Modelling of Pulverized Coal Power Plants in Carbon ... · Outubro 2012. Education is the most...

Modelling of Pulverized Coal Power Plants in CarbonCapture and Storage (CCS) Networks

Hugo Manuel Dias Rodrigues

Dissertation for the Master’s Degree

Chemical Engineering

JuriChair: Prof. Joao Manuel Nunes Alvarinhas FareleiraAdviser: Prof. Henrique Anıbal Santos de MatosAdviser PSE: Eng. Jose Alfredo Ramos PlasenciaMember: Vıtor Manuel Geraldes FernandesMember PSE: Javier Rodriguez

October 2012

Modelling of Pulverized Coal Power Plants in CarbonCapture and Storage (CCS) Networks

Hugo Manuel Dias Rodrigues

Dissertacao para obter o grau de Mestre em

Engenharia Quımica

JuriPresidente: Prof. Joao Manuel Nunes Alvarinhas FareleiraOrientador: Prof. Henrique Anıbal Santos de MatosOrientador PSE: Eng. Jose Alfredo Ramos PlasenciaVogal: Vıtor Manuel Geraldes FernandesVogal PSE: Javier Rodriguez

Outubro 2012

Education is the most powerful weapon which you can use to change the world.Nelson Mandela

Acknowledgments

I would like to express my deepest gratitude to my supervisors Prof. Dr. Henrique Matos and

Alfredo Ramos, for all the help they provided and the guidance during the past seven months.

Also would like to thank all the gCCS team especially Dr.Adekola Lawal for all the support and

availability to analyze and discuss ideas.

To all the people that made my life easier in London since all PSE to my cousin Joao Cunha which

welcome me in his home for the first days. My flat mates and coworkers: Elton Dias, Mario Calado

and Ricardo Fernandes for all the time we spend together and the adventures discovering London, its

attractions and social life.

To my friends and my girlfriend which helped not only in this step but throughout my degree and

my life the deepest recognition.

At last, but not less important, I would like to thank my family for giving me all the conditions and

support all this years, to accomplish my objectives.

To all of you a big thank you!

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Abstract

Carbon dioxide emissions to the atmosphere are getting the worldwide attention. Carbon Capture

and Storage technologies promise to take an important role in climate change mitigation. However,

nowadays no software can do a full chain analysis of the Carbon Capture and Storage for power

plant systems. For that purpose Process System Enterprise with the support of Energy Technologies

Institute (ETI) and other associates is developing a new tool-kit, which should have the models for

entire chain addressing different types of power plants, injection and storage.

In the scope of this work pseudo steady state component models of a supercritical power plant

were developed as well as the composite model that fully represents a supercritical power plant. Two

modes, design and operational were developed for the composite model to be able to simulate part

load in addition with turbine following control. A daily cycle simulation was analysed and sensitivity

studies were made on the boiler efficiency and on the reheat vapour temperature. The mathematical

modelling was implemented in the commercial software gPROMS.

This is a highly complex system where all the interactions and all the recirculation of information

that appears in the steam cycle were studied and successfully captured by the model. The sensitivity

analysis shows that an increase in the reheat vapour temperature improves the power production and

the gross efficiency. Pointing out that an improvement of the equipment manufacture material will lead

to more efficient power plants.

Keywords

Supercritical Pulverized Coal Power Plant, Turbine following control, Modelling, Simulation, gPROMS

v

Resumo

As emissoes de dioxido de carbono estao cada vez mais a chamar a atencao do mundo e as tec-

nologias de captura de CO2 prometem ter um papel importante na reducao dos impactos causados

por estas. No entanto, hoje em dia nao existe um software capaz de simular toda a cadeia da captura

do dioxido de carbono para as centrais termoeletricas. Por esta razao a empresa Process System

Enterprise com o apoio do Energy Technologies Institute (ETI) e outras empresas esta a desenvolver

um novo produto que vai dispor de uma biblioteca com todos os modelos, abrangendo diferentes

tipos de centrais ate a injecao e armazenamento.

No tema desta dissertacao desenvolveu-se modelos de pseudo estado estacionario para uma

central a carvao, mas tambem o modelo composito que representa a central termoelectrica su-

percrıtica de carvao. Dois modos foram desenvolvidos: dimensionamento e operacao para o modelo

composito, permitindo simular diferentes producoes de energia juntamente com o controlo turbine

following. Foi simulada uma producao diaria e feita uma analise de sensibilidade a eficiencia da

caldeira e a temperatura do vapor reaquecido. O software usado neste trabalho foi o gPROMS.

Este sistema e muito complexo onde todas as interacoes e recirculacoes de informacao foram es-

tudadas e fielmente capturadas pelo modelo composito. A analise de sensiilidade do vapor reaque-

cido mostra que um aumento nesta provoca um aumento da producao electrica assim como da

eficiencia da central. Este fato mostra que um aumento da resistencia termica dos materiais levara

no futuro a centrais com uma maior eficencia.

Palavras Chave

Central Supercrıtica de Carvao Pulverizado, Turbine following, Modelacao, Simulacao, gPROMS

vii

Contents

1 Introduction 1

1.1 Motivation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

1.2 State of the Art . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

1.3 Original Contributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

1.4 Dissertation Outline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

2 Background Review 7

2.1 Carbon Capture and Storage Technologies . . . . . . . . . . . . . . . . . . . . . . . . . 8

2.1.1 Post Combustion Capture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

2.1.2 Pre-Combustion Capture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

2.1.3 Oxyfuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

2.1.4 Compression and transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

2.1.5 Injection and storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

2.2 Power Plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

2.2.1 Steam Generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

2.2.2 Steam Cycle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

2.2.2.A Carnot Cycle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

2.2.2.B Rankine Cycle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

2.2.2.C Reheat-Regenerative Cycle . . . . . . . . . . . . . . . . . . . . . . . . 15

2.2.3 Integration with CCS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

2.3 Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

2.3.1 Boiler . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

2.3.2 Turbine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

2.3.3 Feedwater heater/Deaerator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

2.3.3.A Deaerator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

2.3.3.B Feedwater Heater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

2.3.4 Condenser . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

2.3.5 Flue Gas Desulphurization unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

2.3.5.A Limestone forced oxidation (LSFO) . . . . . . . . . . . . . . . . . . . . 25

2.3.6 Electrostatic Precipitator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

2.3.7 Gas/Gas Heater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

ix

2.3.8 Governor valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

2.3.9 Stack . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

2.3.10 Generator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

2.4 Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

2.4.1 Boiler/turbine control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

2.4.2 Feed water control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

2.4.3 Steam temperature control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

2.4.4 Deaerator Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

2.4.5 Condenser Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

2.4.6 Feedwater heaters Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

3 Materials and Methods 31

3.1 gPROMS software . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

3.2 Model development workflow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

3.3 gCCS model library . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

3.4 gCCS structure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

4 Mathematical Modelling of PCPP Components 35

4.1 Feedwater Heater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

4.1.1 Inlets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

4.1.2 Outlets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

4.1.3 Variables Nomenclature . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

4.1.4 Equations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

4.1.5 Degree of freedom . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

4.1.6 gPROMS interface . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

4.2 Boiler Steam Condenser . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

4.2.1 Inlets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

4.2.2 Outlets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41


4.2.4 Equations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42


4.3 Electrostatic Precipitator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

4.3.1 Inlets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

4.3.2 Outlets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44


4.3.4 Equations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45


4.4 Flue Gas Desulphurisation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

4.4.1 Inlets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

4.4.2 Outlets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

x


4.4.4 Equations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49


4.5 Gas/Gas Heater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52

4.5.1 Inlets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52

4.5.2 Outlets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52


4.5.4 Equations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52


4.6 Control Valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

4.6.1 Inlets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54

4.6.2 Outlets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54


4.6.4 Equations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55


5 Supercritical Pulverized Coal Power Plant Modelling 57

5.1 Design Mode . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58

5.1.1 Results and Discussion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

5.1.1.A Stream conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

5.1.1.B Key Performance Indicators . . . . . . . . . . . . . . . . . . . . . . . . . 61

5.1.1.C Equipment Parameters . . . . . . . . . . . . . . . . . . . . . . . . . . . 62

5.2 Operational Mode . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63

5.3 Control Mode . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64

5.3.1 Control loops . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64

5.3.1.A Condenser pressure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64

5.3.1.B Deaerator drum level . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65

5.3.1.C Turbine following control loop . . . . . . . . . . . . . . . . . . . . . . . . 66

5.3.1.D Others controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66

5.3.2 Step change in power plant load . . . . . . . . . . . . . . . . . . . . . . . . . . . 66

5.3.3 Daily Cycle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69

5.4 Sensitivity analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74

5.4.1 Boiler efficiency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74

5.4.2 Reheat temperature . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75

6 Conclusions and Future Work 77

6.1 Future Work . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79

Bibliography 81

Appendix A gCCS Model Library A-1

xi

Appendix B Main Operating Conditions and Results B-1

xii

List of Figures

1.1 Carbon dioxide annual emissions from fossil fuels world wide, IEA values. . . . . . . . . 2

1.2 Global CO2 emissions and Green House Gases emission reductions. . . . . . . . . . . 3

2.1 Technical options for CO2 capture from coal-power plants. . . . . . . . . . . . . . . . . . 8

2.2 Block diagram illustrating Power Plant with Post-Combustion CO2 Capture. . . . . . . . 9

2.3 Block diagram illustrating Power Plant with Pre-Combustion CO2 Capture. . . . . . . . . 10

2.4 Block diagram illustrating Power Plant with Oxyfuel CO2 Capture. . . . . . . . . . . . . . 11

2.5 Scheme of an Advanced Supercritical Power plant. . . . . . . . . . . . . . . . . . . . . . 13

2.6 Carnot thermodynamic cycle. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

2.7 Rankine thermodynamic cycle. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

2.8 Reheat regenerative thermodynamic cycle. . . . . . . . . . . . . . . . . . . . . . . . . . 16

2.9 Representation of a power plant steam cycle. . . . . . . . . . . . . . . . . . . . . . . . . 16

2.10 Boiler schematic representation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

2.11 Schematic representation of a feedwater heater. . . . . . . . . . . . . . . . . . . . . . . 22

2.12 Schematic representation of a LSFO system. . . . . . . . . . . . . . . . . . . . . . . . . 25

3.1 Model development workflow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

4.1 gCCS feedwater heater example of a specification. . . . . . . . . . . . . . . . . . . . . . 40

4.2 gCCS environment for a fwh simulation. . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

4.3 gCCS boiler steam condenser model configuration. . . . . . . . . . . . . . . . . . . . . . 41

4.4 gCCS electrostatic precipitator model configuration. . . . . . . . . . . . . . . . . . . . . 44

4.5 Specific power relationship with the efficiency of an ESP unit . . . . . . . . . . . . . . . 46

4.6 gCCS FGD model configuration. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

4.7 Valve stem position for different flow characteristics . . . . . . . . . . . . . . . . . . . . . 53

4.8 gCCS control valve model configuration. . . . . . . . . . . . . . . . . . . . . . . . . . . . 54

5.1 Supercritical steam cycle flow diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . 58

5.2 gCCS diagram of a Supercritical Pulverized Coal Power Plant. . . . . . . . . . . . . . . 59

5.3 Flow diagram of the HP pressure feedwater heaters side. . . . . . . . . . . . . . . . . . 61

5.4 Condenser pressure control loop. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64

5.5 Deaerator drum level control loop. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65

5.6 Turbine following control loop. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66

xiii

5.7 Load change and throttle pressure deviation for the different types of load control. . . . 67

5.8 Load change and throttle pressure deviation results for 4% step change in load. . . . . . 68

5.9 Daily cycle of the Portuguese National Grid from 3 of September 2012. . . . . . . . . . 69

5.10 Simulation results from the daily cycle schedule. . . . . . . . . . . . . . . . . . . . . . . 70

5.11 Boiler pressure and governor valve stem position response during the daily cycle sched-

ule. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71

5.12 Feedwater and coal deviation from full capacity load for the daily cycle schedule. . . . . 71

5.13 Responses of the manipulated and controlled variable for a change of load from 90%

to 100%, for the level control. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72

5.14 Responses of the manipulated and controlled variable during the daily load, for the

condenser pressure control. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72

5.15 Variation of the feedwater heater and deaerator temperature and pressure during the

day. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73

A.1 gCCS boiler model configuration. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-2

A.2 gCCS turbine model configuration. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-3

A.3 gCCS deaerator model configuration. . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-4

A.4 gCCS governor model configuration. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-4

A.5 gCCS drum model configuration. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-5

A.6 gCCS pump model configuration. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-6

A.7 gCCS blower model configuration. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-7

A.8 gCCS generator model configuration. . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-7

A.9 gCCS recycle model configuration. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-8

A.10 gCCS recycle model configuration. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-8

A.11 gCCS controller model configuration. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-9

xiv

List of Tables

2.1 Classification of pulverized coal power plants according to UNIPEDE.[1] . . . . . . . . . 13

4.1 Nomenclature of the variables used in the feedwater heater model. . . . . . . . . . . . 37

4.2 Nomenclature of the variables used in the condenser model. . . . . . . . . . . . . . . . 41

4.3 Nomenclature of the variables used in the electrostatic precipitator model. . . . . . . . 45

4.4 Nomenclature of the variables used in the FGD model. . . . . . . . . . . . . . . . . . . 48

4.5 Nomenclature of the variables used in the GGH model. . . . . . . . . . . . . . . . . . . 52

4.6 Nomenclature of the variables used in the Control Valve model. . . . . . . . . . . . . . 54

5.1 Main assignments in the flowsheet. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60

5.2 Key performance indicators (KPI) deviation. . . . . . . . . . . . . . . . . . . . . . . . . . 62

5.3 Equipment parameters for the feedwater heaters and the condenser. . . . . . . . . . . . 62

5.4 Equipment parameters for the turbines. . . . . . . . . . . . . . . . . . . . . . . . . . . . 63

5.5 Specification trade-offs for operational mode. . . . . . . . . . . . . . . . . . . . . . . . . 63

5.6 Controllers parameters and stabilization time for every controller. . . . . . . . . . . . . . 67

5.7 Table summarizing the controllers parameters. . . . . . . . . . . . . . . . . . . . . . . . 70

5.8 Power plant Key performance indicators for different loads. . . . . . . . . . . . . . . . . 74

5.9 Boiler efficiency sensitivity study . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74

5.10 Reheat temperature sensibility study. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75

B.1 Main operating conditions deviation from reference [2].(for stream identification please

see fig 5.1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-2

B.2 Key performance indicators (KPI) and flue gas composition from reference [2]. . . . . . B-2

B.3 Main operating conditions from design results.(for stream identification please see fig

5.1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-3

B.4 Key performance indicators (KPI) and flue gas composition from design results. . . . . B-3

B.5 Equipment parameters for the feedwater heaters and the condenser. . . . . . . . . . . . B-4

B.6 Equipment parameters for the turbines. . . . . . . . . . . . . . . . . . . . . . . . . . . . B-4

B.7 Main operating conditions from operational results.(for stream identification please see

fig 5.1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-4

B.8 Key performance indicators (KPI) and flue gas composition from operational results. . . B-5

B.9 Main operating conditions for 95% load.(for stream identification please see fig 5.1) . . . B-5

xv

B.10 Key performance indicators (KPI) and flue gas composition for 95% load. . . . . . . . . B-6

B.11 Main operating conditions for 90% load.(for stream identification please see fig 5.1) . . . B-6

B.12 Key performance indicators (KPI) and flue gas composition for 90% load. . . . . . . . . B-7

B.13 Main operating conditions results for a reheat temperature increase of 1.2%.(for stream

identification please see fig 5.1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-7

B.14 Key performance indicators (KPI) and flue gas composition for a reheat temperature

increase of 1.2%. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-8




increase of 7.4%. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-9




increase of 14.5%. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-10

xvi

Abbreviations

Abbreviation Description

AGR Acid Gas RemovalASU Air Separation UnitCCGT Combined Cycle Gas TurbineCCS Carbon Capture and StorageCFBD Circulating Fluidized Bed CombustionCLC Chemical Looping CombustionCW Cooling WaterDCA Drain Cooler ApproachDeff Drain effectivenessDFGD Dry Flue-Gas DesulfurizationDOF Degree of FreedomEDF Electricite de FranceEOR Enhanced Oil RecoveryE.ON E.ON Energy LimitedESP Electrostatic PrecipitatorETI Energy Technologies InstituteEU European UnionFGD Flue-Gas DesulfurizationFTR Feedwater Temperature RiseFWH Feedwater HeatergCCS CCS system modelling toolkit, based on gPROMSGHG Green House GasesGGH Gas Gas HeatergPROMS gPROMS® ModelBuilderHP High PressureIEA International Energy AgencyIGCC Integrated Gasification Combined CycleITM Ion Transport MembraneIP Intermediate PressureLHV Lower Heating ValueKPI Key Performance IndicatorsLP Low PressureLSFO Limestone Forced OxidizedMEA MonoethanolamineMSD Model Specifications DocumentOSTG Once-Through Steam GenerationPC Pulverized CoalPCC Pos Combustion CapturePFBC Pressurized Fluidized Bed CombustionPSE Process Systems Enterprise Ltd.RH ReheatSCR Selective Catalytic ReductionSH SuperheatSNCR Selective Non Catalytic ReductionTTD Terminal Temperature DifferenceUK United KingdomUSC Ultra SupercriticalWFGD Wet Flue-Gas Desulfurizationxviii

List of Symbols

Latin Symbols

Variable Description Units

A Heat transfer area m2

C Components –Cv Valve flow coefficient kg Pa s−1

F Mass flowrate kg s−1

h Specific enthalpy J kg−1

H Head J kg−1

H Henry coefficient Pa m3 mol−1

L Leakage –M Molecular weight g mol−1

N Number of –p Pressure PaP Power WQ Heat duty WrCaCO3/SO2

Molar ratio of limestone/SO2 removed –Rf Rangeability factor –T Temperature KU Overall heat transfer coefficient W m−2 K−1

Vsp Valve stem position –w Mass fraction –W Work duty Wwt Solids content –x Mole fraction –

Greek Symbols


γ Isentropic index (blower) –γ Valve flow exponent (valve) –γ Mass concentration mg Nm−3

Γ Mole percentage %∆ Differential –∆fH Standard heat of formation J mol−1

∆lmT Logarithmic mean differential temperature K∆rH

Θ Standard heat of reaction J mol−1

η Efficiency %κ Rate tphµ Purity –

Continued on next page

xix

Table 2 – Continued


ρ Mass density kg/m3

τ Time constant s -ν Stoichiometric coefficient of the component

Subscripts

Variable Description

A Reactantsair Airash Ashashout Outlet stream with only ashB Productscap capturecold Coldcondenser Condensereq equationsf FractionFW Feedwatergyp Gypsumhot Hotin Inlet streamlime Limestonemax Maximummindiff Minimum differenceout Outlet streamremoved Removeds Isentropicsat Saturationshell Shellspec Specifiedvapour Vapourvar Variablesw Water

Superscripts

Variable Description

act ActualAux Auxiliariescold Colddry Dry basisFW Feedwaterhot Hotnormal Normal conditionsSteam Steam

xx

1Introduction

Contents1.1 Motivation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31.2 State of the Art . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41.3 Original Contributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51.4 Dissertation Outline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

1

Since 1997 with Kyoto protocol, global concern with climate changes from carbon dioxide emis-

sions have been increasing. In 2008, UK government took the next step committing by law to reduce

by 2050, 80% of carbon dioxide emissions from 1990 level.[3] [4]

Over the last decades, carbon dioxide emissions has been increasing at a very high rate, with new

countries like China and India starting to growth economically so their energy demands, therefore,

his carbon dioxide emissions. Besides, this increase in energy demand, a major issue is the use of

coal which amongst the fossil fuels, releases the most CO2 on combustion around 960 gCO2e/kWh

in comparison to natural gas with 443 gCO2e/kWh, for example.[5]

Figure 1.1: Carbon dioxide annual emissions from fossil fuels world wide, IEA values.[6]

Analysing figure 1.1, in 2009, carbon dioxide emissions dropped in relation to the 2008, the cause

of that reduction was the economic crisis. However, despite the slow global economic recovery, 2010

saw the largest single year increase in global human CO2 emissions from energy, growing a whopping

1.6 billion metric ton from 2009, to 30.6 billion metric ton. Last year, a new high record emission was

achieved, 31.6 billion metric ton.

