, and the pressure would enable the equipment to operate in pressure-driven mode, like in the real power plant. On the other hand, boiler and coal handling units dynamics would also be an important step. This improvement would allow to analyse the different boiler/turbine system control modes correctly, since the main difference between them is the fast or slow use of the stored energy and mass in the steam drum. Another important improvement would be the insertion of leakage in the steam cycle to turn it into an open cycle with make-up control. The models could also be, in general, more detailed to improve the accuracy of the results. As examples, the feedwater heater should take in account the different zones of heat exchange and calculate accurately the overall heat transfer coefficient, and the deaerator should be modeled taking into account the three Rdifferent zones that compose it. The boiler s furnace should produce NO x during the combustion, to be removed in the SCR, and to take in account the power consumption of this removal. Another important issue is the modelling of other units that would improve both the control and the power plant performance studies. For example, the modelling of the cooling water and coal systems would improve the veracity of the auxiliary power calculation to study the power plant s performance more accurately, while the modelling of the attemperators in the boiler model would permit control of both the RH and the SH temperatures. Connecting the entire CCS chain would be the perfect final step, sending the flue gas to the capture plant to remove the CO 2 before being set to the stack. With this tool, it would be possible to study the performance of the power plant with capture, and to control all the CCS components. An optimization of the power plant would be also an interesting work to be done in the future, when the models allow sizing the most relevant units. 76

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A gccs Model Library A-1

A.1 BoilerSubcritical The coal flowrate can be specified or not. If so, it will replace one of the water side specifications, otherwise, all the water specifications must be given. Because the most used mode is the nonspecification of the coal flowrate, the specifications are explained for this case. Figure A.1 shows the model icon and connectivity in gproms. Figure A.1: BoilerSubcritical model in gproms. A.1.1 Ports structure The BoilerSubcritical has the following ports: One UtilityFluid inlet port representing the boiler feedwater to the BoilerSubcritical. One UtilityFluid inlet port representing the cold reheat steam to the BoilerSubcritical. One ProcessFluid inlet port representing the air to the BoilerSubcritical. One Coal inlet port representing the coal to the BoilerSubcritical. One UtilityFluid outlet port representing the superheat steam from to the BoilerSubcritical. One UtilityFluid outlet port representing the hot reheat steam from to the BoilerSubcritical. One ProcessFluid outlet port representing the flue gas from the BoilerSubcritical. One Coal outlet port representing the bottom ash from the BoilerSubcritical. One ControlSignal outlet port representing the superheat pressure measurement signal of the BoilerSubcritical. A.1.2 Ports specifications The obligatory specifications in the ports are: 1. Feedwater - temperature. 2. Any one of: Feedwater - mass flowrate. Superheat steam - mass flowrate. 3. Cold reheat steam - temperature. 4. Any one of: A-2

Cold reheat steam - mass flowrate. Hot reheat steam - mass flowrate. 5. Air - Composition, temperature and pressure. 6. Coal - Temperature, composition and LHV (everything in the SourceCoal except mass flowrate). Additional Specifications The additional specifications depend on the pressure specification mode in the specification dialog: 1. Superheat and reheat steam pressure drop: Feedwater or superheat steam pressure. Cold reheat steam or hot reheat steam pressure. 2. Superheat and reheat steam outlet pressure: Feedwater pressure. Cold reheat steam pressure. 3. Superheat steam pressure drop and reheat steam outlet pressure: Feedwater or superheat steam pressure. Cold reheat steam pressure. 4. Superheat steam outlet pressure and reheat steam pressure drop: Feedwater pressure. Cold reheat steam or hot reheat steam pressure. A.1.3 Specification Dialog To better explain the specifications, the different tabs ( Boiler properties, Steam Properties, Air heater properties and Tramp air ) are separated. Steam Properties The user has to specify the following obligatory variables in the Steam Properties tab: 1. Superheat steam - temperature. 2. Hot reheat steam - temperature. The additional specifications depend on the pressure specification mode: 1. Superheat and reheat steam pressure drop. 2. Superheat and reheat steam outlet pressure. 3. Superheat steam pressure drop and reheat steam outlet pressure. 4. Superheat steam outlet pressure and reheat steam pressure drop. Boiler Properties The user has to specify the following obligatory variables in the Boiler Properties tab: 1. Fraction of ash in the flue gas. A-3