Reducing significantly the carbon dioxide emissions level requires several measures: increasing

energy efficiency, diversify energy sources with renewable energies and implementation of carbon

capture and storage chains. Figure 1.2, exemplifies exactly that where we can see that CCS technol-

ogy will represent a decrease of 19% in CO2 emissions in 2050 to meet the target. This contribution

is more than from renewable energies and more than triple the contribution from nuclear.

Nowadays, carbon capture and storage is a very expensive technology. Two major factors will

determine viability of such a technology, the cost of technology itself (that tends to decrease as the

technology gets more mature) and the cost of carbon dioxide emissions.

As the largest contribution to CO2 emissions is from the burning of fossil fuel, particularly in pro-

ducing electricity, three main processes are being developed to capture CO2 from power plants that

use coal or gas. These are:

• Post Combustion Capture (PCC)

• Pre-Combustion Capture

• Oxy Combustion

2

Figure 1.2: Global CO2 emissions and Green House Gases emission reductions [7]

In the world there are 74 large scale integrated CCS projects, from this 14 are already in operation

or under construction. Europe accounts with 20 of those projects, being United Kingdom the most

active country in this area. This confirms the effort being done by the UK in reducing Green House

Gases (GHG), and creating conditions to accomplish the targets, either by integrated large scale

CCS project or by modelling tool-kit that allows a simple understanding of the system, make techno-

economical decisions, optimization studies and control tuning.[8]

1.1 Motivation

Mitigating global warming is the major challenge of the next century, global conscience about

the problem has been rising along with CO2 emissions. Measures need to be taken to accomplish

a significant reduction in carbon dioxide emissions and Carbon Capture Storage (CCS) technology

promises to be an important technology for climate change mitigation.

Coal power plants emitted in 2011 almost 14 billion metric tons of carbon dioxide representing the

most significant share in global emission with 45% of the total carbon dioxide emissions. Applying

CCS system to this kind of power plant will reduce significantly CO2 emissions. [9] [10]

In September of 2011, UK government by the Energy Technology Institute (ETI) delivered Process

Systems Enterprise (PSE) and others stakeholders like EDF, E.ON, Rolls - Royce, CO2DeepStore and

e4Tech a project to build a carbon capture and storage modelling tool-kit. The completion time for this

project is scheduled to spring of 2014.

The tool-kit allows the users to study the differences and the effects on the system at part load,

start up and shutdown, being able to identify the key issues.

This project will help to support future design of integrated CCS in power plants, analysing eco-

nomical effects on the entire cluster, help the owners and developers of power plants to understand

the all concept from power generation to storage and its trade-offs, technology suppliers that want

to understand new possibilities around the system and policy makers keen to understand the issues

around the overall CCS system.

3

The main objective of this work is the development of (pseudo) steady-state models of relevant

unit operations in pulverized coal power plants as feedwater heaters, condenser, gas gas heater,

electrostatic precipitators and flue gas desulphurization unit, as well as modelling the pulverized power

plant as a component model using the existing gCCS power plant library and implement turbine

following control and other relevant power plant control for part load operation.

A literature review was conducted to see what have already been done in this area.

1.2 State of the Art

A literature review was made to see what has been done. There is a little information regarding su-

percritical steam cycles, however several attempts have been made for static and dynamic simulation

but most deal with combined cycles or sub critical power plants.

Supercritical power plant studies were made by Sergio Espatolero [11], where an optimization of

the boiler cold-end was analyzed as well as its integration with the supercritical steam cycle. From the

same author and Romeo [2], a supercritical power plant was designed to aim the optimal integration

with the capture plant, especially the energy requirements of CO2 amine scrubbing which require

specific steam drawn offs from the turbine cycle. Both studies took place in the ASPEN software.

Falah, [12] presents a static and dynamic simulation model of a supercritical once-through heat

recovery steam generator (SC HRSG) and its application to investigate the load changes and start-

up processes for next generation high efficiency combined cycles. The work was developed in the

commercial simulation software named Advanced Process Simulation Software (APROS).

Miroslav Variny, [13] presents a part load operation study for a combined cycle to improve the

efficiency provisioning the auxiliaries services.

Performance studies were made by Chia-Chin Chuang [14], for a combined cycle power plant with

variable condenser pressure and variable load.

Some reports can be found that simulate sub critical and supercritical power plants, such as DOE

[15] and ALSTOM [16], in commercial softwares such as ASPEN. This type of reports have case

studies for real power plants considering introduction of capture plant or new arrangements to improve

the efficiency of the power plant.

Changliang Liu [17], presents and updated, from 2011, overview of the modelling and simulation of

thermal power plants. The thermal process control is review as well as the thermal process modelling

which the author categorizes in three main areas: simplified boiler-turbine models for CCS research,

dynamic models of subsystem and thermal performance calculation and optimization model. He

identifies as one of the main challenges in the future the improvement of the accuracy of the models

with actual power plant data.

Modelling and simulation is the base of optimal operation and control and plays an important role

in energy saving in thermal power plants.[17] There still more work to do on improvements of the

models and on the analysis of the supercritical power plant steam cycle. Some more studies such as

the ones made by Espatolero [11] would be welcome, however accuracy of the models need to be

4

analyzed to perform part load operations studies. Part load operation, control and the integration with

the capture plant are the main areas that can be further developed.

1.3 Original Contributions

The main contribution in this work is the development in gPROMS of steady state models adequate

for power plant simulation. The implementation of those models together with the existing gCCS

library to model a supercritical coal power plant. Moreover, the simulation of part load operation plant

adding the adequate control system.

1.4 Dissertation Outline

This dissertation is organized as follows:

Chapter 2 presents a background review focusing on carbon capture and storage technologies

such as post combustion; in power plant concepts and the thermodynamics behind the steam cycle;

the power plant equipments and their concepts and uses in the system; and to finalize a control review

was done to see what are the most typical types of control used and what is controlled.

In the chapter 3 a explanation on the materials and methodology that were used during this work.

The chapter 4 presents a description of the mathematical modeling developed, the concept and

assumptions behind the models needed to be implemented for the gCCS power plant library.

In the chapter 5, the flowsheet construction is explained and the various modes possible to sim-

ulate: design and operational. Is also presented the controls strategies implemented especially the

turbine following and a daily cycle simulation, along with the sensitivity analysis on the boiler efficiency

and on the reheat temperature in the boiler.

To finalize, chapter 6 presents the conclusions of the thesis and suggestions for future work.

5

2Background Review

Contents2.1 Carbon Capture and Storage Technologies . . . . . . . . . . . . . . . . . . . . . . 82.2 Power Plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 122.3 Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 172.4 Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

7

2.1 Carbon Capture and Storage Technologies

The main technologies being developed to capture CO2 from power plants that use coal or gas

are: Post combustion (PCC), Pre combustion and Oxy Combustion. These systems differentiate from

each other in the technology used and where CO2 in removed.

Pre-combustion capture is applicable to integrated gasification combined cycle (IGCC) power

plants, while post- and oxy-combustion capture could be applied to conventional pulverized coal (PC)-

fired power plants.

Figure 2.1: Technical options for CO2 capture from coal-power plants.[7]

Analysing the figure 2.1, is possible to see that post combustion and oxyfuel combustion have

similar concepts, being the main difference the use of oxygen instead of air in oxyfuel technology.

This concept doesn’t need capture plant after the power station which represents an advantage.

On the other hand post combustion can be applied to newly designed fossil fuel power plants,

or retrofitted to existing plants. Air is used along with coal in the boiler leading to relatively small

CO2 concentration being used different capture methods: absorbent, adsorbent, and membranes.

Some other capture methods are being study with far less emphasis: converting CO2 to mineral and

employing biofixation.

Pre-combustion technology use a totally different concept, first the coal is gasified with air or

oxygen under high pressure, then it goes to water gas-shift reactor that converts CO to CO2 while

producing additional H2, thus increasing the CO2 and H2 concentrations. CO2 removal is the second

step using Acid Gas Removal (AGR), then a hydrogen rich syngas used as a fuel in a combustion

turbine combined cycle to generate electricity.

2.1.1 Post Combustion Capture

Post combustion capture refers to the separation of CO2 from flue gas, is mainly used in typical

coal fired power plant but can also be applied to integrated gasification combined cycle (IGCC) and

8

natural gas combined cycle (NGCC).[3]

Figure 2.2: Block diagram illustrating Power Plant with Post-Combustion CO2 Capture.[3]

In a coal-fired power plant, coal is combusted with air and released heat that vaporizes water

from the steam cycle to produce energy. The combustion result composition has N2, CO2, H2O, O2,

SOx, NOx, and particulate matter. Firstly nitrous oxides are removed in selective catalytic reduction

(SCR), then particulate matter is removed from the gas in an electrostatic precipitator (ESP) followed

by flue-gas desulphurization unit to remove sulphur compounds. [8]

Conventional pulverized coal power stations release the flue gas to the stack after pollutants con-

trol, but now with CO2 emissions control flue gas will go into another process to reduce the amount of

CO2 emitted.

The type of fuel has also influence in the application of this technology to natural gas because

typical CO2 coal composition is 10-15%, but for natural gas is 4-5% and for the same amount of

power output generated coal power plant generate twice the CO2 amount than natural gas. This

means that although natural gas has less CO2 to remove, apply carbon capture to coal power plants

is less energy consuming for the same amount of CO2 capture because the composition is higher.

CO2 capture process can be done by absorption, adsorption, membranes, mineralization and

biofixation. Absorption is a chemical process where CO2 is dissolve into a liquid solution. Actually

almost every PCC projects use absorption based methods, being monoethanolamine (MEA) aqueous

solution the most common example.

In absorption based method flue gas containing CO2 is contacted with solvent in gas liquid con-

tactors (absorber), where mass transfer occurs with CO2 transfers from gas phase to liquid phase.

Then CO2 rich solution is pumped to the regenerator where is heated and CO2 is release since the

solubility decreases with temperature increase. The lean solution is circulated back to the absorber,

and the carbon dioxide collected is dried. [8]

Chemical absorption process requires the extraction of a relatively large volume of low-pressure

steam from the power plant’s steam cycle, to regenerate the solvent, which decreases the gross

electrical generation of the plant.

Adsorption is another possible choice, but still in an earlier demonstration stage. Physically CO2

is adsorbed in a surface of a solid sorbent material, which can be zeolites, zeolitic imidazolate and

metal organic frameworks.

Typically Van der Waals forces prevail for physisorption but chemisorption can happen as well with

9

stronger covalent bonding. These kinds of systems are usually applied in packed bed or fluidized bed

systems.

Adsorption could be a valid alternative to absorption analyzing heat capacities because solid heat

capacities are lower than liquids, which would reduce the energy penalties. However other effects

must be taken in account like heats of reaction, working capacity, and others.

Membranes technology could also be applied to extract CO2 from the flue gas stream. If the

membrane material is more permeable to CO2 than the other compounds, carbon dioxide will selec-

tively permeate. Partial pressure is required to create a gradient high enough to allow CO2 transport

across the membrane, that can be obtain pressuring the flue gas side, or applying vacuum to the

other side.[8]

Potentially these units can allow more flexible operation as well as providing less energy consum-

ing capture plant.

2.1.2 Pre-Combustion Capture

Pre combustion as the name implies is the method that requires CO2 capture before the combus-

tion section, outlined in figure 2.3.

Figure 2.3: Block diagram illustrating Power Plant with Pre-Combustion CO2 Capture.[3]

In the gasifier, fuel is converted into gaseous components by applying heat under pressure in the

presence of steam and limited O2. Syngas is the gasified product, rich CO and H2 mixture. In the

next step, syngas goes to the water gas shift reactor where in the presence of water, CO is converted

to CO2 and more hydrogen is produce, by the following reaction:

H2O + CO → CO2 +H2 (2.1)

After this, carbon dioxide is separated from the hydrogen that will be burnt in the combustion

turbine combined cycle to generate electricity. The capture process is accomplished under pressure

by an acid gas removal process of absorption in a solvent followed by regenerative stripping of the rich

solvent to release the CO2 . Acid gas removal systems can be chemical or physical absorbents. State

of art processes are the physical ones, with the glycol-based Selexol process and the methanol-based

Rectisol process. [3]

Physical sorbents dissolve acid gases under pressure and released when the pressure is de-

creased or the temperature increased. In a AGR unit there is two stages, the first stage absorber/stripper

to remove the sulphur and in the second stage the CO2 is remove. [8]

10

In comparison, chemical absorbents react with the acid gases and require heat to reverse the

reactions release the acid gases, this heat requires withdrawn from the steam cycle large amounts of

steam-heat for solvent regeneration. However, initial capital costs are lower than physical processes.

Pre combustion is usually associated to IGCC power plants but can also be applied to Natural gas

combined cycles and Natural gas reforming and partial oxidation.

Capture addition to IGCC reduces efficiency by 7-8 %, although this is lower than post combustion

capture still very high and some major development in capture technology is required like better

integration and IGCC component equipments (e.g. air separation unit, shift, gas turbines for hydrogen)

improvements to decrease efficiency losses. [8]

2.1.3 Oxyfuel

Oxy-combustion is an alternative to post-combustion CO2 capture for new and existing conven-

tional PC-fired power plants that offers the potential for high percentage of CO2 capture. The nitrogen

in air that is use in the combustion of Pulverized coal power plants dilute flue gas CO2 content, being

later required capture plants. Oxyfuel concept is exactly taking this nitrogen inert out, burnt the fuel

only with oxygen, this makes the flue gas CO2 content extremely high about 90% in dry basis.[3]

This technology depending on the regulations can only require minor purification (dry CO2) or

none thereby less costs than purification in PCC.

Figure 2.4: Block diagram illustrating Power Plant with Oxyfuel CO2 Capture.[3]

A simplified process schematic of oxy-combustion CO2 capture is shown in figure 2.4, flue gas

recycle is need about 80% flue gas stream to keep the boiler combustion and heat transfer character-

istics of combustion with air, having CO2 as inert instead of N2.

At the moment, there still no significant commercial scale, however oxyfuel relies on normal con-

ventional equipment that is already available at the scale necessary for power plant applications, and

key process principles like power generation is obtained by optimized integration of the steam cycle.

A major issue is the high capital and operational cost of the air separation unit that doesn’t com-

pensate impurities reduction in the flue gas. Improvements in ASU technology or the development of

more cost-effective oxygen production are required.

Two leading technologies to produce less energy consuming oxygen are:

11

• Chemical Looping Combustion (CLC)

• Ion Transport Membrane (ITM)

Chemical looping combustion idea is to separate oxygen from nitrogen by a reversible reaction

suitable by solids. Then oxygen molecules are transported to a different vessel where oxygen is

release and combustion occurs.[18]

Ion transport membrane uses selected ceramic materials that at high temperature (1000°C) and

moderate pressures allow oxygen to migrate through the solid. [8]

2.1.4 Compression and transportation

After capture the carbon dioxide it’s important to reduce its volume to a more cost effective trans-

port and storage. Carbon dioxide can be compressed to liquid or supercritical phase, critical point

is at 31.1°C and 72.9 atm. Either compression or a combination of refrigeration/pumping is done to

convert the CO2 gas to a supercritical fluid.[3]

The transport can be done by pipeline in supercritical phase, ship or road tanker if the CO2 is in

liquid phase at moderate pressures and low temperature. The method most frequently used is the

pipeline transport strategy to take the CO2 from the power plant to a selected location for permanent,

safe underground storage or beneficial reuse.[19]

2.1.5 Injection and storage

Geologic storage involves the injection of CO2 into underground formations that have the ability to

secure CO2 for long periods. Storage locations for carbon dioxide can be: [20]

• Deep saline formations

• Depleted or partially depleted oil fields

• Depleted or partially depleted natural gas fields

• Coal seams

In partially depleted oil and natural gas fields, CO2 can be used in enhance oil recovery (EOR) a

technique already well established in the oil industry. [3]

2.2 Power Plant

Coal is the most abundant fossil fuel in the world, being a relatively inexpensive energy source

however it produces relatively high levels of pollution. In 2009, almost 40 percent of the total electrical

power produce in the world was from coal source. [21]

Of the number of coal-fired electricity plants, pulverized coal (PC)-fired power plant is the most

used in electricity generation plants around the globe. The other options for coal electrical power

generation are:

• Circulating Fluidized Bed Combustion (CFBD)

• Pressurized Fluidized Bed Combustion (PFBC)

12

• Integrated Gasification Combined Cycle (IGCC)

However pulverized coal (PC) -fired power plant has the highest reliability and commercial readi-

ness for high electricity production capacity. In 2004, PC-fired power plant represented 99% of coal

total electrical production.[1]

Different PC-fired power plants types can be encountered as improvements appear along the

years. Table 2.1, compare the different types.

Table 2.1: Classification of pulverized coal power plants according to UNIPEDE.[1]

Category Unit Subcritical Supercritical Advanced UltraSupercritical Supercritical (USC)

Live steam pressure MPa 16.5 >22.1 27.5 - 30 >30Live steam temperature °C 540 540 - 560 560 - 600 >600Reheat steam temperature °C No reheat 560 580 >600Single Reheat °C No Yes Yes NoDouble Reheat - No No No YesGenerating efficency % 38 41 44 >46

A schematic figure for a pulverized coal power plant can be seen in figure 2.5. In this figure, the

entire system interaction is capture, from steam generation and steam cycle integration systems to

the power distribution grid.

Figure 2.5: Scheme of an Advanced Supercritical Power plant.[22]

2.2.1 Steam Generation

A scheme of a pulverized power plant can be found in figure 2.5. The key equipment for steam

generation is the boiler, where the coal is burned with air, to heat up and vaporize the water to generate

electricity in the steam cycle.

13

Inside the boiler there is a control of nitrogen oxides (NOx) like nitrogen dioxide and nitrogen

dioxide that are produce in the combustion, this control is done in a Selective Catalyst Reduction

(SCR) reducing NOx concentration to the legislation imposed limits. Uses ammonia to react with NOx

in the presence of a catalyst and produce water and nitrogen. An air heater can be found in the boiler

scheme as well, in the air heater the air is integrated with the hot flue gas to take advantage of the

heat still available.

Particulate removal of ash or particulate matter is done in a fabric filter or Electrostatic Precipitator

(ESP). Ash removal is followed by the sulphur removal that is done in the Flue Gas Desulphurization

unit (FGD), this uses limestone to react with the sulphur content of the flue gas and gets a sub product

which is gypsum.

After these purifications steps to control pollutants emissions, flue gas goes to the stack where is

dispersed into the atmosphere.

2.2.2 Steam Cycle

Energy production is always about transforming one type of energy into another, for example

gasoline is first burnt transforming chemical energy into mechanical energy to move the cars. First

law of thermodynamics implies the conservation of energy heat in a thermodynamic process. When

one energy form is converted into another, the total amount of energy remains constant.[23]

Power plant steam cycles try to take advantage of this principle to produce energy as much ef-

ficiently as possible, using thermodynamics. A thermodynamic cycle is a series of thermodynamic

processes at the end of which the system returns to its initial state.[24]

2.2.2.A Carnot Cycle

Figure 2.6: Carnot thermodynamic cycle.[25]

Carnot cycle was the first thermodynamics

cycle, represented in figure 2.6, four reversible

steps which two are adiabatic (2 to 3 and 4 to 1)

and the other two isothermal (1 to 2 and 3 to 4).

This is an ideal cycle being impossible to apply

in power plant design, efficiency of Carnot cycle

is the maximum thermal efficiency that a power

plant cycle could ever achieve.

It’s impossible to achieve because of techni-

cal difficulties in doing adiabatic heat exchanges,

letting turbines receive saturate steam because

originate an outlet with low quality in vapour

which cause turbines to have corrosion problems, having liquid with some vapour also cause cav-

itation problems in the pumps.[26]

14

2.2.2.B Rankine Cycle

Rankine cycle, or vapour power cycle because working fluid changes phase from liquid to vapour

within the system, gives a better description of a power plant.

A schematic of the Rankine cycle in the figure 2.7 helps to understand the system thermodynam-

ics.

Figure 2.7: Rankine thermodynamic cycle.[25]

Process 1 to 2: Pump pressurizes working fluid, having an increase of temperature in this isen-

tropic step, pump requires external power input.

Process 2 to 3: Boiler vaporizes high pressure water to the turbine, using coal or natural gas as

heat source.

Process 3 to 4: Ideally, isentropic turbine produces power from the expansion of the working fluid,

reducing pressure and temperature.

Process 4 to 1: Outlet stream from the turbines enters a condenser, where the vapor is cooled to

saturation liquid.

In a real Rankine cycle compression and expansion are not isentropic which will reduce the effi-

ciency of the system. One of the major issues is that with a high boiler pressure or a low condenser

pressure formation of liquid droplets appears in the low pressure side of the turbine, causing corro-

sion.

2.2.2.C Reheat-Regenerative Cycle

The thermodynamic cycle used nowadays in power generation stations is the Reheat-Regenerative

Cycle, as the name implies it’s a combination of two thermodynamic cycles.

Reheat cycles use two turbines instead of one, and the steam from the first turbine is reheated in

the reheater of the boiler before going to the next one.

This system has the following advantages:

• Increases the dryness of the steam, reducing the corrosion problem in the turbines.

• Increases efficiency.

• Boiler size decreases because of an increase of work done per kg of steam.

The disadvantages of reheat systems are the higher maintenance and plant equipment cost be-

cause of the reheater and its long connections, and condenser capacity is increased because of the

15

dryness increase in the turbines.

In regenerative cycles steam is extracted from the turbine at certain points during its expansion and

the steam is used for heating the feed water, more extractions usually mean an increase in efficiency.

This process reduces the energy requirement to heat the high pressure water in the boiler and

the condenser duty since less steam is needed to condensate, often this system have the problems

already describe in the turbines thus usually power plant design combine reheat cycles with regener-

ative cycles, obtaining higher efficiency than in any of the others cycles.

Figure 2.8: Reheat regenerative thermodynamic cycle.[25]

In order to understand the entire concept of a pulverized coal power plant is important to com-

prehend the termodynamic behind it. A typical flowsheet is much more complex than the scheme

presented in figure 2.8 to illustrate reheat Regenerative cycle. In figure 2.9, a typical flowsheet is pre-

sented. Complexity is exponentially increased with the number of integration draw offs being taken

from the turbines.

Figure 2.9: Representation of a power plant steam cycle.[27]

The main equipments for the steam cycle are: condenser, deaerator, feedwater heater, turbines,

governor valve, boiler and pumps.

Deaerator is an open feedwater heater where everything is mixed to bled dissolved gases, like

16

oxygen and carbon dioxide. A plant could be design only with open feedwater heaters but then a

pump would be required after each deaerator. With this configuration energy costs are reduced,

having just two pumps that overcome the pressure drops in the system.

A plant configuration with only feedwater heaters could also be designed having deaereation in

the condenser. However, in past power plants where this was tried the deaeration wasn’t as complete

and control of boiler feed pump was more difficult. Most of modern power plants have one deaerator

and the rest with feedwater heaters.

For nomenclature purpose, the condensate steam from the condenser that goes through the

closed low pressure feedwater heaters to the deaerator is called condensate. On the other hand,

the outlet stream from the deaerator is called feedwater.

2.2.3 Integration with CCS

Power plant system can be integrated with the capture plant and with the CO2 compression sec-

tion. For the capture plant usually some low pressure steam draw offs are taken from the power plant

to be used in the reboiler of the amine scrubbing, the thermal energy is needed for amine regener-

ation, typically the reboiler temperature should not exceed 120°C for MEA solvents. Optimizing this

integration point is crucial to avoid high energy penalties in the power plant.[2]

The compression section requires energy for compression and cooling water for intercooling

stages, therefore the feed water can be used in this stages to minimize cooling water requirements.

2.3 Equipment

2.3.1 Boiler

A steam generator is a closed vessel which is used to produce steam by application of heat from

the combustion of fuel to the water. A steam generator can be also called boiler. There are main types

of boiler, but the ones used in power plant exceed by far size and capacity of others. It’s a unique

piece of equipment design specifically to operate at high pressures, with large amounts of water and

with a type of fuel. [23]

Boilers can be classified as water tube or fire tube boilers, but all modern boilers are water tube.

In water tube boilers, water and steam circulates through the tubes and hot flue gas flow over these

tubes. This arrangement offer greater versatility, with more boiler capacity and pressure, and most

efficient use of the furnace, super-heater and reheater. [28]

Two different types of boiling system can be found in boilers, those that have a steam drum or those

that don’t have (termed once-through steam generators, OSTG). The most used is the steam drum

type where the drum serves as a separation point from water and steam. This is the simplest model to

control. The water heats up in the tubes before getting to the drum where steam is generated. Then

water is separated from the steam and the remaining water is then returned to the tube to be heated.

For the OSTG system the water is evaporated somewhere in the tube section. [28]

17

The boilers capacity and pressure are very wide, varying from 0.13 kg/s to 1260 kg/s and from 1

atm to pressures above the water critical pressure (217.7 atm).

Figure 2.10: Boiler schematic representation.[29]

A boiler configuration can be seen in the figure 2.10, representing a typical boiler used in pulver-

ized coal power plant. The boiler has two different sides, the steam generating and the heat recovery

system, the main components are:

• Furnace and convection pass

• Steam superheaters (primary and secondary)

• Steam reheater

• Economizer

• Steam drum

• Attemperator and steam temperature control system

• Air heater

In steam generating side, the coal is first pulverized, however this step does not happen in the

boiler. The idea behind pulverization is that if the coal were made fine enough, it would burn as

easily and efficiently as a gas. To burn successfully coal, a large quantity of fine particles should be

encountered along with some minimum coarser particles. The coal will ground and dried the primary

air and then pneumatically taken to burners inside the boiler.

This air is heated in an air preheater and then separated in primary and secondary air supply. The

secondary air, about 70 to 80% of the total hot air, is directly taken to individual burners. The primary

air with the remaining 20/30% will go the coal pulverisers. The coal and the air is rapidly mixed and

quickly burned in the furnace, releasing heat and producing the flue gas.

The air quantity is very important to insure total combustion, allowing all the carbon monoxide

to convert to carbon dioxide. Also the amount of excess air is very important because if exceeds

the theoretic excess air point the efficiency starts to drop and nitrogen oxides start to form as more

18

oxygen and nitrogen are available.

The hot outlet flue gas will then rise and exchange heat from convection to the superheater steam,

reheated steam, pass through the economizer to heat the feedwater and pass in the air heater at the

end. The superheater, reheater and economizer are usually located in the flue gas horizontal and

vertical down flow sections of the boiler.

The material used in the furnace and convection pass walls is carbon steel or low alloys, which

maintain metal temperature within limits.

In the modern boiler, the superheaters and reheaters are needed to increase plant thermal ef-

ficiency by applying the reheat principle. Therefore in the heat recovery system the feedwater will

pass first in economizer before entering the steam drum where it vaporizes to pressures that can be

above supercritical. The function of the steam drum is not only to vaporize the water, but also to

provide a storage reservoir that allows short terms imbalances between feedwater supply and steam

production. [28]

After the steam drum, the vapour will pass in two superheaters to insure supercritical feed to the

high pressure turbine. The high pressure exhaust steam will also return to be reheated in a reheater

before going to the intermediate pressure or low pressure turbine.

The main difference between superheaters and reheaters is steam pressure, because super-

heaters pressure is much higher. Physically they are a single phase heat exchangers with steam

flowing inside the tubes and the flue gas in the outlet of the tubes usually in counter current.

The steam temperature control is very important to keep temperature in their set point. Complex

combination can be used to do this temperature control, but the simpler method is attemperation, the

addition of water or low pressure steam to high temperature steam to lower the temperature. This

attemperators are usually located between superheaters or in the outlet of the second superheater

to better temperature control. The importance of temperature control is to prevent thermal expansion

from dangerously reducing turbine clearances and to avoid erosion from excessive moisture in the

last stages of the turbine. In the section 5.3 the control systems will more detailed.

2.3.2 Turbine

A steam turbine is a mechanical device that converts thermal energy in pressurised steam into

useful mechanical work. The steam turbine derives much of its better thermodynamic efficiency

because of the use of multiple stages in the expansion of the steam. This results in a closer approach

to the ideal reversible process.[23]

The steam from the boiler is expanded in a passage or nozzle where due to fall in pressure of

steam, thermal energy of steam is converted into kinetic energy of steam, resulting in the emission of

a high velocity jet of steam which impinges with the moving blades of the turbine.

Steam turbines can be classified by type of operation, direction of flow, means of heat supply,

means of heat rejection, number of cylinders, arrangement of cylinder based on general flow of steam,

number of shaft and rotational speed. However, only some classifications will be further developed.

[30]

19

Steam turbines have two principles of operation, impulse or impulse-reaction turbine.

The impulse blading principle is that the steam is directed at the blades and the impact of the

steam on the blades drives them round, the pressure at the outlet sides of the blades is equal to that

at inlet side.

In the impulse reaction turbine, the pressure drop is divided between the fixed and moving blades.

The reaction blading principle depends on the blade diverting the steam flow and gaining kinetic

energy by the reaction. Since this turbine uses both impulse and reaction principle is called impulse-

reaction turbine.[23]

The direction of the flow in a turbine can also be classified as: axial flow turbine, radial flow turbine

and tangential flow turbine.

A consideration on the heat supply can be done as well, turbines can be: single pressure turbine,

mixed or dual pressure turbine or reheated turbine.

The last classification to be mentioned is the heat rejection type: pass-out or extraction turbine,

regenerative turbine, condensing turbine, non-condensing turbine and back pressure or topping tur-

bine.

Turbines are used for a large range of power requirements. For a power calculation is a good

approximation to admit adiabatic system:

Ws = F∆H (2.2)

Isentropic efficiency can give a good idea of the turbine performance, assuming once again that

the heat lost to the surroundings is near to be zero.

ηs =hin − hout

hin − hs,out(2.3)

2.3.3 Feedwater heater/Deaerator

Feedwater heater (FWH) and deaerator are heat transfer equipments very important in the steam

cycle efficiency, allowing an increase in temperature of the feedwater thus increasing the efficiency

cycle and reducing the amount of heat duty lost in the condenser since less steam is needed.

The number of feedwater heaters used in a steam cycle depends mainly on the turbines sizes,

inlet and outlet steam conditions, the overall plant cycle and most important economic considerations.

An economic analysis is the best way to determine the optimum number of FWHs, each new

equipment introduces more capital costs with equipment, piping, valves, controls and instrumentation

and space requirements. Maintenance costs will also increase with more pumping costs to overcome

pressures drops and equipment maintenance.

On the positive side, with more feedwater heaters higher is the efficiency of the power plant, being

needed less fuel consumption which will economically improve the power plant performance.

Feedwater heaters can be classified as open or closed heat exchangers depending if mixing oc-

curs or not.

20

2.3.3.A Deaerator

Open feedwater heater or deaerator mix the extract steam with the condensate to be heated. The

objective of this equipment is to deaerate the condensate, releasing dissolved gases like oxygen,

nitrogen, ammonia and carbon dioxide that appear as a result of chemical reactions and leaks.[24]

The presence of a deaerator in the power plant is crucial since the presence of non-condensable

gases is the major cause of corrosion in feedwater piping, boiler and condensate handling equipment.

Corrosion is mainly cause by three factors: feedwater temperature, pH and oxygen content.

Dissolved oxygen in the water will cause rapid localized corrosion in boiler tubes. Carbon dioxide

will lower water pH levels and produce carbonic acid that will corrode the entire boiler system and

piping. High temperatures are a corrosion catalyst since at high temperature conditions corrosion is

more severe, increasing the effect of oxygen and pH corrosion.[31]

Remove this non condensable gases could be done by chemical additions however mechanical

removal is thermal and economically more efficient. Chemicals are only used when additional oxygen

or other non-condensable gases removal is required to control corrosion in the power plant.[32]

Mechanical deaeration is based on two principles: Henry’s Law and gas solubility variation with

temperature

Henry’s Law asserts that gas solubility in a solution decreases as the gas partial pressure above

the solution decreases. Gas solubility in a solution decreases as the temperature of the solution

increases and approaches saturation temperature.

Both of these natural processes are exploited to achieve low gas concentration in the feedwater,

therefore in design of a deaerator four conceptual ideas should be fulfilled:

• Feedwater temperature should achieve the saturation temperature to decrease gas solubility

near to zero.

• Agitation should be promoted: firstly by spraying feedwater in thin films increases the surface

area of the liquid in contact with the steam; secondly the water is cascaded over a bank of

slotted trays, further reducing the surface tension of the water.

• Steam will be sprayed in the feedwater to sweep out any gases still dissolved.

• Steam layer should be above the water level to accomplish Henry’s Law and decrease partial

pressure of non condensable gases.

Two types of steam deaerators can be found in a power plant: Spray type and Tray type.

Deaerator equipment allows a smooth transition between high-pressure and low-pressure closed

heater design and also provides proper suction conditions for the boiler feed pump in addition to

crucial task of bled dissolve gases. Disadvantages of the deaerator are being large and heavy and

require the boiler feed pump to move the liquid forward.

2.3.3.B Feedwater Heater

Closed feedwater heater is usually referred as feedwater heater (FWH). Most of this heat ex-

changer equipments configuration is a standard shell and tube but can be also header type. The inlet

21

steam enters to the shell side and the feedwater passes in the tube side.[24]

A feedwater heater is designed to preheat boiler feedwater by means of condensing steam ex-

tracted (or ”bled”) from a steam turbine. No mixing occurs between feedwater and the steam conden-

sate, passing through different sides, being the heat transfer by convection and condensation.[33]

The nomenclature of a feedwater heater is steam inlet to the extracted steam from the turbine,

drain outlet to the condensate steam, feedwater inlet and feedwater outlet to the water that goes in

the tubes. A drain inlet can also be an inlet in the shell side, being this usually an outlet drain from the

feedwater heater downstream.

Three different zones can be seen in a feedwater heater:

• Desuperheating zone

• Condensation zone

• Subcooling zone

Condensation zone is present in every FWH, this is where the steam is condensed. The other two

zones are optional depending on the function required. And can have multiple entries with a drain

inlet and steam inlet, exemplified in figure 2.11.

Figure 2.11: Schematic representation of a feedwater heater.[24]

Desuperheating zone is design to thermally assure dry wall conditions with a minimum pressure

drop loss, this is the final zone of the feed water in the tubes. Dry wall conditions prevent flashing and

provide maximum heat recovery. [34]

Sub cooling zone is totally isolated and could be either internal to the FWH or external. Usually

is an internal zone, isolated by a plate, and the drain outlet is cooled to a temperature lower than the

saturation temperature.

Feedwater heaters can be classified by operational pressure as: low pressures heaters, interme-

diate pressure and high pressure heaters.

Low pressure usually extracts steam from the low pressure turbine and is located between the

condensate pump and either the boiler feed pump or, if present, an intermediate pressure (booster)

pump.

In intermediate pressure heaters the steam is extracted from the intermediate pressure and are

located between the booster pump and the boiler feed pump.

22

High pressure usually have a tube side pressure of at least 100 bar, extracts steam from the high

pressure turbine and is located downstream from the boiler feed pump.

Different configurations can be also found in industry like, horizontal, vertical: channel up and

vertical: channel down. The most used is the horizontal version that as a better level control although

it occupies more space.

There are some parameters usually used to individual heater performance like:

• Feedwater Temperature Rise (FWTR)

• Terminal Temperature Difference (TTD)

• Drain Cooler Approach (DCA)

Feedwater temperature rise is the difference between the feedwater outlet temperature and the

feedwater inlet temperature. Terminal temperature difference is the saturation temperature of the

extraction steam minus the feedwater outlet temperature. It’s the most commonly used parameter

used to control a heater performance, a decrease in this difference indicates an improvement in the

heat transfer. Drain cooler approach the temperature difference between the drain cooler outlet and

the feedwater inlet. An increasing DCA temperature difference indicates the level is decreasing.[35]

2.3.4 Condenser

Condenser is one of the essential equipments in modern power plants, increasing considerably

the efficiency of the system.

It’s a heat transfer equipment that condenses all the steam from the turbine. For condensation

to occur, the heat vaporization must be removed from the steam and exchanged with a cooling fluid.

The cooling fluid can be water or more rarely air.

Since the pressure of the last turbine is below atmospheric pressure, so is the pressure in the

condenser, the optimum condenser pressure should be determined along with steam pressure out-

let pressure. Physical limits impose limitations to the lower pressure possible, like circulating water

flow parameters, inlet temperature and cooling water temperature rise. Typical operating pressure is

around 0.05 bar.[24]

There are two types of water cooled condensers: Surface and jet condensers.