2. Fraction of carbon in the ash. 3. Pressure of the flue gas. 4. Temperature of the bottom ash. 5. Efficiency of the Boiler. 6. Any one of: Mass fraction of oxygen in the flue gas. Molar fraction of oxygen in dry flue gas. Excess of air. Air heater properties If the user chooses the have air heater in the boiler the following obligatory variables have to be specified in the Air heater properties tab: 1. Flue gas pressure drop. 2. Air pressure drop. 3. Air heater leakage fraction. 4. Air heater heat transfer efficiency. 5. Any one of: Heat exchanger effectiveness. Flue gas inlet temperature. Air outlet temperature. Tramp air The user has to specify the following obligatory variable in the Tramp air tab: 1. Inlet tramp air fraction. 2. Tramp air temperature 3. Tramp air pressure. A.2 GovernorValve Figure A.2 shows the model icon and connectivity in gproms. Figure A.2: GovernorValve model in gproms. A-4

A.2.1 Ports structure The GovernorValve has the following ports: One UtilityFluid inlet port representing the superheat steam inlet to the GovernorValve. One ControlSignal inlet port representing the stem position signal to the GovernorValve. One UtilityFluid outlet port representing the superheat steam outlet from the GovernorValve. A.2.2 Ports specifications The obligatory specifications in the ports are: 1. Inlet superheat steam - temperature. 2. Any one of: Inlet superheat steam - pressure. Outlet superheat steam - pressure. Additional Specifications 1. Pressure drop known: Stem position specified: Inlet or outlet superheat steam - pressure. Stem position controlled: Inlet or outlet superheat steam - pressure. Inlet signal - stem position. 2. Specify flow coefficient: Stem position specified:. Stem position controlled: Inlet signal - stem position. The additional specifications depend on the pressure specification mode in the specification dialog: A.2.3 Specification Dialog The user has to specify the following obligatory variables in the specification dialog: 1. Inherent characteristic. Additional specifications The additional specifications depend on the mode: 1. Pressure drop known: A-5

Stem position specified: Stem position. Stem position controlled:. 2. Specify flow coefficient: Stem position specified: Stem position. Flow coefficient. Stem position controlled: Flow coefficient. A.3 SteamTurbineStage Figure A.3 shows the model icon and connectivity in gproms. Figure A.3: SteamTurbineStage model in gproms. A.3.1 Ports structure The SteamTurbineStage has the following ports: One UtilityFluid inlet port representing the steam inlet to the SteamTurbineStage. One Power inlet port representing the mechanical power (1). One UtilityFluid outlet port representing the exhaust steam from the SteamTurbineStage. One Power bidirectional port representing the mechanical power (2). A.3.2 Ports specifications The obligatory specifications in the ports are: 1. Any one of: Inlet steam - mass flowrate. Exhaust steam - mass flowrate. A-6

Additional Specifications The additional specifications depend on the specification mode in the specification dialog: 1. Design Mode: Inlet temperature. Inlet or exhaust steam pressure ( dialog ). 2. Operational Mode: Any one of: Inlet temperature and exhaust temperature. Any one of: Inlet pressure and exhaust pressure. A.3.3 Specification Dialog The user has to specify the following obligatory variables in the specification dialog: 1. Design Mode Inlet or exhaust design pressure ( ). 2. Operational Mode Isentropic efficiency. Stodola s constant. Additional specifications The additional specifications depend on the outlet phase: 1. Design Mode Vapour: Exhaust design temperature. Two phase: Exhaust vapour fraction. A.4 Generator Figure A.4 shows the model icon and connectivity in gproms. Figure A.4: Generator model in gproms. A-7

A.4.1 Ports structure The Generator has the following ports: One Power inlet port representing the mechanical power to the Generator. One Control outlet port representing the electrical power from the Generator. A.4.2 Ports specifications The obligatory specifications in the ports are: 1. Mechanical Power A.4.3 Specification Dialog The user has to specify the following obligatory variables in the specification dialog: 1. Efficiency. Additional specifications The additional specifications depend on the power specification mode: 1. Power specified: Electrical Power. 2. Power non-specified:. A.5 BoilerSteamCondenser Figure A.5 shows the model icon and connectivity in gproms. Figure A.5: BoilerSteamCondenser model in gproms. A.5.1 Ports structure The BoilerSteamCondenser has the following ports: One array of UtilityFluid inlet ports representing the inlet steam to the BoilerSteamCondenser. A-8

One UtilityFluid inlet port representing the inlet cooling water to the BoilerSteamCondenser. One UtilityFluid outlet port representing the outlet steam condensate from the BoilerSteamCondenser. One UtilityFluid outlet port representing the cooling water return from the BoilerSteamCondenser. One Control outlet port representing the pressure measurement of the BoilerSteamCondenser. A.5.2 Ports specifications The obligatory specifications in the ports are: 1. Inlet Steam(s): Temperature, pressure and mass flowrate. 2. Inlet Cooling water: Temperature and pressure. Mass flowrate ( dialog ). A.5.3 Specification Dialog The user has to specify the following obligatory variables in the specification dialog: 1. Overall heat transfer coefficient. 2. Cooling water pressure drop. Additional specifications The additional specifications depend on the specification mode: 1. Condenser pressure: Design Mode: Condenser pressure. Any one of: Cooling water return temperature and minimum temperature difference. Operational Mode: Heat transfer area. Any one of: Condenser pressure, cooling water return temperature and minimum temperature difference. 2. Cooling water flow known ( ): Design Mode: Condenser pressure. Operational Mode: Heat transfer area. A.6 FeedWaterHeater Figure A.6 shows the model icon and connectivity in gproms. A-9

Figure A.6: FeedWaterHeater model in gproms. A.6.1 Ports structure The FeedWaterHeater has the following ports: One UtilityFluid inlet port representing the inlet feedwater to the FeedWaterHeater. One UtilityFluid inlet port representing the inlet steam extracted from the Turbine. One array of UtilityFluid inlet ports representing the inlet drains to the FeedWaterHeater. One UtilityFluid outlet port representing the heated feed water from the FeedWaterHeater. One UtilityFluid outlet port representing the outlet steam condensate drain from the FeedWater- Heater. A.6.2 Ports specifications The obligatory specifications in the ports are: 1. Inlet feedwater - temperature, pressure and mass flowrate. 2. Inlet drain - temperature, pressure and mass flowrate. 3. Inlet steam - temperature and pressure. Mass flowrate ( dialog ). A.6.3 Specification Dialog The user has to specify the following obligatory variables in the specification dialog: 1. Overall heat transfer coefficient. 2. Pressure drop in the shell. 3. Pressure drop in the tubes. Additional specifications The additional specifications depend on the specification mode: 1. With steam flowrate calculated: Design Mode: Any one of: Steam condensate temperature, drain cooler aproach and drain effectiveness. A-10

Any one of: Heater feedwater temperature, terminal temperature difference and feedwater temperature rise. Operational Mode: Heat transfer area. Any one of: Drain cooler aproach, drain effectiveness,terminal temperature difference and feedwater temperature rise. 2. With steam flowrate known ( ): Design Mode: Any one of:steam condensate temperature, drain cooler aproach, drain effectiveness, heater feedwater temperature, terminal temperature difference and feedwater temperature rise. Operational Mode: Heat transfer area. A.7 PumpUtility Figure A.7 shows the model icon and connectivity in gproms. Figure A.7: PumpUtility model in gproms. A.7.1 Ports structure The PumpUtility has the following ports: One UtilityFluid inlet port representing the inlet water to the PumpUtility. One UtilityFluid outlet port representing the outlet water from the PumpUtility. One Power outlet port representing the electrical power from the PumpUtility. A.7.2 Ports specifications The obligatory specifications in the ports are: 1. Inlet - pressure and temperature. 2. Any one of: A-11

Inlet mass flowrate. Outlet mass flowrate. A.7.3 Specification Dialog The user has to specify the following obligatory variables in the specification dialog: 1. Efficiency. 2. Discharge pressure. A.8 ElectrostaticPrecipitator Figure A.8 shows the model icon and connectivity in gproms. Figure A.8: ESP model in gproms. A.8.1 Ports structure The ESP has the following ports: One ProcessFluid inlet port representing the inlet flue gas to the ESP. One ProcessFluid outlet port representing the outlet flue gas from the ESP. A.8.2 Ports specifications The ports obligatory specifications are: 1. Inlet flue gas - Temperature, pressure, mass flowrate and composition. A.8.3 Specification Dialog The user has to specify the following obligatory variables in the specification dialog: 1. Pressure drop. Additional specifications The additional specifications depend on the performance specification mode: 1. Outlet ash concentration or removal efficiency. A-12

A.9 FGD Figure A.9 shows the model icon and connectivity in gproms. Figure A.9: FGD model in gproms. A.9.1 Ports structure The FGD has the following ports: One ProcessFluid inlet port representing the inlet flue gas to the FGD. One ProcessFluid outlet port representing the outlet Flue gas from the FGD. A.9.2 Ports specifications The obligatory specifications in the ports are: 1. Inlet flue gas - Temperature, pressure, mass flowrate and composition. A.9.3 Specification Dialog The user has to specify the following obligatory variables in the specification dialog: 1. Any one of: Pressure drop. Outlet pressure. 2. Any one of: Efficiency. Outlet SO 2 mass fraction. Outlet SO 2 mole fraction. Outlet SO 2 concentration. 3. Limestone in slurry. Additional specifications The additional specifications depend on the mode: A-13