Surface condensers don’t have direct contact between cooling water and condensate, usually are

tube and shell heat exchangers, with water in tubes and condensing steam in the shell. This type of

condenser arrangement has several advantages: the condensate can be used as boiler feed water,

cooling water can be of poor quality since it doesn’t contact with the steam and high vacuum can be

obtained (around 0.03 bar) allowing an increase of efficiency.

Since condensers operational pressure is below atmospheric air leaks into the system which

needs to be continuously removed from the system to maintain low pressure. In small condensers the

use of jet air ejectors is enough. For large condensers mechanical evacuators are used, which basi-

cally compress the air from low pressure to atmospheric pressure, this kind of equipment is specially

design is each case.[23]

23

Some disadvantages of this kind of condenser arrangement are: capital cost is higher, mainte-

nance and running cost are high and requires more space in the plant.

A power plant requirement for a proper operating is to don’t allow any sub cooling degree in

the condenser, which reduces the efficiency of the system. To prevent this sub cooling, the outlet

temperature of cooling water should be regulated to the saturation temperature of the steam.

On the other hand, jet condensers allow contact between cooling water and the steam. The water

needs to be of higher quality, and it’s mixed with sprays. Jet condensers are not the most used in

power plant designs.

Air cooled condensers are not so used in power plant industry as well because of his disadvan-

tages: higher condenser operating pressure which cause less cycle efficiency, higher capital and

operational costs, larger space requirements and noise level increase.

However, it has some advantages as well, minimizes water make-up requirements and eliminates

cooling water blow down disposal problems, cooling tower freeze up, tower vapour plume and cir-

culating water pollution restrictions. These advantages clearly points out that this equipment is best

suitable when water is scarce and water legislation restrictions are tight.

Two types of air cooled condensers can be considered:

• Jet condenser with dry cooling tower

• Direct air cooled condenser

For the first type, part of the steam condensate is cooled in a dry cooling tower, being then returned

to the condenser where it is sprayed into the steam flow, causing the steam to condensate. This

condenser needs circulating water pumps and piping to work.

In the direct air cooled condenser the steam is piped from the turbine to the steam coils where it

condensates and is collected in a tank. This type of condenser needs large steam duct and produces

a better vacuum then the jet condenser.

2.3.5 Flue Gas Desulphurization (FGD) unit

Flue gas desulphurization unit is very important in modern power plants since sulphur emission

legislation is very tight. Annually worldwide around 160 million tons are emitted to the atmosphere,

nearly half of which are from industrial sources. Sulphur dioxide in combination with liquid water easily

forms sulphuric acid the main constituent of acid rain.[28]

Sulphur dioxide control in power plants is done with one of two strategies: use of low sulphur coal

or implementation of scrubbers. Basically a chemical reaction occurs in the scrubbers, SO2 from the

flue gas stream reacts with a reagent. The efficiency of this kind of units can be high, around 95%.

Commercially available desulphurization units can be wet, semi-dry and completely dry processes.

Wet flue gas desulphurization unit is the most used technology worldwide with more than 85% of

installed capacity, however dry processes are also used for low sulphur applications.

Wet scrubbers most frequently selected for sulphur dioxide removal used limestone or lime as

reagent, but can also use magnesium enhanced lime, ammonia and sodium carbonate. Limestone

24

and lime systems are non-regenerative therefore all the reagent is consumed in the chemical reaction.

2.3.5.A Limestone forced oxidation (LSFO)

Limestone forced oxidation is the wet process most used in the industry, produces gypsum as by

product that can be sold to cement industry, manufacture of wallboard, used as fertilizer or sent to a

landfill.

A scheme of the process and the absorber can be seen in the figure 2.12.

Figure 2.12: Schematic representation of a LSFO system.[28]

Flue gas enters in a mid section in the absorber and goes upwards while limestone sprayed down-

wards in counter current. The bottom of the absorber is an integral reaction or recirculation tank,

fresh reagent is added to the tank to replenish the alkalinity required to remove SO2, the addition of

air helps to oxide the gypsum. The products are pumped out to the slurry dewatering.

The chemical reactions that describes the chemistry in the absorber are:

• Dissolving gaseous SO2

SO2(g) SO2(aq) (2.4)

• Hydrolysis of SO2

SO2(aq) +H2O HSO−3 +H+ (2.5)

• Dissolution of limestone

CaCO3(s) +H+ Ca++ +HCO−3 (2.6)

• Acid-base neutralization

HCO−3 +H+ CO2(aq) +H2O (2.7)

• CO2 stripping

CO2(aq) CO2(g) (2.8)

In the reaction tank:

• Dissolution of limestone

CaCO3(s) +H+ Ca++ +HCO−3 (2.9)

25

• Acid-base neutralization

HCO−3 +H+ CO2(aq) +H2O (2.10)

• CO2 stripping

CO2(aq) CO2(g) (2.11)

• Sulfite oxidation

O2(g) + 2HSO−3 → 2SO−

4 + 2H+ (2.12)

• Precipitation of gypsum

Ca++ + SO−−4 + 2H2O CaSO4.2H2O (2.13)

Parameters that control SO2 removal capability can be chemical or physical. Chemical parameters

are: inlet SO2 concentration, stoichiometry, pH and chlorine concentration. The physical are: liquid

to gas ratio, tray pressure drop and nozzle pressure. The alkalinity is the key to every effect on the

sulphur removal.

2.3.6 Electrostatic Precipitator

Particulate emissions need to be control in a power plant, and several technologies are available

commercially like: electrostatic precipitators, fabric filters (baghouses), mechanical collectors and

venture scrubbers.

A fabric filter is comprised of multiple compartment enclosure with each compartment containing

rows of fabric bags in the form of round, flat, or shaped tubes, or pleated cartridges. Fabric filters col-

lect particles with sizes ranging from submicron to several hundred microns in diameter at efficiencies

generally in excess of 99 or 99.9 percent.[36]

However ESP has been the most commonly used in particulate matter control. Efficiencies of

99.9% can be obtained in medium and high ash coals.

Basically a dry electrostatic precipitator electrically charges the ash particles in the flue gas to

collect and remove them, is comprised of a series of parallel and vertical metallic plates. Each plate

contains electrodes which are positively charged. When the particulate gas enters the electrostatic

precipitator and is struck with a negative charge electrode, the positively charged plate act as a

magnet and pulls the particulate gas to them.[28]

2.3.7 Gas/Gas Heater

This is heat exchanger equipment, it is important to heat up the outlet flue gas from the FGD to

avoid plume formation, since flue gas is saturated with water vapour, condensation is inevitable. This

condensation can be extremely acidic leading to the formation and accumulation of acidic deposits.

Usually, the GGH cools down the temperature of the flue gas to the FGD in order to increase the

temperature from the FGD.

26

2.3.8 Governor valve

The pressure in the steam cycle is a very important variable in to control. The governor valve

purpose in a power plant is to regulate the high pressure into the first HP turbine. When a power

demand changes the governor valve will change this pressure drop to meet the final required power.

2.3.9 Stack

Stack is a vertical structure used to convey gaseous products of combustion. The objective is

to disperse the pollutants at higher altitude to ease down its influence on the surroundings, with tall

structures the chemicals in the flue gas are neutralize in the air before they reach the ground.

2.3.10 Generator

The generator converts the mechanical shaft energy it receives from the turbine into electrical

energy. Has a stationary stator and spinning rotor with cooper as conductor. The rotor can spin with

of values from 3600 rpm.

The production of energy only happens when the power production is synchronized with grid

power. The rotor is protected in chamber cooled with hydrogen because of its high heat transfer

coefficient and low viscosity to prevent windage losses.

2.4 Control

Control is a constant and important presence in industrial world. Instrumentation and control are

essential to maintain a normal equipment operation, promoting safety and economic profit.

In control terminology, an output variable or measure variable value is compared to the setup point.

Depending on the error between those two variables the controller will adjust the manipulated value

to some obtain the desired set point value.

The proportional control is the simplest type of control where the manipulated variable is propor-

tional to the error signal. The control is always directly or inversely proportional, depending upon

the control configuration. This way, if a positive variation in the manipulated variable produces an

answer with positive value it is a directly proportional. On the other hand, if a positive variation in

a manipulated variable produces a negative variation in the set point it’s an inversely proportional

system.[28]

In this kind of control an increase of the proportional term (or gain) will reduce the final offset but

increase the time required to get to stationary state.

An introduction of an additional control parameter can eliminate the implicit offset of the propor-

tional control. The addition of Integral term reduces the offset completely but can make the system

be less stable as well as take longer to get to stationary state without any offset. The integral term

does a repetitive integration of the error signal along the time the deviation occurs.

A further and last improvement can be made to the response and stability problems of the system

with the addition of derivative control. Derivative control is used to reduce the magnitude of the

27

overshoot produced by the integral component and improve the combined controller-process stability.

However, it has some problems with the noise in the error signal since the derivative term determines

the derivative of the error signal.

2.4.1 Boiler/turbine control

The control of the boiler-turbine system is essential for a proper response to power demands.

Three main control options can be presented to a boiler/turbine system:

• Boiler following control

• Turbine following control

• Coordinated boiler turbine control

Boiler following control system implies that the boiler response follows the turbine response. In

this control mode a change in power demand will implicate a response to the throttle pressure, and a

change in the boiler pressure produces a change of the firing rate.

The turbine following control is the opposite since the turbine response follows the boiler response.

A change in power demand set point will produce a change of the firing rate, therefore the boiler

pressure will change and to main the throttle pressure constant, the turbine control valves change

position.

Coordinated boiler turbine control combines both previous control modes to exploits their advan-

tages and minimize the disadvantages. In simple terms power demand changes and throttle pressure

changes are responsibility of both boiler and turbine systems.

Coordinated boiler turbine provides a faster response than turbine following systems, however is

not as fast as boiler following systems since power error is limited to maintain a balance between

boiler response and stability.

2.4.2 Feed water control

The objective of this control is to make sure that the inlet feedwater is equal to the evaporation

rate. As simple as this sounds, some difficulties appear within this task, drum level measurement is

hard because of swelling or shrink due to steam evaporating and the interactions that changes may

cause in other location in the boiler, therefore measure the level is not sufficient to say that feedwater

supply needs to be regulated.[37]

Three main control strategies can be implemented in this case: one-, two- or three-element feed-

water control systems.

The one-element feedwater control is basically done by measuring the level and changing the

feedwater supply to maintain the level correct, however as said before phenomenon’s related to steam

vaporizing make this control system very inefficient.

Two-element feedwater control uses another concept, measuring the outlet steam flowrate and

matching the inlet feedwater to that value, with level measurement assuring correct drum level. This

kind of control system is not very used in power stations.

28

Three-element control is a cascade control system that uses three variables: drum level, steam

flow, feedwater flow. This type of control is the most used in power stations since it is the most

accurate.

Several combinations of this control can be made, however a frequently used is the following: the

level of the steam drum is controlled and measured in the secondary loop of the cascade, the primary

loop will be the difference between the feedwater flow and the steam flow measurement, however

when this values differ the control will be faster and will trim the level variations. The manipulated

variable is the feedwater valve. Controlling the system this way corrects the error produce by the

feedwater valve.

2.4.3 Steam temperature control

The outlet steam temperature from the boiler is very important it can be affected by the firing rate,

excess air, feedwater temperature, changes in fuel, ash deposits in the heat transfer surfaces and the

specific burner combination in service.[37]

The control of the temperature can be done by the following methods:

• Attemperation - attemperator is an apparatus that is used for reducing the steam temperature

by spray high purity water into an interconnecting steam pipe.

• Gas proportioning dampers - are used in control the steam temperatures by splitting the flue

gas flow rate opening the damper, and rearranging the amount of heat being transfer to the

superheaters and reheaters.

• Gas recirculation - recirculation of the flue gas after passing through the superheaters, re-

heaters, economizer and air heater.

• Excess air - increasing the excess air will also change the heat absorption pattern within the

furnace.

• Burner selection - steam temperature can be regulated by selective burner operation.

• Movable burners - can be a solution as well changing the pattern of the combustion zone will

affect the steam temperature.

• Differentially-fired divided furnaces - divided furnace sections thus heating up different sections,

e.g. one heating the superheaters and the other generating steam and providing heat to the

reheater

• Separately-fired superheaters - has the name implies the superheaters are independent of the

boiler.

2.4.4 Deaerator Control

The deaerator principles where already seen in the section 2.3.3.A, thus it is clear that the two

key parameters must be controlled for a performance. The key issues are: maintenance of the steam

pressure at an optimum value and keep a considerable level of water in the equipment.[38]

The pressure is maintained by the amount of steam being taken off the turbine draft. The level is

controlled by manipulating the condensate inlet flow a typical control for this level can be the method

29

already described for the steam drum control system as three elements. For this an additional outlet

flow measurement is required to trim level variations.[39]

The temperature can be also a controlled variable using some electric immersion heaters which

are capable of maintaining the required minimum temperature under no steam flow conditions.

2.4.5 Condenser Control

In the condenser it’s crucial to control the pressure, since as low as this pressure can be the

higher is the thermal efficiency of the power. Thus the pressure in this unit is always measured and

controlled by the cooling water inlet flowrate.[38]

The level in the condenser is also important to assure, if the level drops a make-up of water will be

introduce in the system, this make up is important to face off the water and steam losses during the

process. If an increase in the level occurs that can be related to swelling effects already described or

by a failure in the feedwater pumping system, therefore requiring immediate operator actions.[39]

2.4.6 Feedwater heaters Control

In a feedwater heater the level control is essential to good maintenance of the heat transfer effi-

ciency. The maximum heat transfer takes place when the largest tube area is exposed to the steam

without allowing steam blow-through. Condensate is allowed to drain from the shell through the nor-

mal drain. When the tubes become submerged in condensate, heat is transferred to the condensate

rather than the tubes with the feedwater inside, resulting in poor heater efficiency.

Therefore, the level control is implemented in feedwater heaters, the level is measured and the

manipulated will be the outlet drain condensate valve, obviously changing the flowrate of the outlet

drain.

The steam draft flow is usually imagined as a control system where the temperature is controlled

by the amount of steam taken from the turbine however FWH have a self-regulating feature. There

are no control valves on the extraction steam supply lines. The steam flow adjusts itself by a thermal

equilibrium process. When the feedwater temperature approaches the saturated steam temperature

then condensation of the extraction steam diminishes and therefore the flow of extraction steam to

the feedwater heater tends towards zero.

30

3Materials and Methods

Contents3.1 gPROMS software . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 323.2 Model development workflow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 323.3 gCCS model library . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 333.4 gCCS structure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

31

3.1 gPROMS software

The software used in this work was the gPROMS from the Process Systems Enterprise the com-

pany that developed it and holds its rights. It is a platform for high-fidelity predictive modelling for

the process industries. Advanced Process Modelling environment where it is possible to create first

principle models or simply use the gPROMS model libraries.

Models are built using fundamental chemistry, physics, chemical engineering, operating proce-

dures and other relationships to fully capture with high fidelity the behaviour of the system being

modeled. Different activities can be simulated such as: steady state and dynamic simulation, param-

eter estimation, model-based experiment design and optimisation.

gPROMS is an equation based modelling system resulting on a numerical solution of all the equa-

tions in a model or a flowsheet at the same time. This type of numerical resolution has several

advantages increasing the robustness and fastness in comparison with traditional sequential-modular

simulation approaches.

gPROMS offers a number of products and complete libraries for diverse applications, products

examples are: gSOLIDS, gCRYSTALS, gSAFT, gFLARE, gFuelCell and in the interest of this work

the future product gCCS.

3.2 Model development workflow

gCCS is a new product that is now being developed by PSE and as previously stated this work is

integrated in it, being necessary to develop the models and basis from scratch, making them obviously

physical and chemically correct as well as, in a robust and simple modelling writing to be integrated in

large flowsheets. The evolution of the work is described in the figure 3.1 where a model development

flowchart is presented.

The first step is to study the technical specification required for each model, doing a detailed

bibliographic review getting in touch with all the concepts, objectives, specific characteristics and

physical constraints of the model. Analyze the equations of the system and its variables to know the

degrees of freedom (DOF).

The next step is to make the model specification document (MSD) where all the assumptions,

equations, variables and degrees of freedom of the model are clearly explained. After the MSD

is reviewed the implementation of the model in gPROMS starts, in this step all that was stated in

the MSD is transcript to gPROMS language, created the user dialog box according to the expected

assignments and the model report.

Tests within physical constraints of the system are applied to the model and the results checked,

usually model refinement is required changing equations, improving thermodynamics calculations or

developing initialization procedures to increase robustness of the model.

The final step of a model development is to check the results of predictive simulations against data

processing from the partners and confirm the accuracy of the model. If the model does not pass the

32

predictive simulations refining is necessary to make it more accurate. After being review by the chief

technologist the final model document can be produced.

Figure 3.1: Model development workflow.[40]

Once the models are tested and verified connecting different models to make a flowsheet is the

next step and will complement the analysis made for the DOF of model in the early stages of the

workflow. The degree of freedom of the flowsheet is now required and can eventually affect the dialog

box options of simple models. The construction of a flowsheet is done connecting model by model,

to avoid recirculation of information which causes some troubles in gPROMS. The solution found to

solve this issue is explained in the chapter 5.1.

The development of a power plant flowsheet requires several models that were divided by the

members of the gCCS power plant team. Connecting them together and initialise a complex flowsheet

is a hard task, requiring the deep knowledge of all models to be able to calculate their DOF and the

global value for the entire flowsheet. After being tested in the flowsheets some models can return to

the early stages of development requiring a new arrangement of assignments.

3.3 gCCS model library

In the early stages of the work a gCCS library was already been developed by the several members

of the power plant team. The models can be categorized by their importance in representing the power

plant configuration, those models are described as main equipments of the power plant, however to

build a consistent flowsheet some other auxiliary simple models were introduced and for last the

models introduced only for control purpose can be listed as well.

33

The main equipments available in the libray were: the boiler, the turbine, the deaerator and the

governor valve. The auxiliary models were: the drum, the pump, the blower, the generator, the recycle

breaker, the source coal, source air, source utility, sink utility, sink waste, the stack and the junction.

The following missing models in the library were mathematically modeled: feedwater heater, con-

denser, electrostatic precipitator, flue gas desulphurization unit, gas gas heater and the control valve.

Appendix A is the review and summary of all the characteristics and specification options available

for all the models used. Typically all the models have a design and operational mode, design mode

is used when the stream conditions are fixed and the parameters of the equipments such as areas

and efficiencies are calculated. In operational mode those parameters are specified and the stream

conditions are determined.

3.4 gCCS structure

gPROMS is a very powerful tool that solves difficult mathematical problems. It allows the user

to write first principle models that can later be used as drag and drop to build large and complex

flowsheets.

The models communicate with the exterior through ports and connections, which depending on

the type can pass different types of information. In the gCCS there are several types of connections:

UtilityFluid, ProcessFluid, Coal, Power and Control ports. After connecting all the models, the assign-

ments must be done in the process. If the model have the specification dialog box the assignments

are automatically updated in the process otherwise must be done manually. The advantages of the

process is that with only one model several processes can be used simultaneously.

The physical property package Multiflash was used to obtain the thermodynamics properties of

the compounds. An example of a property call is :

T hot,satout = PhysProp.DewTemperature(pout, 1) (3.1)

This equation written gives the saturation temperature of the water at the outlet pressure. In

the multiflash package is possible to choose the thermodynamics more adequate to the different

connection types. For the UtilityFluid connection was used the steam tables 1995 version: IAPWS-95,

as the name suggests this connection was used for all the steam cycle. The ProcessFluid connection

that is used for the flue gas side used the Peng-Robinson 1978 equation of state.

34

4Mathematical Modelling of PCPP

Components

Contents4.1 Feedwater Heater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 364.2 Boiler Steam Condenser . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 414.3 Electrostatic Precipitator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 444.4 Flue Gas Desulphurisation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 474.5 Gas/Gas Heater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 524.6 Control Valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

35

In the power plant several models were required and the responsibility of modelling each piece

of equipment was divided by the members of the gCCS power plant team. The models developed in

this work are described in this chapter: the feedwater heater, boiler steam condenser, electrostatic

precipitator, flue gas desulphurization unit, gas gas heater and the control valve.

The description of the models only include the assumptions used and the general equations, the

manipulation of equations to make the models more robust and the initialisation procedures are not

presented since it is classified information.

4.1 Feedwater Heater

The FeedWaterHeater (FWH) model is used to pre-heat boiler feed water using condensing steam

from the turbines and is usually used to determine that steam flowrate drawn off from the turbine. This

is a lumped and steady-state model.

There can be two or more inlet streams, these streams are first mixed and the properties of the

mixture are estimated by mass and energy balances. The only exception is the inlet pressure which

is assumed to be the minimum of all the inlet steam pressures.

It is assumed that the inlet and outlet feedwater is in liquid phase and the outlet steam condensate

can be liquid or vapour phase. For the design of the equipment logarithmic mean temperature differ-

ence is used and a constant overall heat transfer coefficient is assumed to estimate the heat transfer

area required.

The model includes temperature relationships such as terminal temperature difference and drain

effectiveness, these type of temperatures relationships are more or less constant in the feedwater

heaters relating the temperatures with the pressure of the system. They are very important in part

load operations because the pressures of the system start to decrease but these relations are kept

constant.

4.1.1 Inlets

• One UtilityFluid inlet port representing the inlet feed water.

• One UtilityFluid inlet port representing the inlet steam from the turbines.

• One array of UtilityFluid inlet port representing the inlet(s) drain(s) from another feedwater

heater.

4.1.2 Outlets

• One UtilityFluid outlet port representing the outlet steam condensate drain from the feedwater

heater.

• One UtilityFluid outlet port representing the heated feed water from the feedwater heater.

36

4.1.3 Variables Nomenclature

Table 4.1: Nomenclature of the variables used in the feedwater heater model.

Symbol Definition Units Array Size

Fin Mass flowrate of the hot side kg s−1 –FFW Mass flowrate of the cold side kg s−1 –Tin Inlet temperature of the hot side K –Tout Outlet temperature of the hot side K –TFW

in Inlet temperature of the cold side K –TFW

out Outlet temperature of the cold side K –T hot,sat

out Dew temperature of the steam K –TTD Terminal temperature difference K –DCA Drain cooler approach K –FWTR Feed water temperature rise K –Deff Drains effectiveness K –∆Tin Inlet temperature difference K –∆Tout Outlet temperature difference K –pin Inlet pressure of the hot side Pa –pout Outlet pressure of the hot side Pa –pFW

in Inlet pressure of the cold side Pa –pFW

out Outlet pressure of the cold side Pa –∆pshell Pressure drop on the hot side Pa –∆pFW Pressure drop on the cold side Pa –hin Inlet specific enthalpy of the hot side J kg−1 –hout Outlet specific enthalpy of the hot side J kg−1 –hFW

in Inlet specific enthalpy of the cold side J kg−1 –hFW

out Outlet specific enthalpy of the cold side J kg−1 –Q Heat duty W –A Heat transfer area m2 –∆lmT Logarithmic mean differential temperature K –U Overall heat transfer coefficient W m−2 K−1 –

4.1.4 Equations

The inlet port connections are used to obtain the inlet conditions to the hot stream in the FWH via

a material and energy balance. The inlet pressure is assumed to be the lowest pressure among the

Inlet ports. Mass balance for the mixing section:

F [Steam] +

Nauxin∑i=1

F [aux]i = Fin (4.1)

Energy balance for the mixing section:

F [Steam].h[Steam] +

Nauxin∑i=1

F [aux]i .h[aux]i = Fin.hin (4.2)

A p-h flash call is used to obtain the inlet temperature:

Tin = PhysProp.PHFlash(pin, hin, 1) (4.3)

pin = mini

(p[Steam], p[aux]i) (4.4)

37

Energy balance for the heat exchange:

Q = Fin.(hin − hout) (4.5)

Q = FFW.(hFWout − hFW

in ) (4.6)

Design calculation:

Q = U.A.∆lmT (4.7)

A counter current flow is asssumed therefore the logarithmic mean temperature difference is de-

fined by:

∆Tin = T hotin − T cold

out (4.8)

∆Tout = T hotout − T cold

in (4.9)

∆lmT =∆Tin −∆Tout

ln (∆Tin/∆Tout)(4.10)

Outlet pressure calculation:

pout = pin −∆pshell (4.11)

pFWout = pFW

in −∆pFW (4.12)

The enthalpy estimation for the feedwater stream:

hFWin = PhysProp.LiquidEnthalpy(TFW

in , pFWin , 1) (4.13)

hFWout = PhysProp.LiquidEnthalpy(TFW

out , pFWout , 1) (4.14)

Oulet drain enthalpy :

hout = PhysProp.Enthalpy(Tout, pout, 1) (4.15)

Outlet saturation temperature:

T hot,satout = PhysProp.DewTemperature(pout, 1) (4.16)

Temperature differences:

TTD = T hot,satout − TFW

out (4.17)

DCA = Tout − TFWin (4.18)

FWTR = TFWout − TFW

in (4.19)

Drain effectiveness:

Deff =T hot,sat

out − Tout

T hot,satout − TFW

in

(4.20)

38

4.1.5 Degree of freedom

Analysing the number of variables and the number of equations the degrees of freedom of the

model are:

DOF = Nvar −Neq = (27 + 3[Steam] + 3.N [aux])− 20 = 7 + 3[Steam] + 3.N [aux] (4.21)

The feedwater heater specification will include the following mandatory specifications, note that in

some options no inlet steam flowrate is provided in the model but an additional specification replaces

that one and the steam flowrate drawn off is determined:

1. Inlet streams:

• Feedwater inlet - Temperature, pressure and flowrate.

• Drain inlet(s) - Temperature, pressure and flowrate.

• Steam inlet - Temperature and pressure.

2. Overall heat transfer coefficient

3. Pressure drop on the cold side

4. Pressure drop on the hot side

Additional Specifications:

1. With steam flow calculated

• Design

Any one of: Drain outlet temperature, Drain cooler approach or Drain effectiveness

Any one of: Outlet feedwater temperature, Terminal temperature difference or Feed-

water temperature rise.

• Operational

Heat transfer area

Any one of: Terminal temperature difference or Feedwater temperature rise, Drain

cooler approach or Drain effectiveness

2. With steam flow known

• Inlet stream: Steam flowrate.

• Design

Any one of the outlet temperatures or temperatures approaches.

• Operational

Heat transfer area

4.1.6 gPROMS interface

This section is only presented for the feedwater heater to exemplify and show how the gPROMS

inputs should be done and how the results are presented. One of the feedwater heaters specification

can be seen in the figure 4.1:

39

Figure 4.1: gCCS feedwater heater example of a specification.

Using this specification in a flowsheet and specifying the inlets. The outlets of the feedwater

heater, the steam flowrate, the heat transfer area and the logarithmic mean temperature difference

are calculated. An example of the gPROMS software environment is presented in the figure 4.2.

Figure 4.2: gCCS environment for a fwh simulation.

40

4.2 Boiler Steam Condenser

Figure 4.3: gCCS boiler steam condenser model con-figuration.

The BoilerSteamCondenser model is used

for condensation of low-pressure steam, using

cooling water. This is a lumped and steady state

model that is usually used to calculate the value

of the cooling water flowrate.

There can be two or more inlet streams,

these streams are first mixed and the properties

of the mixture are estimated by mass and en-

ergy balances. The only exception is the inlet

pressure which is assumed to be the minimum

of all the inlet steam pressures.

Is assumed that the inlet and outlet cooling water is in liquid phase and the outlet steam conden-

sate is saturated.

For the design of the equipment logarithmic mean temperature difference is used and a constant

overall heat transfer coefficient is assumed, to estimate the heat transfer area required for the system.

This model have a control port that passes the pressure in the condenser to the controller, the model

is presented in the figure 4.3.

4.2.1 Inlets

• One array of UtilityFluid inlet ports representing the inlet steam to condenser.

• One UtilityFluid inlet port representing the inlet cooling water to condenser

4.2.2 Outlets

• One UtilityFluid outlet port representing the outlet steam condensate from the condenser.

• One UtilityFluid outlet port representing the cooling water return from the condenser.

• One ControlSignal port for pressure measurement.


Table 4.2: Nomenclature of the variables used in the condenser model.


Fhot Mass flowrate of the hot side kg s−1 –Fcold Mass flowrate of the cold side kg s−1 –T hot

in Inlet temperature of the hot side K –T hot

out Outlet temperature of the hot side K –T cold

in Inlet temperature of the cold side K –T cold

out Outlet temperature of the cold side K –T hot,sat

out Dew point temperature of the steam K –Tmindiff Minimum temperature difference K –∆Tin Inlet temperature difference K –

Continued on next page

41

Table 4.2 – Continued


∆Tout Outlet temperature difference K –phot

in Inlet pressure of the hot side Pa –pspec Pressure specified by the user Pa –pcondenser Pressure in the condenser Pa –pcold

in Inlet pressure of the cold side Pa –pcold

out Outlet pressure of the cold side Pa –∆pcold Pressure drop on the cold side Pa –hhot

in Inlet specific enthalpy of the hot side J kg−1 –hhot

out Outlet specific enthalpy of the hot side J kg−1 –hcold

in Inlet specific enthalpy of the cold side J kg−1 –hcold

out Outlet specific enthalpy of the cold side J kg−1 –Q Cooling load for the condenser W –A Heat transfer area m2 –∆lmT Logarithmic mean differential temperature K –U Overall heat transfer coefficient W m−2 K−1 –

4.2.4 Equations

The inlet port connections are used to obtain the inlet conditions of the hot stream in the condenser

via a material and energy balance. The inlet pressure is assumed to be the lowest pressure among

the Inlet ports.

Mass balance for the mixing section ([Inlet]i is the ith Inlet port):

Nhotin∑i=1

F [Inlet]i = Fhot (4.22)

Energy balance for the mixing section:

Nhotin∑i=1

F [Inlet]ih[Inlet]i = Fhothhotin (4.23)

A p-h flash call is used to obtain the inlet temperature:

T hotin = PhysProp.PHFlash(phot

in , hhotin , 1) (4.24)

photin = min

i(p[Inlet]i) (4.25)

Pressure in the condenser will be:

pcondenser = min(photin , pspec) (4.26)

It’s important to track down if pcondenser is higher then photin which is physically impossible.

The outlet pressure of the cooling water will be:

pcoldout = pcold

in −∆pcold (4.27)


Q = Fhot(hhotin − hhot

out) (4.28)

42

Q = Fcold(hcoldout − hcold

in ) (4.29)

Design calculation:

Q = UA∆lmT (4.30)

Assuming counter current flow, logarithmic mean temperature difference is defined:

∆Tin = T hotin − T cold

out (4.31)

∆Tout = T hotout − T cold

in (4.32)

∆lmT =∆Tin −∆Tout

ln (∆Tin/∆Tout)(4.33)

One of the assumptions of the model is that the outlet condensate is saturated therefore the outlet

temperature of the condensate fluid will be:

T hot,satout = T hot

out (4.34)

T hot,satout = PhysProp.DewTemperature(phot

out, 1) (4.35)

Minimum temperature difference of the system is always between the outlet condensate tempera-

ture which is the saturation temperature and the outlet temperature of the cooling water:

Tmindiff = T sathot − T cold

out (4.36)

Specific enthalpy estimation for the cooling water:

hcoldin = PhysProp.LiquidEnthalpy(T cold

in , pcoldin , 1) (4.37)

hcoldout = PhysProp.LiquidEnthalpy(T cold

out , pcoldout , 1) (4.38)

Specific enthalpy for the working fluid:

hhotout = PhysProp.LiquidEnthalpy(T hot

out , photout, 1) (4.39)



model are:

DOF = Nvar −Neq = (24 + 3.Nhotin )− 18 = 6 + 3.Nhot

in (4.40)

The condenser specification will include the following mandatory specifications:

1. Inlet streams:

• Steam inlet(s) - Temperature, pressure and flowrate.

• Cooling water inlet - Temperature and pressure.

2. Overall heat transfer coefficient

3. Cooling water side pressure drop


43

1. With cooling water flow calculated

• Design

Condenser pressure

Any one of: Outlet cooling water temperature or Minimum temperature difference

• Operational

Heat transfer area

Any one of: Condenser pressure, Outlet cooling water temperature or Minimum tem-

perature difference

2. With cooling water flow known

• Inlet stream: Cooling water flowrate.

• Design

Condenser pressure

• Operational

Heat transfer area

4.3 Electrostatic Precipitator

Figure 4.4: gCCS electrostatic precipitator model con-figuration.

The Electrostatic Precipitator model removes

the required particulate matter from the inlet

stream, the outlet ash concentration or the unit

efficiency can be specified. The model esti-

mates the amount of power required to perform

this operation with empirical equations. The

pressure drop across the equipment is not es-

timated, must be an input from the user.

This is a steady-state and lumped model. No

explicit modelling of the particulates themselves or the equipment is done and no temperature change

is considered. The outlet flue gas is in gas phase nothing condenses and only ash is removed.

4.3.1 Inlets

• One ProcessFluid inlet port representing the inlet flue gas.

4.3.2 Outlets

• One ProcessFluid outlet port representing the outlet flue gas.


44

Table 4.3: Nomenclature of the variables used in the electrostatic precipitator model.


Fin Inlet mass flowrate kg s−1 –Fout Outlet mass flowrate kg s−1 –Fashout Outlet ash mass flowrate kg s−1 –win Inlet mass fraction – C (Components)wout Outlet mass fraction – Cwashout Auxiliary outlet ash mass fraction – Cxin Inlet mole fraction – Cxout Outlet mole fraction – C

xdryin,O2

Mole fraction of the oxygen in the inlet dry flue gas % –xdry

out,O2Mole fraction of the oxygen in the outlet dry flue gas % –

γin,ash Concentration of the ash in the inlet flue gas mg Nm−3 –γout,ash Concentration of the ash in the outlet flue gas mg Nm−3 –pin Inlet pressure Pa –pout Outlet pressure Pa –∆p Pressure Drop in the ESP Pa –hout Outlet specific enthalpy J kg−1 –ρin Density of the inlet stream kg m−3 –ρnormal

in Normal density of the inlet stream kg m−3 –ρnormal

out Normal density of the outlet stream kg m−3 –κash,cap Ash capture rate tph –η Efficiency of ash removal % –P Electrical consumption of the unit W –

4.3.4 Equations

Efficiency expression:

η =γin,ash − γout,ash

γin,ash.100 (4.41)

Conversion between molar and mass fractions:

wout,i = xout,iMi∑C

i=1(Mixout,i)(4.42)

win,i = xin,iMi∑C

i=1(Mixin,i)(4.43)

Mass balance:

Finwin,i = Foutwout,i + Fashoutwashout,i (4.44)

Total Composition Restriction:C∑i=1

xout,i = 1 (4.45)

In the outlet ash stream, only ash is present so:

washout,ash = 1 (4.46)

washout,i = 0 (4.47)

Outlet pressure:

∆p = pin − pout (4.48)

45

The concentration should be reported in terms of mg/Nm3, corrected to dry gas at 6% O2 because

this is how it is reported to the authorities and checked if the values are within the limits.

γin,ash = f(win,ash, ρnormalin , xdry

in,O2) (4.49)

γout,ash = f(wout,ash, ρnormalout , xdry

out,O2) (4.50)

(Concentration should be converted from kg.Nm−3 to mg.Nm−3)

The inlet and outlet concentration correction for the oxygen in the dry flue gas:

xdryin,O2

=xin,O2

1− xin,H2O.100 (4.51)

xdryout,O2

=xout,O2

1− xout,H2O.100 (4.52)

ρnormalin = PhysProp.Density(Tstandard, pstandard, win) (4.53)

ρnormalout = PhysProp.Density(Tstandard, pstandard, wout) (4.54)

The outlet enthalpy is:

hout = PhysProp.VapourEnthalpy.(Tout, pout, w) (4.55)

The power consumption of the ESP is quite variable, however there is a clear relationship between

capture efficiency and the power, to achieve greater efficiencies more power will be required. The

specific power relationship with the efficiency can be found in figure 4.5.

A two branch equation was found fitting the relation in figure 4.1, using TableCurve 2D version

5.01. The equation was rearranged to obtain the following power (W) expression:

P =

1100.

Fin

ρinif η > 99.9

21.94 + 0.22.η

1− 0.02.η + 9.04.10−5η2.Fin

ρinotherwise

(4.56)

Figure 4.5: Specific power relationship with the efficiency of an ESP unit.[41]

46

To estimate the power requirement is necessary to know the density of the inlet flue gas:

ρin = PhysProp.Density(T, pin, win) (4.57)

The ash capture rate of the ESP unit is estimated by the following expression (conversion is re-

quired to have the ash capture rate in tonnes per hour):

κash,cap = (γin,ash − γout,ash).Fin

ρin(4.58)


The degrees of freedom of the model are:

DOF = Nvar −Neq = (17 + 5.C )− (12 + 4C ) = 5 + C (4.59)

The electrostatic precipitator specification includes the following mandatory specifications:

1. Inlet stream - Temperature, pressure, composition and flowrate.

2. Pressure drop across the equipment.


1. Outlet ash concentration or the removal efficiency.

4.4 Flue Gas Desulphurisation

Figure 4.6: gCCS FGD model configuration.

The flue gas desulphurisation (FGD) unit re-

moves sulphur dioxide of the flue gas to a certain

specification level. Either the sulphur content in

the outlet flue gas stream is specified or the unit

efficiency (of sulphur removal).

The model estimates the power and material

requirements based on the outlet sulphur diox-

ide content specification. The outlet temperature

and composition is also estimated by the model.

The wet flue gas desulphurisation system is

modelled, specifically the limestone forced oxi-

dation (LSFO). The following reaction will take

place in the FGD unit:

CaCO3 +1

2O2 + 2H2O + SO2 → CaSO4.2H2O + CO2 (4.60)

This is a steady-state and lumped model. Desulphurisation operation is not detailed modelled, ra-

tio and stoichiometric data used for estimation of the material requirements. The outlet water content

in the flue gas is determined assuming saturation and in the enthalpy balance the model only takes

into account the liquid and vapour components, the solids are ignored. Another assumption is that

the outlet liquid content is only water and dissolved carbon dioxide.