1. Basic Mode:. 2. Advanced Mode: Molar ratio limestone/so 2 removed. Limestone purity. Slurry temperature. Solids content in gypsum A.10 GGH Figure A.10 shows the model icon and connectivity in gproms. Figure A.10: GGH model in gproms. A.10.1 Ports structure The GGH has the following ports: One ProcessFluid inlet port representing the inlet cold gas to the GGH. One ProcessFluid inlet port representing the inlet hot gas to the GGH. One ProcessFluid outlet port representing the outlet cold gas from the GGH. One ProcessFluid outlet port representing the outlet hot gas from the GGH. A.10.2 Ports specifications The obligatory specifications in the ports are: 1. Inlet hot gas - Temperature, pressure and mass flowrate. 2. Inlet cold gas - Temperature, pressure and mass flowrate. A.10.3 Specification Dialog The user has to specify the following obligatory variables in the specification dialog: 1. Hot gas pressure drop. A-14

2. Cold gas pressure drop. Additional specifications The additional specifications depend on the performance mode: 1. Any one of: Hot stream outlet temperature and heat duty. A.11 ControlValve Figure A.11 shows the model icon and connectivity in gproms. Figure A.11: ControlValve model in gproms. A.11.1 Ports structure The ControlValve has the following ports: One UtilityFluid inlet port representing the inlet water or steam to the ControlValve. One ControlSignal inlet port representing the stemposition signal to the ControlValve. One UtilityFluid outlet port representing the outlet water ir steam to the ControlValve. A.11.2 Ports specifications The obligatory specifications in the ports are: 1. Inlet stream - Temperature and pressure. 2. Stem position. A.11.3 Specification Dialog The user has to specify the following obligatory variables in the specification dialog: 1. Flow coefficient. 2. Maximum allowable flow across the valve. 3. Initial actual stem position (in dynamic mode). 4. Inherent characteristic. Additional specifications The additional specifications depend on the mode: A-15

1. Standart Mode:. 2. Advanced Mode: Time constant. Leakage fraction. Flow exponent. Rangeability factor (only necessary in equal percentage inherent characteristic). A-16

B Source data B-1

Table B.1: Steam cycle data from Lawrence [7]. Stream T (K) P (bar) F (kg/s) Stream T (K) P (bar) F (kg/s) 1 811.0 33.6 563.0 18 353.3 0.5 428.7 2 811.0 165.5 607.3 19 322.1 20.0 522.1 3 591.8 36.7 607.3 20 349.8 20.0 522.1 4 591.8 36.7 563.0 21 370.4 20.0 522.1 5 591.8 36.7 44.3 22 413.4 20.0 522.1 6 516.4 240.0 607.3 23 433.5 20.0 522.1 7 729.4 19.0 22.2 24 455.2 10.5 607.3 8 729.4 19.0 540.9 25 459.3 240.0 607.3 9 648.5 10.9 18.8 26 482.3 240.0 607.3 10 648.5 10.9 522.1 27 487.9 34.9 44.3 11 577.6 6.2 18.8 28 464.9 18.1 66.4 12 577.6 6.2 503.3 29 419.0 5.9 18.8 13 529.8 4.1 36.1 30 376.0 3.9 55.0 14 529.8 4.1 467.1 31 355.4 1.0 71.8 15 407.5 1.0 16.8 32 328.0 0.5 93.4 16 407.5 1.0 450.3 33 322.2 0.1 428.7 17 353.3 0.5 21.6 34 322.1 0.1 522.1 Figure B.1: Flowsheet of the modelled Pulverized Coal Power Plant s Steam Cycle [7]. B-2

Table B.2: Key performance indicators from the Alstrom report [8]. KPI KPI Gross Power (MW) 463.78 Net Power (MW) 433.78 Auxiliary Power (MW) 29.70 Gross Efficiency (% LHV) 38.40 Net Efficiency (% LHV) 35.90 CO 2 emissions (g/kw.h) 848.54 Boiler s flue gas (g/kw.h) 3928.31 Coal comsumption (g/kw.h) 364.54 Feedwater rate (g/kw.h) 3064.20 Boiler efficiency (%) 88.13 Table B.3: Coal ultimate analysis from the Alstrom report [8]. Compound w (%) C 63.2 H 4.3 N 1.3 S 2.7 O 7.1 Moisture 10.1 Ash 11.3 Table B.4: Flue gas composition from the Alstrom report [8]. Compound w (%) CO 2 21.42 N 2 69.10 H 2 O 5.65 O 2 2.50 SO 2 0.50 Ash 0.84 Table B.5: Boiler s streams conditions from the Alstrom report [8]. Stream T (K) p (bar) F (kg/s) Feedwater 529.25 218.2 394.5 Superheated Steam 818.65 165.5 394.5 Cold Reheat Steam 592.95 45.3 359.5 Hot Reheat Steam 813.75 40.7 359.5 B-3

B-4