47

4.4.1 Inlets

• One ProcessFluid inlet port representing the inlet flue gas.

4.4.2 Outlets

• One ProcessFluid outlet port representing the outlet flue gas.


Table 4.4: Nomenclature of the variables used in the FGD model.


η Efficiency of SO2 removal % –Fin Inlet mass flowrate kg s−1 –Fout Outlet mass flowrate kg s−1 –Fw Inlet water in the system kg s−1 –F SO2

removed Removed mass of sulphur dioxide kg s−1 –Flime Required limestone mass flowrate kg s−1 –Fair Required air mass flowrate kg s−1 –Fgyp By-product gypsum mass flowrate kg s−1 –win Mass fraction of the inlet stream – Cwout Mass fraction of the outlet stream – Cxout Molar fraction of the outlet stream – Cwair Mass fraction of the air stream – Cww Mass fraction of the water stream – C

xdryout,O2

Mole fraction of the oxygen in the outlet dry flue gas % –ww

out Mass fraction of the outlet liquid flowrate – –xw

out Mole fraction of the outlet liquid flowrate – –γout,SO2

Concentration of the SO2 in the outlet flue gas mg Nm−3 –Tin Flue gas inlet temperature K –T Inlet temperature of the reactants K –Tout Outlet temperature K –pin Inlet pressure Pa –pout Operational pressure Pa –∆p Pressure drop Pa –hin Inlet specific enthalpy to the FGD J kg−1 –hout Outlet specific enthalpy of the FGD J kg−1 –hgyp Limestone’s water specific enthalpy J kg−1 –hlime Gypsum’s water specific enthalpy J kg−1 –hw Make up water specific enthalpy J kg−1 –hair Air specific enthalpy J kg−1 –wtlime Limestone’s solids content – –wtgyp Gypsum’s solids content – –wgyp Outlet water content in solid gypsum – –ρnormal

out Normal density of the outlet stream kg m−3 –ρin Density of the inlet stream kg m−3 –ρw

out Density of the water kg m−3 –∆rH

Θ Standard heat of reaction J mol−1 –rCaCO3/SO2

Molar ratio of limestone/SO2 removed – –HCO2,H2O Henry coefficient for carbon dioxide in water Pa m3 mol−1 –µlime Purity of the limestone – –P Power requirement W –

48

4.4.4 Equations

Efficiency definition is:

η =Finwin,SO2

− Foutwout,SO2

Finwin,SO2

(4.61)

and

F SO2

removed = Finwin,SO2− Foutwout,SO2

(4.62)

Conversion between molar and mass fractions:

wout,i = xout,iMi∑C

i=1(Mixout,i)(4.63)

Total Composition Restriction:C∑i=1

xout,i = 1 (4.64)

The pressure in the system is given by the following equation:

∆p = pin − pout (4.65)

Mass balance for the nitrogen:

win,N2Fin + wair,N2

.Fair = wout,N2.Fout (4.66)

For carbon dioxide:

win,CO2.Fin + F SO2

removed.MCO2

MSO2

= wout,CO2.Fout + (1− ww

out).Fgyp.1− wtgyp

wtgyp(4.67)

xout,CO2=HCO2,H2O.(1− xw

out)

pout(4.68)

The carbon dioxide is the most important component in the system this way its losses must be

well taken in account, so the dissolution in water will be function of the operational temperature: [42]

HCO2,H2O = exp

(11.25− 395.9

Tout − 175.9

).ρw

out

MH2O.1000 (4.69)

ρwout = PhysProp.LiquidDensity(Tout, pout, ww) (4.70)

For water, estimation of the vapor pressure [43] must be done:

pvapour = −2846.4 + 411.24.(Tout − Tref)− 10.554.(Tout − Tref)2 + 0.16636.(Tout − Tref)

3 (4.71)

xout,H2O =pvapour.x

outw

pout(4.72)

Where Tref = 273.15 K.

The mass balance for the water is presented in the following equation:

win,H2O.Fin + Fw + Flime.1− wtlime

wtlime

= wout,H2O.Fout + woutw .Fgyp.

(1− wtgyp

wtgyp+ wgyp

)+ 2.F SO2

removed

MH2O

MSO2

(4.73)

49

The conversion between mass and molar fraction for the liquid outlet, water and carbon dioxide,

is:

woutw .(MCO2 .(1− xout

w ) +MH2O.xoutw ) = MH2O.x

outw (4.74)

Total mass balance:

Fin +Flime

wtlime+ Fwater + Fair = Fout +

Fgyp

wtgyp(4.75)

For all the components except sulphur dioxide, water, oxygen, carbon dioxide and nitrogen the

following equation is applied:

Fin.win,i = Fout.wout,i (4.76)

Estimation of material requirements:

Flime.µlime = rCaCO3/SO2.MCaCO3

MSO2

.F SO2

removed (4.77)

FAir =F SO2

removed

wair,O2

.MO2

MSO2

(4.78)

Typically the gypsum brings a certain percentage of water (wgypsum) and the rest of limestone that

didn’t react.

Fgyp = f(wgypsum, FSO2

removed, rCaCO3/SO2, µlime) (4.79)

Enthalpy balance:

Fin.hin +

(1− wtlime

wtlime

)Flime.hlime + Fairhair

= Fout.hout +

(wgyp +

1− wtgyp

wtgyp

)Fgyp.hgyp + ∆rH

Θ.F SO2

removed

MSO2

(4.80)

The enthalpy of reaction is calculated by:

∆rHΘ = ΣνB∆fH

ΘB − ΣνA∆fH

ΘA = −318964 Jmol−1 (4.81)

γout,SO2= f(wout,SO2

, ρnormalout , xdry

out,O2) (4.82)

Concentration correction for the oxygen in the dry flue gas :

xdryout,O2

=xout,O2

1− xout,H2O(4.83)

ρnormalout = PhysProp.Density(Tstandard, pstandard, wout) (4.84)

Enthalpy calculation:

hgyp = PhysProp.LiqudiEnthalpy(Tout, pout, ww) (4.85)

hlime = PhysProp.LiquidEnthalpy(T, pout, ww) (4.86)

hwater = PhysProp.LiquidEnthalpy(T, pout, ww) (4.87)

The lime and gypsum are only liquid enthalpy beacause of the assumption already stated before

that the solids enthalpy are ignored, note that in liquid phase can only be found water and/or carbon

dioxide. For hAir, hout and hin vapour enthalpy calls are used to determine the required enthalpy.

50

Power expression was provided by one of the partners in this project (E-On), therefore is confi-

dential and is only represented the relationship behind:

P = f(F SO2

removed, Fin, ρin) (4.88)

ρin = PhysProp.Density(Tin, pin, win) (4.89)

Air stream assigned:

wair =

0.79 for N2

0.21 for O2

0 other components

(4.90)

Water stream assigned:

ww =

1 for H2O

0 other components(4.91)


The degrees of freedom of the model are:

DOF = Nvar −Neq = (5C + 35)− (4C + 25) = C + 10 (4.92)

The FGD specification will include the following obligatory specifications:

1. Inlet stream - Temperature, pressure, composition and flowrate.

2. Any of this:

• Operational pressure

• Pressure drop

3. Any of this:

• Efficiency

• Outlet SO2 mass fration

• Outlet SO2 mole fration

• Outlet SO2 concentration

4. Limestone in slurry


1. In advanced mode (in standard mode this values are assigned as default)

• Molar ratio limestone/sulphur dioxide removed

• Limestone purity

• Slurry temperature

• Solids content in gypsum

51

4.5 Gas/Gas Heater

The gas/gas heater model is a simple heat exchanger, exchanging heat from two gas streams.

The user needs to assign the hot outlet temperature or the heat duty. The pressure drop and the heat

transfer efficiency should be specified by the user as well. This a steady state and lumped model.

4.5.1 Inlets

• One ProcessFluid inlet port representing the inlet hot stream usually from the ESP unit.

• One ProcessFluid inlet port representing the inlet cold stream typically from the FGD unit.

4.5.2 Outlets

• One ProcessFluid outlet port representing the outlet hot stream that goes to the FGD.

• One ProcessFluid outlet port representing the outlet cold stream that goes for the stack.


Table 4.5: Nomenclature of the variables used in the GGH model.


Fhot Mass flowrate of the hot side kg s−1 –Fcold Mass flowrate of the cold side kg s−1 –whot Mass fraction of the hot side – Cwcold Mass fraction of the cold side – CT hot

in Inlet temperature of the hot side K –T hot

out Outlet temperature of the hot side K –T cold

in Inlet temperature of the cold side K –T cold

out Outlet temperature of the cold side K –phot

in Inlet pressure of the hot side Pa –phot

out Outlet pressure of the hot side Pa –pcold

in Inlet pressure of the cold side Pa –pcold

out Outlet pressure of the cold side Pa –∆p Pressure drop on the hot side Pa –hhot

in Inlet specific enthalpy of the hot side J kg−1 –hhot

out Outlet specific enthalpy of the hot side J kg−1 –hcold

in Inlet specific enthalpy of the cold side J kg−1 –hcold

out Outlet specific enthalpy of the cold side J kg−1 –η Heat transfer efficiency % –Q Heat duty W –

4.5.4 Equations


η =Q

Fhot.(hhotin − hhot

out).100 (4.93)

η =Q

Fcold.(hcoldout − hcold

in ).100 (4.94)

Outlet pressure calculation:

photout = phot

in −∆p (4.95)

52

pcoldout = pcold

in −∆p (4.96)

Vapour enthalpy calls are used to determine the: hhotin ,hcold

in ,hhotout and hcold

out .



model are:

DOF = Nvar −Neq = (2C + 17)− 8 = 2C + 9 (4.97)

The Gas Gas Heater specification will include the following obligatory specifications:

1. Inlet streams:

• Inlet hot stream - Temperature, pressure, composition and flowrate.

• Inlet cold stream - Temperature, pressure, composition and flowrate.

2. Heat transfer efficiency

3. Pressure drop across both sides.


1. Hot stream outlet temperature or heat duty.

4.6 Control Valve

This model describes a valve, determining the flow as a function of the pressure difference and the

valve stem position. The model is characterized in terms of the valve flow coefficient (Cv, gpm/psi0.5),

the inherent flow characteristic (linear, equal-percentage, quick-opening), the rangeability factor and

the leakage fraction. The flow-characteristic options for the valve can be linear, quick-opening or

equal-percentage and are illustrated in Fig. 4.7.

Figure 4.7: Valve stem position for different flow characteristics.[44]

53

The flow coefficient (Cv) describes the flow versus pressure relationship through a valve. By

definition, Cv is the number of gallons per minute of 60oF water which will pass through a valve with

fixed pressure drop of 1 psi.

Figure 4.8: gCCS control valve model con-figuration.

The rangeability factor of a valve (used only in the

equal-percentage calculation) is the ratio of the valve flow

coefficient at maximum valve stem position to the valve

flow coefficient fraction when the valve stem position is at

its minimum. In real engineering sense, this rangeability

factor should always be greater than 1.

The dynamics of the valve are modelled via a time de-

lay equation on the stem-position of the valve. This model can have both liquid or gas inlet streams

and no phase change occurs in the system. It is assumed isenthalpic expansion and irreversible flow.

Since this is a control valve, the stem position setting is an input from the controller connected in the

control port. The representation of the control valve model can be found in the figure 4.8.

4.6.1 Inlets

• One UtilityFluid inlet port representing the inlet water or vapour stream.

• One ControlSignal inlet port representing the stem position setting.

4.6.2 Outlets

• One UtilityFluid outlet port representing the inlet water or vapour stream.


Table 4.6: Nomenclature of the variables used in the Control Valve model.


F Mass flowrate kg s−1 –Fmax Maximum mass flowrate across the valve kg s−1 –w Mass fraction in the valve - CTin Inlet temperature K –Tout Outlet temperature K –pin Inlet pressure Pa –pout Outlet pressure Pa –hin Inlet specific enthalpy J kg−1 –hout Outlet specific enthalpy J kg−1 –∆p Pressure drop across the valve Pa –Cv Valve flow coefficient kg Pa s−1 –Cvf Fraction of valve flow coefficient – –Vsp Valve stem position – –V actsp Actual valve stem position – –Lf Leakage fraction – –τ Time constant s –γ Valve flow exponent – –Rf Rangeability factor – –

54

4.6.4 Equations

Due to the isenthalpy assumption in the valve the inlet and outlet enthapies are equal:

hout = hin (4.98)

hin = PhysProp.Enthalpy(Tin, pin, 1) (4.99)

Note that in the flow is implicit that the inlet flow is equal to the outlet since only one flow variable

was defined, the same condition can be applied for the composition.

The outlet temperature is determined by a p-h flash call:

Tout = PhysProp.PHFlash(pout, hout, 1) (4.100)

Valve dynamics can be described by the following equation:

τdV actsp

dt= Vsp − V actsp (4.101)

Inherent flow characteristics can be one of the following options:

CASE:

Linear Cvf =V actsp + Lf

1 + Lf(4.102)

EqualPercentage Cvf =R

(V actsp −1)

f + Lf

1 + Lf(4.103)

QuickOpening Cvf =sin(

πV actsp

2 ) + Lf

1 + Lf(4.104)

The flow across the valve will be a function of the maximum allowable flow for the valve, depending

on the stem position opening and the inherent flow characteristics:

F = Cvf .Fmax (4.105)

F = Cv.Cvf .|∆p|1γ (4.106)

The pressure drop in the system is defined as:

∆p = pin − pout (4.107)


Analysing the number of variables and the number of equations the degree of freedom of the

model is

DOF = Nvar −Neq = (C + 17)− 8 = C + 9 (4.108)

The valve specification includes the following obligatory specifications:

1. Inlet streams : Temperature, pressure and composition.

55

2. Inlet control port : Stem position.

3. Flow coefficient

4. Maximum allowable flow across the valve


1. In advanced mode (in standard mode these options are assigned with default values):

• Time constant

• Leakage fraction

• Flow exponent

• Rangeability factor (only necessary in equal percentage inherent characteristics)

Initial Conditions

The user must provide initial conditions for each of the state variables. The following options are

supported from the model specification dialog:

1. Steady statedV actsp

dt= 0 (4.109)

2. Dynamic

Specify actual valve stem position

56

5Supercritical Pulverized Coal Power

Plant Modelling

Contents5.1 Design Mode . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 585.2 Operational Mode . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 635.3 Control Mode . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 645.4 Sensitivity analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74

57

The topic in this chapter is the development of a composite model representing a supercritical

pulverized coal power plant (PCPP) with the models already explained in the chapter 4 and the models

available on the gCCS library.

The idea behind the modelling of the PCPP is to be able to verify the accuracy of the models taken

in account all the assumptions at the same time, to simulate with a high degree of accuracy part load

operations with turbine following control implemented and for a future work to connect the power plant

with the capture plant, compression, liquefaction and storage. This will allow the partners and clients

to study sensibility issues and relationships in the entire carbon capture cluster such as the effects of

CCS on power plant operations.

In this chapter is presented a comparison between the results obtained by the gCCS tool-kit and

the results presented in the paper ”Designing a supercritical steam cycle to integrate the energy

requirements of CO2 amine scrubbing” from Luis M. Romeo, Sergio Espatolero and Irene Bolea, the

simulations in it were carried out using Aspen Plus software (Aspen 2003). [2]

5.1 Design Mode

The design mode is one of the 3 steps to simulate part load operations, in this step the results

presented in Romeo et al. [2]are matched by the gCCS fixing the main operating conditions (feedwater

flowrate, temperatures and pressures of the streams) to obtain the equipments design parameters

(size, area, efficiency, etc).The flowsheet configuration is the same as the paper and is presented in

the figure 5.1.

Figure 5.1: Supercritical steam cycle flow diagram. Streams conditions can be found in the appendix B.[2]

As it can be seen the system has the expected steam cycle having a regenerative reheat cycle

with 8 feedwater heaters, four low pressure FWH and four high pressure feedwater heaters. A deaer-

58

ator unit, four pumps, one boiler, high, intermediate and low pressure turbines and a turbine pump

(”turpump”) are also found in this power plant.

Some notes should be made for this system:

• Turmpump relationship with the pump 4

• FWH 8 with outlet drain in vapour phase

• No governor valve represented

• No flue gas side represented or information provided

The turpump and the pump 4 (P4) present a relationship suggesting that the turbine provides the

shaft power required by the pump. Another note is that the last feedwater heater (FWH 8) is not a

real FWH in a sense that the drain from this unit is in vapour phase. The feedwater heaters outlet

drain should only be saturate or sub cooled water however the gCCS FWH model does not have that

assumption, therefore it’s possible to have outlet drain in vapour phase without any problem.

From the figure 5.1 no governor valve is represented which in the gCCS is included since it is

crucial for control purpose in part load operations.

Another thing is that the paper does not present any data on the flue gas side, except the flue gas

flowrate and composition.

The gCCS flowsheet can be seen in the figure 5.2. A simple explanation of the gCCS model library

used in this work can be found in the appendix A.

Figure 5.2: gCCS diagram of a Supercritical Pulverized Coal Power Plant. Legend: A - Source coal; B - Sourceair; c - Boiler; D - Governor Valve; E - Turbine; F- Generator; G - Condenser; H - Drum; I - Pump; J - Feedwaterheater; K - Deaerator; L - Electrostatic Precipitator; M - Blower; N- Gas/Gas Heater; O - Flue gas desulphurizationunit; P - Stack; Q - Recycle breaker

The development of the flowsheet was done step by step adding one model at a time, one issue

that soon needed to be solved was the incapability for the gPROMS to solve the recirculation of

information that naturally exists in the steam cycle. The solution found was the introduction of the

59

recycle breaker model which basically simulates a source and a sink and at the end of each simulation

replaces automatically the source values by the solution found until the system converges.

The degrees of freedom of the power plant was analysed and the necessary assignments were

made, the most important are summarized in the table 5.1. All the models are assigned with the

stream conditions to match the results and obtain the operational parameters for the next step. The

stream conditions and main operating conditions from the reference [2] are presented in the appendix

B.

Table 5.1: Main assignments in the flowsheet.

Model Specification

Boiler Superheat (SH) temperature and pressureReheat (RH) temperature and pressure drop

Turbine Inlet pressureOutlet temperature or vapour fraction

GovernorValve Stem position

BoilerSteamCondenser Operating pressureMinimum temperature difference

FeedWaterHeater Outlet temperatures

Deaerator Operating pressure

Drum Residence timeVolume occupation

PumpUtility Discharge pressure

ElectrostaticPrecipitator Efficiency

Blower Discharge pressure

GGH Outlet hot temperature

FGD Outlet limit concentration

Coal Coal ultimate analysis

Air Air composition and humidity

One additional assignment, specified in the process was the outlet pressure of the last turbine set

equal to the pressure in the condenser. This assignment is necessary to meet the degrees of freedom

of the power plant and will influence the flux of information of the cycle. The last turbine pressure is

known so all the pressures are known backwards therefore the outlet RH pressure is already known

so the RH pressure in the boiler needs to be a pressure drop specification.

Another important thing to understand is that the feedwater flowrate is specified on a special

recycle breaker that only closes the temperature and pressure because obviously if no flowrate is lost

during the cycle what is specified is equal to what returns. However, if the flowrate of water was not

specified the expected power should be specified in the generator model.

The introduction of the governor valve requires a change of the specifications because it introduces

a pressure drop, reducing the pressure and the temperature at the high pressure turbine. To avoid

this deviation a study was done to discover the right SH conditions in the boiler to obtain the expected

conditions after the governor valve (the outlet SH conditions from Romeo et al. [2]) .

60

The relation already stated between the turpump and the pump 4 is represented by a recycle

break that sets the power produced in the turbine equal to the power required by the pump.

It’s important to notice that the last FWH (FWH 8) is not specifying two temperatures because its

flow is already known, was determined by the FWH 5.

Some values were adjusted to match the results such as the vapour fraction in the low pressure

turbine 5 and in the turpump because having a fraction of liquid increases the turbine isentropic

efficiency therefore the power production. Although the Romeo et al. [2]] doesn’t mention the vapour

fraction in the last turbines the outlet temperatures are at saturation conditions which suggestes that

steam moisture can be found in those turbines.

The values of humidity in the air, oxygen mass fraction in the outlet flue gas, fraction of carbon in

ash and fraction of ash in the flue gas were adjust to get the best results possible in comparison with

Romeo et al. [2].

5.1.1 Results and Discussion

5.1.1.A Stream conditions

The design mode is based on the specification of the pressures and temperatures. The flowrates

of steam drawn from the turbines could be used to verify the model. The only exceptions are the

drawn off steam flowrates from the turbines but nothing significant because the biggest error has

the value of 6%. This is due to the steam tables used that have minor differences and because the

FWH 5 determines the flowrate of the drawn off 6, but if this value is already a little deviated then the

temperature of 29 will be deviated as well (3% deviation), please see figure 5.2 and 5.3 for a better

understanding of the system.

Note that if the temperature 29 is wrong so the error in the flow will increase not only due to steam

table differences. A representation of the high pressures feedwater heaters can be found in figure 5.3.

The stream conditions and the deviation can be found in the appendix B.

Figure 5.3: Flow diagram of the HP pressure feedwater heaters side.

5.1.1.B Key Performance Indicators

Key performance indicators obtained were compared with the ones from the reference [2] and are

presented in the table 5.2. The results show that the power obtained is 1.71% lower than the expected

61

and the coal and flue gas flowrate were matched adjusting the fraction of unburned carbon. Both coal

and flue gas flowrate are calculated in the boiler model.

Table 5.2: Key performance indicators (KPI) deviation.

KPI % Flue gas compostion %

Gross power -1.7 CO2 0.6Net Power -0.7 N2 -0.1Specific CO2 emissions 2.4 H2O 0.0Gross efficiency -1.8 O2 0.0Coal flowrate 0.1 SO2 0.0Flue gas flowrate 0.0

Although there is a lack of information in the Romeo et al. [2] to made a better comparison the

results are in an acceptable range. The biggest error is the specific CO2 emissions with 2.4% because

the power is lower than the expected and the carbon dioxide in higher.

The excess oxygen and the air humidity were adjusted to match the oxygen composition and the

hydrogen composition. The air has an humidity of 60%.

Analyzing the gross efficiency may be concluded that since the same amount of coal is used,

less power is generated which is probably due to limitations on the steam cycle. The turbines models

used from Aspen used by the reference [2] probably have different assumptions which make the gCCS

turbines generate less power.

The gross efficiency is defined as the power generated divided by the ideal power produced which

is equal to the lower heating value of the coal times the coal flowrate.

5.1.1.C Equipment Parameters

In design mode, the equipment parameters and sizes are calculated, as a simplification is just like

sizing the equipments fixing the expected performance. To clarify, in design the temperatures and

pressures of every stream are specified in order to obtain the equipment parameters and sizes which

will be used in operational mode to allow part load operation. In part load operation when the areas

and sizing are assigned the temperatures and pressures change according to the load.

For the heat transfer equipments such as feedwater heaters and condenser the overall heat trans-

fer coefficient is constant and specified with the value of 5000 W m−2 K−1 which is within the typical

range of 1100 - 8500 W m−2 K−1 for the FWH and 1100 - 5600 W m−2 K−1 for the condensers. [28]

In the following tables are presented the values obtained for the feedwater heaters, condenser and

turbines. The results obtained for the feedwater heaters terminal temperature difference is close to

the typical range that should be around 3 K for low pressure FWH and around 15 K for high pressure.

[35]

Table 5.3: Equipment parameters for the feedwater heaters and the condenser.

Parameters Feedwater Heaters Condenser1 2 3 4 5 6 7 8

TTD (K) 2.1 0.9 3.3 11.1 13.1 20.9 13.5 – –Area (m2) 509.6 673.6 180.3 86.8 590.4 922.6 259.4 15.8 7343.3

62

Table 5.4: Equipment parameters for the turbines.

Parameters HP 1 HP 2 IP 1 IP 2 LP 1 LP 2 LP 3 LP 4 LP 5 Turpump

η (%) 89.3 88.5 88.9 89.3 87.9 91.6 62.1 26.5 98.5 88.1Stodola’sconstant 20235.2 1008.6 779.4 270.7 65.9 16.1 2.8 0.3 0.06 13912.3

In the table 5.4 are presented the equipment parameters for the turbines. The efficiency is more or

less constant around 90% in all the turbines with exception for low pressure turbines (3 and 4) where

the efficiency starts to decrease and in the LP5 where is really high due to two phase appearance.

The vapour fraction in the LP5 turbine is 94% and 91% in the turpump this values are within the

acceptable values not lower than 85-90% because lower vapour fractions can damage the turbine.

[45]

Stodola’s constant is a parameter used to relate through an empirical equation the pressure ratios

and the flowrate of vapour being expanded in the turbine.

5.2 Operational Mode

The second step is to introduce equipment parameters determined in the design mode (5.3 and

5.4). The objective of this step is to ensure that changing the specifications (can be seen 5.5) in the

same stream conditions are achieved. This will allow in a further step to go to part load operations

with no fixed temperatures or pressures in the steam cycle but only fixed equipment performance

parameters.

A large number of specification trade-offs are implemented in this step, for some models the

specification dialog already gives an indication switching from design to operational mode. Examples

are the turbines, the feedwater heaters and the condenser. However the deaerator doesn’t have

that option and the specification is changed from operational pressure specification to pressure drop

specification.

The specification trade-offs are summarized in the table 5.5.

Table 5.5: Specification trade-offs for operational mode.

Model Design Mode Operational mode

Condenser Pressure PressureCW oulet temperature Area

FWH Drain tempetarature TTDFeedwater oulet temperature Area

Deaerator Operational pressure Pressure drop

Drum Residence time Design volumeVolume of liquid Level

Turbine Inlet pressure Stodola’s constantOutlet temperature or vapour fraction Efficiency

These are the specification changes for the operational mode, all the operational data was deter-

mined by the models in the design step. At this stage the results for the stream conditions and key

63

performance indicators are once more analyzed however as expected just by switching the specifica-

tion the results obtained are the same.

Therefore the results are not presented in this section and are presented the Appendix B.

5.3 Control Mode

In this section some control loops will be introduced in the system to try to reproduce the sys-

tem response of a real power plant. Although, the only model with full dynamics is the drum, the

implementation of the controls loop will confirm and help to understand the system response to load

changes.

Obviously with load changes the pressures, the temperatures and the feedwater flowrate changes.

Therefore the specification determined in the first step and tested in the operational mode are now

used and kept constant over the course of load changes.

To successfully model the control system, the controlled variable that was assigned in the opera-

tional mode is now given in the controller model as a set point. The controller will send the signal to

the valves where the stem position is changed according to the desired response.

The control loops implemented were: the pressure control in the condenser, the level control in

the deaerator drum and the turbine following control loop. In the turbine following the power and

the superheat pressure are controlled using the coal flowrate and changing the stem position in the

governor valve.

In this control mode, the power is specified in the power controller and not the feedwater flowrate

in the recycle as it was specified in design mode. The controllers used were not optimized because

that was not the objective of this thesis.

A daily cycle will be studied in this section.

5.3.1 Control loops

5.3.1.A Condenser pressure

This control loop which is presented in the figure 5.4, is usually implemented in power plants where

the pressure is controlled with the cooling water flowrate. If the cooling water flowrate increases the

pressure will decrease because more heat will be transfer and more steam will condense.

Figure 5.4: Condenser pressure control loop.

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Naturally there is a limit to this heat exchange, being the amount of flowrate possible to pump and

the outlet temperature of the cooling water which can’t increase more than the saturation temperature

of the steam at that pressure.

5.3.1.B Deaerator drum level

The drum model wasn’t initially a model required for the gCCS library. However, it was necessary

to add these drums (after the condenser and deaerator) to serve as buffers in load changes. The

explanation is that the models are steady state, so when a controller is introduced for example in the

condenser, it is just like specifying the flowrate of cooling water and then the pressure is calculate.

If the load decreases so will the steam flowrate to the condenser, therefore the pressure will

drop instantaneously and since the condenser model sets the temperature to the saturation this will

decrease with the pressure. The problem with this happening is that will produce a perturbation in the

feedwater heaters and eventually will crash due to temperature crossovers.

With the introduction of this dynamic drum models, even though the pressure still decreases in the

condenser that change will be diluted in the tank. One future work could be introducing dynamics in

the condenser and the deaerator models to better capture the system responses.

In spite of these problems in a real power plant the drums exist and are controlled as it can be

seen in the figure 5.5. The condenser tank is typically controlled by the makeup water, losses due

to leakage, steam venting or non recoverable steam usage need to be compensated. [24]. Because

there isn’t any water loss in the system this control loop is not represented in the flowsheet.

Figure 5.5: Deaerator drum level control loop. Legend: A - Drum; B - Deaerator; C - Feedwater heater; D -pump; E - Recycle breaker; F - Governor valve; G - Controller

The deaerator’s drum serves as a surge tank for boiler feedwater and in order to control the

level the inlet feedwater into the deaerator is manipulated. In terms of modelling that is exactly what

is represented and the outlet feedwater from the tank is specified from the governor valve steam

requirement.

In the deaerator’s tank the residence time is not specified as it was in operational mode, but is

specified (as set point in the controller) the level which is the controlled variable.

65

5.3.1.C Turbine following control loop

The last, but nevertheless the most important control loop is the turbine following as described in

the section 2.4.1, it is a load demand adjusting system. Basically, when a load increase is required the

first step would be to change the firing rate (flowrate of coal) which will induce an increase of pressure

in the boiler. The pressure controller will then send a signal to the governor valve to decrease the

pressure by opening the valve.

The figure 5.6 presents the turbine following control as it is implemented in the gPROMS.

Figure 5.6: Turbine following control loop. Legend: A - Source coal; B - Source air; C - Boiler; D - controller; E -Governor valve; F - Turbine; G - Generator; H - Recycle breaker.

This type of control loop is more used when a frequency power change is required. For a typical

grid energy production a boiler following mode is more suitable since uses stored energy in the boiler

to provide immediate load response.

5.3.1.D Others controls

The power plant have much more controls loop like the ratio controller with the air and the fuel and

the level controllers in the feedwater heaters that were not represented. The feedwater heaters and

the deaerator control were not represented due to the lack of dynamics in the system. An important

thing to note is that the actual flow drawn off from the turbine is not controlled but is pressure driven.

5.3.2 Step change in power plant load

The reference [28] presents a comparison between the load control loops (figure 5.7). This figure

helps to understand the system dynamics with the different types of control. The turbine control has

the behaviour already explained in the previous section and the boiler following control response has

a decrease in the throttle pressure when an increase of power demand is required. This is due to

the fact that when a power increase is required the governor valve is immediately adjusted which will

make the pressure to decrease, only after this the coal will be adjusted to make the pressure go back

to the set point.

The coordinated or integrated control instate the best of both controls systems being the fastest

and having less pressure deviation than the boiler following control. A positive step change was

simulate and the results are presented in the following charts. Since no relative deviation was defined

in the reference, a step of 4% was defined for the simulation from 90% to 94% of load change.

66

Figure 5.7: Load change and throttle pressure deviation for the different types of load control.

The step change was done within the typical rate change allowed in a power plant. Physical

restrictions in supercritical power plants usually set the limit rate of load change to 8%per minute. [46]

In the simulation this will help to obtain less sharp and more smooth results, as it can be seen

in the figure (5.7) the power response seems to be second order. However in the simulation the

results suggests only first order response and that response is only due to the controller that adds

one order to the system. To get a better response is only possible by adjusting the controllers or

adding dynamics to the system.

This is a limitation on this simulation in terms of control because even thought the results represent

correctly the general behavior of the system, it currently does not accurately predict the dynamics of

the system.

Analysing the figure 5.8, it can be concluded that the pressure is well controlled since it is almost

constant having no significant deviation, the biggest deviation achieves 1.2%. Although the reference

step change is unknown, the stabilizing times are close to the expected and still show that the power

controller reaches the set point without any problem. The stabilizing times are presented in the table

5.6, there was no intention to match the time frames but the relationship between them, in other words

the pressure should always stabilize faster than the power reaching the set point. The stabilizing time

is defined as the time when the variable becomes within 99.5 % of the set point objective.

In figure 5.8, can be seen the different controllers tested and their parameters can be found in

table 5.6.

Table 5.6: Controllers parameters and stabilization time for every controller.

Controller Power Controller Pressure Controller

Gain Reset Stabilization Gain Reset Stabilizationtime (s) time (min) time (s) time (min)

Reference 0.015 7.5 7.5 1 7.5 –

1 0.15 7.5 1.1 0.5 7.5 1.7

2 0.05 7.5 2.4 0.5 7.5 1.8

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Figure 5.8: Load change and throttle pressure deviation results for 4% step change in load.

The power controller has a direct action and the pressure controller an inverse action on their

corresponding manipulated variables the firing rate and governor valve stem position, respectively.

The controllers were tuned manually however the first guess for the parameters were based on the

values obtained from reference [47].

The values from the reference found are not exactly as it was supposed to be, since they are used

for coordinated control which is completely different. Nevertheless, especially the reset times can

be valuable providing a typical value since those are more likely to keep constant. The gain of the

controllers certainly should not be the same because the measured variables are different.

Therefore the reference controller is the initial guess for the manual tunning, it has the literature

parameters for the power controller and the reset time of the literature for the pressure controller. The

gain of the pressure controller starts with 1, since the gain is unidimensional.

Observing the gain of the controllers and the stabilizing time can be concluded that as bigger it is

the gain the faster the response becomes. The controller 1 with the power gain of 0.15 is the quickest

to get to the set point only taking 1.1 minutes to reach it and 1.7 minutes to stabilize the pressure which

does not represent correctly the expected behavior. The controller that shows the closer behavior to

expected is the controller 2, taking more time to reach the set point (2.4 minutes) than to stabilize the

disturbance in the pressure (1.8 minutes). The set of parameters used in the controller 2 will be used

to simulate the daily cycle in the following section.

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However, in spite all this efforts to find the controller is important to know that in the limit if the

controllers were to good (high gain and lower reset time) the response should be seen immediately,

the entire dynamics is given only by the controllers and the governor valve.

5.3.3 Daily Cycle

In a country power demand there are 3 types of energy load requirements: the base load, the

intermediate load and the peak load. The base load is the minimum level of demand on an elec-

trical supply system over 24 hours. Base load power sources are those plants which can generate

dependable power to consistently meet demand, typically nuclear and coal power plants are used.

Base load power plants produce continuous, reliable, efficient power at low cost and often are

relatively inefficient at less than full output.

Electricity demand fluctuates over the course of a day, the power demand is then met by interme-

diate and peak load power plants. Usually base load power plants produce between 30% and 40%

of the power requirements and intermediate meet 30% to 60%. The rest is fulfilled by the peak load

power plants.[48]

Peak load generators, such as natural gas, have low fixed costs, low plant load factor and high

marginal costs. Also coal can be used as intermediate and peak load power plants, but natural gas is

much more flexible and faster than coal power plants.

For purpose of this work, coal is considered base load and is analyzed the daily demand for the

Portuguese Electrical Grid (provided by REN) for the 3 of September of 2012.[49]

Figure 5.9: Daily cycle of the Portuguese National Grid from 3 of September 2012.

Results

Analyzing the figure 5.9, the schedule for the daily cycle of the power is decided. Clearly from 1

a.m to 8 a.m less power is required therefore the power plant could work at 90% load. From 8 a.m

to 5 p.m the power plant is working at full capacity, then drops to 95% until 10 p.m when it goes back

to the 90% load . the simulation is done with the previous control loop explained: condenser control,

drum level control and turbine following control.

The simulation of this production schedule is presented in the following figure 5.10.

69

Figure 5.10: Simulation results from the daily cycle schedule.

The controllers implemented were manually tuned, the condenser controller and the level control.

The parameters used for the turbine following control are the ones used in the controller 2 of the step

test in the previous section. The controllers parameters are summarized in the table 5.7.

Table 5.7: Table summarizing the controllers parameters.

Controller Gain Resettime (s)

Power 0.05 7.5Boiler pressure 0.5 7.5Condenser pressure 2 3Deaerator tank level 8 –

The level controller was define as a proportional controller since typically in industry level is con-

trolled with proportional controllers, having a high gain ensures that the level stays close to the set

point but at the same time can make the system unstable, therefore a trade-off between both must be

determined.

As previously stated, the change in set point is considered in terms of the physical limits typically

allowed in real power plants, so in order to be inside those limits the same rate of load change was

used 8% per minute. [46]

Primarily, are presented the results to the variables directly affected by the load change, the coal,

the governor valve stem position, feedwater flowrate and boiler pressure. When the coal flowrate is

increased (power demand increased, more heat required) the pressure in the boiler increases (figure

5.8), then the governor valve will open decreasing the pressure drop and letting more vapour to flow

across and going into the turbines which will decrease the pressure. This physical response can be

seen in the following figures 5.11 and 5.12.

Observing the figure 5.11, is possible to see that the pressure is always well controlled being the

biggest deviation with the value of -4.3% which represents about 13 bar decrease in 303.5 bar of set

point pressure, however it is possible to reduce this results decreasing the rate of load change which

is already in the upper limit. This deviation occurs in the change from 100% to 95% ate 5p.m, and is

interesting that a negative step causes more impact than a positive one, which is related to the fact

that the controllers were tune for positive disturbances.

70

Figure 5.11: Boiler pressure and governor valve stem position response during the daily cycle schedule.

Figure 5.12: Feedwater and coal deviation from full capacity load for the daily cycle schedule.

This is a important restriction in load change because the pressure in the boiler should not change

to much and depends on the materials and type of boiler, but is certainly of crucial importance in the

power plant safety and performance.

At 8 a.m, the biggest change in load of the day happens, changing the load from 90% to 100%

which makes the governor valve to saturate since it was designed for full capacity.

In terms of feedwater flowrate and coal requirements, the deviation tracks the evolution of load

demand. The deviation of the feedwater flow is exactly the same as the load, but for the coal a

production of 90% load only saves 9% of coal this will cause the gross efficiency of the power plant to

drop to around 1%.

The rest of the steam cycle is also affected by the load changes, for example the level controller

in deaerator tank (figure 5.13). The deviation in the level set point is irrelevant and the main reason

is that what doesn’t get in the deaerator tank is accumulated in the condenser tank. When the load

increases so does the feedwater that goes into the boiler, to adjust this increase in the outlet of the

tank, the valve after the condenser drum changes the stem position to have more flow out. The

outcome of this action is the decrease of the level in the condenser tank. Since this control loop is the

only real dynamic loop, will be presented a closest look on a step from 90% to 100%.

Analyzing the figure is possible to see a typical proportional response. The manipulated variable

is a valve and the stem position is presented in the figure 5.13. The valve goes to half open in the full

71

Figure 5.13: Responses of the manipulated and controlled variable for a change of load from 90% to 100%, forthe level control.

load since all the valves were sized for double the flow. The level also achieves the set point without

any error because the first control arrangement was for 100% load therefore when it comes back it

will get to the same point exactly.

The response in figure 5.13 is first order. The proportional action is present, for example the steady

state in 90% load is not at the step point but has an error and that error is due to the proportional

control. The proportional control only sets the inlet flow equal to the outlet but all the accumulate error

is never compensated has it is with the integral term of a PI controller.

The level change in the condenser tank is not presented, however since the tanks are the only two

dynamic models in the power plant, whatever one loses is accumulated in the other.

The condenser pressure control is a proportional and integral controller with the values of the table

5.7. The response for the daily cycle is presented in the following charts, figure 5.14.

Figure 5.14: Responses of the manipulated and controlled variable during the daily load, for the condenserpressure control.

As it can be seen, the pressure is not so well controlled during part load operations, however this

results need to be carefully analyzed since this suddenly increase in pressure is mainly due to the

lack of dynamics in the model. This exemplifies the need to add the tank model since this increase in

pressure would immediately be seen in the feedwater heaters which would cause them to fail at some

72

point along the line.

The cooling water flowrate is being manipulated for part load operations. Therefore, for a decrease

in the load, a decrease in the inlet steam pressure of the condenser will occur and in order to maintain

the pressure at its set point less cooling water flowrate will be required.

Looking for the overall performance of the system when the load changes, the entire cycle would

change as well - stream temperatures, pressures, flowrates. For example the temperature and pres-

sure of the feedwater heater 6 and the deaerator are presented in the figure 5.15.

In part load operations, less power is required therefore less steam flow is required. Since the

turbines have the same performance with less flow the pressures and temperatures will start to de-

crease and thats when the TTD of the FWH and the pressure drop of the deaerator are of extreme

importance, because they follow the decrease in temperature and pressure of the turbine system to

keep the steam cycle integration system working.

Figure 5.15: Variation of the feedwater heater and deaerator temperature and pressure during the day.

Another important thing to analyze is the vaporization of the steam in the last turbines and in all of

the turbines, making sure that none had vapour fraction below the mechanical limit of 85%.

The simulation results determined that the vapour fraction along part load operations varies but

in none of the cases drops below 90% of steam. This assures that the mechanical limits of the

equipments are not being exceeded in the simulation.

he turpump power is being determined by the amount of the power that the pump 4 requires. In

part load operations the same happens and obviously is less the power required by the pump because

less feedwater is circulating. In order for the turpump to achieve the power required, the steam drawn

off will decrease.

The key performance indicators are presented for the different loads in the table 5.8

A direct relation is visible in this table since the interaction between all the key performance indi-

cators seems to be suggesting some proportionality. Even though none of the variables decreases in

the same degree has the load they follow the same direction.

Exception to this is the specific carbon dioxide emissions because the systems is less efficient and

the amount the coal is not saved in the same degree the atmospheric emissions will be more severe

per megawatt produced.

73

Table 5.8: Power plant Key performance indicators for different loads.

KPI Reference Case Power plant load100% 95% 90%

Gross power (MW) 471.25 -5.0% -10.0 %Gross efficiency (%) 46.37 -0.6% -1.2 %Specific CO2 emissions (gCO2/kWh) 718.65 0.6% 1.2%Coal flowrate (kg/s) 38.50 -4.5% -8.9%Flue gas flowrate (kg/s) 438.67 -4.5 % -8.9%

The coal tendency is the same as the flue gas, the reason for this is simple, if for example, less 2

% of coal is burned in the boiler the flue gas flowrate will decrease exactly 2%.

If the amount of flue gas decreased so the amount of carbon dioxide sent to the stack. However,

if the power decreased more the specific carbon dioxide emissions will increase per megawatt.

The gross efficiency decrease as well with the load which shows that the power plant is losing

money comparing to 100% load. The relative difference between the power and the coal deviation

gives the gross efficiency relative deviation. Which is due to the fact that the steam cycle in part load

operation does not maintain the same performance in the heat integration.

This results corroborate the previous stated that base load power plants typically lose efficiency in

part load operations.

5.4 Sensitivity analysis

To study the effects of some assumed performance parameters in the equipments, a sensitivity

analysis was conducted for the boiler efficiency. This will provide ideas on how important is the boiler

efficiency in terms of power generation. An important factor that can be analyzed is the effect of the

reheat steam temperature in the power plant performance.

5.4.1 Boiler efficiency

In this section was studied the effect of the boiler efficiency in the system. Efficiencies of 2% and

4% above and below of the assumed valued were simulated and the results for the key performance

indicators are presented in the table 5.9:

Table 5.9: Boiler efficiency sensitivity study, relative deviation to the reference case is presented.

KPIBoiler efficiency cases

Reference Case Study cases94 % 90 % 92 % 96 % 98 %

Boiler efficiency (%) – -4.3 % -2.1 % 2.1 % 4.3 %

Gross power (MW) 471.25 0.0 % 0.0 % 0.0 % 0.0 %Gross efficiency (%) 46.37 -4.3 % -2.1 % 2.1 % 4.3 %Specific CO2 emissions (gCO2/kWh) 718.65 4.4 % 2.2 % -2.1 % -4.1 %Coal flowrate (kg/s) 38.50 4.4 % 2.2 % -2.1 % -4.1 %Flue gas flowrate (kg/s) 438.67 4.4 % 2.2 % -2.1 % -4.1 %

Analyzing the results, is easy to conclude that the main effect is not on the power generation

74

side since that all the temperatures and pressures in the steam cycle are kept constant. However

changing the efficiency will determine how much coal is required, since that less heat is lost due to

inefficiencies.

The amount of coal used will determine the increase or decrease of the power plant efficiency.

As it can be seen in table 5.9, the increase of the boiler efficiency is directly proportional to all key

performance indicators. For example an increase of 2% in the boiler efficiency will lead to a decrease

of 2% in the coal as expected, due to a enhancement in the heat transfer of the boiler, therefore less

flue gas will be sent to the stack (2%).

The specific carbon dioxide emissions will decrease 2% because the coal burned is reduced so

less carbon dioxide will be emitted for the same power output. The opposite happens to the overall

gross efficiency of the power plant which increases 2% due to a decrease of the coal required, in

order to achieve the same power.

The conclusions for this sensitivity are the expected which is higher the efficiency of the boiler

the better, because improves the consumption of fuel and therefore increases the overall efficiency

of the power plant and decreases the amount of carbon dioxide sent to atmosphere, reduce the

inefficiencies in the heat transfer of the boiler can significantly improve the power plant performance.

The enhancement is proportional to the improvement of the boiler efficiency.

5.4.2 Reheat temperature

The reheat temperature is a condition of the power plant design, typically for supercritical power

plants the temperature can be above 600oC which is the case for this power plant. The effect of the

reheat temperature in the overall performance of the power plant will be the objective in this section.

It’s expected an improvement of the performance of the power plant with the reheat temperature .

This is because higher temperatures allow a better use of the steam’s energy by the turbines.

Table 5.10: Reheat temperature sensibility study, relative deviation to the reference case is presented.

KPIReheat temperature cases

Reference Case Study cases610.0oC 618.8oC 654.2oC 698.3oC

Reheat temperature (%) – 1.4 % 7.2 % 14.5 %

Gross power (MW) 471.25 0.7 % 3.4 % 7.0 %Gross efficiency (%) 46.37 0.1 % 0.7 % 1.4 %Specific CO2 emissions (gCO2/kWh) 718.65 -0.1 % -0.7 % -1.4 %Coal flowrate (kg/s) 38.50 0.5 % 2.7 % 5.5 %Flue gas flowrate (kg/s) 438.67 0.5 % 2.7 % 5.5 %

Table 5.10, presents the results for three different temperatures with an increase of 1.4%, 7.2%

and 14.5%. As it is possible to observe the gross power in this case is affected by this change in

the system. The key performance indicator that improved the most with reheat temperature, was the

power production, for the 1.4% increase in the reheat (RH) vapour temperature the power increases

0.7%. In terms of numbers it represents an increase of 3 MW for an increase around 9oC in the

temperature, which clearly confirms the importance of the reheat temperature in the power generation.

75

Another thing to note is that the coal does not increase in the same proportion as the power,

which is a good thing meaning that the efficiency of the power plant will increase with the temperature

improvement. For example, in the case two the temperature increases 7.2% and in order to achieve

the required temperature, the coal increases 2.7%, therefore the flue gas will also increase in the

same proportion of the coal flowrate. For this case the gross power increases more than the coal

(3.4%), which will lead to higher power plant efficiency of 0.7%.

Even thought the coal increases the performance of the power plant is improved producing more

power without having to increase the coal in the same proportion, also the environmental performance

improves decreasing 0.1% the amount of carbon dioxide sent to the atmosphere per Megawatt pro-

duced.

The steam conditions in the steam cycle can be found in the appendix B. However with bigger

values of reheat temperature, bigger are the deviation of the temperatures, pressures and flowrates in

comparison to the reference case. Even thought the efficiency of the power plant increases because

the steam cycle heat integration is improved with this increase. The feedwater entering the boiler has

an increase in the temperature in the same range of value as the gross efficiency. So for example,

for an increase of the RH vapour temperature of 7.2% the feedwater’s temperature increases in 0.7%

which will allow the system to save coal leading to an increase of the gross efficiency in 0.7%.

The conclusion is that the power generated is highly improved by the increase of the reheat tem-

perature however a limitation on equipment side makes impossible to increase that temperature has

high as desired because of materials restrictions on how high the temperature can be.

New materials are nowadays being discover and adapt to improve this restrictions. Modern chrome

and nickel-based super alloys in the steam generator, steam turbine, and piping systems can with-

stand prolonged exposure to this high temperature steam.[27] Future materials will push further the

efficiencies and incomings of supercritical power plant generations leading to temperatures around

7000C helping the plants to achieve above 50% efficiencies.[50]

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6Conclusions and Future Work

Contents6.1 Future Work . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79

77

The subject of this dissertation was the development of a supercritical pulverized coal power plant

model and some of the relevant sub-models. The objective was the simulation of part load operation

along with some control strategies. The control strategy implemented was turbine following control

and with it a daily cycle of a power plant was simulated.

The main original contributions of this work were the development from scratch in the gPROMS

software of the sub models and the composite power plant model. Also the understanding of the

system which allows the simulation of part load operations fixing the equipments design parameters.

Nothing like this was ever implemented in gPROMS, therefore the first step was to prove the

accuracy of the models and the design mode which prove that the modelling accuracy of the models

used are at the same level as the ones used by Romeo et al.[2] with the ASPEN software. The

power deviation is the only meaningful difference having less 1.7% of gross power because of the

assumptions used for the gCCS turbine models. However due to this error the other key performance

indicators suffer some deviations exception done to the coal required and the flue gas flowrate which

were matched.

A supercritical pulverized coal power plant was simulated producing 471.25 MW of gross power

with an efficiency of 46.25% and a specific carbon dioxide emission of 718.65 g/kWh of gross power.

The coal consumption is 38.50 kg/s producing 438.65 kg/s of flue gas. The power plant has 350 kg/s

of feedwater circulating the system.

The understanding of the system allowed the introduction of a second simulation mode called

operational mode. The operational mode made possible the change of specification based on the

results of the design mode without losing the accuracy already achieved. Some of the important

variables in the system were the terminal temperature difference and the deaerator pressure drop

that allow part load operations and establish a relation between the temperatures and the pressures

of the system.

The control loops implemented showed the expected response which was proved by the step

change done in the load. However due to the lack of dynamics in the models the introduction of

dynamic drum models was crucial to part load operations.

Since that the tanks were the only two dynamic models whatever losses in one was accumulated

in the other. The tanks were used as buffers which was of extreme importance because when a

change in the pressure of the condenser occurred the change would be felt in the FWH line which

would cause them to fail since the temperature would be far away from the expected. With the tank,

the pressure in the condenser can change but the tank acts as a buffer until the controller puts the

pressure back to its set point.

The daily cycle simulation presents a clear relation between the key performance indicators and

the load. The decrease in power production of 5% does not mean that the coal consumed decreases

5%, actually the coal consumption decreases around 4.5% which makes the efficiency of the power

plant worse in 0.6%. This is due to the fact that the steam cycle in part load operation does not

maintain the heat recovery efficiency.

The flue gas flowrate is directly proportional to the consumed coal and so is the carbon dioxide

78

emitted however the specific carbon dioxide emissions will increase 0.6% due to the greater decrease

of power than the flue gas emission. The daily cycle helped to understand the dynamic in part load

operation. To produce less 5% of power, less feedwater is required in the same proportion (5%). With

less feedwater the outlet temperatures and pressure in the turbine will be reduce and all the steam

cycle will be rearranged. The amount of reduction is different from the steam cycle position but is

accentuated with the load decrease.

The boiler efficiency was considered constant along part load operations however a sensitivity

analysis was perform and the conclusions indicate that the improvement of 2% of the boiler efficiency

impacts positively the power plant gross efficiency in 2%. This is explained with the fact that the heat

transfer in the boiler is improved therefore the coal consumption reduces 2%.

The sensitivity analysis was also conducted on a reheat temperature which showed that an in-

crease in the reheat temperature of 7.2% would cause an increase of 3.4% in the produced power.

With the reheat temperature increase the steam cycle integration is improved and the feedwater tem-

perature entering the boiler is increased in 0.7% which enables a save in the coal consumption.

Therefore the gross efficiency of the power plant is increase in 0.7%.

The sensitivity analysis showed two ways of improving the power plant efficiency the first one the

boiler efficiency can be improved with new approaches and materials to improve the heat transfer

efficiency. The reheat temperature clearly affects the steam cycle completely and an optimization of

the steam cycle with those conditions could increase up to 50% or more the efficiency of the power

plant. However nowadays those temperatures are not possible to achieve but in a close future new

materials will allow higher temperatures and pressures.

The objective of this thesis was fully accomplished with the supercritical pulverized coal power

plant being able to successfully simulate the part load operation. However some work can still be

done to improve the accuracy of the simulations. In the following section are described some of the

future ideas to complement the work done so far.

6.1 Future Work

Power plant modelling is a widely studied subject however, there is a shortage of full chain CCS

process modelling capability. Further work includes integrating the capture plant, and other parts of

the chain with the power plant. In further steps the transmission and injection could also allow a study

and optimization of the entire carbon capture chain.

Another approach should be the improvement of some steam cycle models such as: condenser,

deaerator and feedwater heater. The integration of dynamics is crucial to more accurate part load

simulation, this would change the system degree of freedom making the flow to be pressure driven.

A dynamic feedwater heater and deaerator could allow a study in the level controllers.

Also the dynamics in the boiler and the coal milling could be explored to open a variety of control

studies, having meaningful responses for the implemented controls such as turbine following. The op-

timization of power plant with cost estimation incorporated in the models could determine the number

79

of feedwater heaters and drawn offs required.

Some of these ideas are already in place and this is just the first gCCS library with the first steady

state model that will be improved later.

80

Bibliography

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AgCCS Model Library

A-1

A.1 Main power plant models

The main power plant equipments are: the boiler, the turbine, the deaerator and the governor

valve.

A.1.1 Boiler model

The boiler model configuration is represented in figure A.1, with the ports connections. The boiler

has an inlet and outlet port for the reheat steam, inlet port for coal and air, outlet port for the ash

deposits from the coal and for the outlet flue gas, one inlet port for the feed water, one outlet for the

outlet superheat steam and one control port for superheat pressure measurement.

Figure A.1: gCCS boiler model configuration.

Specification options

The following options will be available in the specification dialog.

1. Boiler properties tab

• Fraction of ash in flue gas

• Fraction of carbon in ash

• Boiler flue gas outlet pressure

• Boiler fractional efficiency

• Temperature of bottom ash

• Excess oxygen or outlet mass fraction of oxygen in the flue gas or molar fraction in dry flue

gas

2. Steam properties tab

• Reheat outlet temperature

• Superheat outlet temperature

• Reheat outlet pressure or pressure drop in the RH side

A-2

• Superheat outlet pressure or pressure drop in the SH side

This options are for the boiler operating conditions however this is a composite model and the

air heater is include in this model it is possible to choose if the air heater exist and in positive

case what are the specification for the unit. Also the tramp air (the air that enter the boiler) can

be specified.

3. Air heater properties tab

• Heat exchanger effectiveness or the air outlet temperature or flue gas inlet temperature

• Flue gas pressure drop

• Air pressure drop

• Leakage fraction

• Heat transfer efficiency

4. Tramp air tab

• Inlet fraction

• Temperature outlet temperature

• Pressure

A.1.2 Turbine model

The turbine model configuration is represented in figure A.2, with the ports connections. The

turbine has an inlet and outlet port for the steam and an inlet port for the power generated by the

previous turbine and an outlet power port that sends the power generated in the turbine plus the

power given by the inlet power port.

Figure A.2: gCCS turbine model configuration.



1. Design mode

• Inlet pressure

• Outlet pressure or outlet vapour fraction

2. Operational mode

A-3

• Stodola’s constant

• Isentropic efficiency

A.1.3 Deaerator model

The deaerator model configuration is represented in figure A.3, with the ports connections. The

deaerator has an array of inlets and one outlet port for the feed water, one inlet steam port, one outlet

bleed steam port and one control port for pressure measurement.

Figure A.3: gCCS deaerator model configuration.



• Bled fraction

• Operational pressure or pressure drop

A.1.4 Governor valve model

The governor valve model configuration is represented in figure A.4, with the ports connections.

The governor valve has one inlet and outlet port for the superheat and one inlet control port where

the stem position is set. This model is very similar to the control valve the only exception is the fact

that the maximum allowable flow is not applicable here.

Figure A.4: gCCS governor model configuration.



1. Specification mode

A-4

• In advanced mode (in standard mode these options are assigned with default values):

Time constant

Leakage fraction

Flow exponent

Rangeability factor (only necessary in equal percentage inherent characteristics)

2. Inherent characteristic

• Linear

• Equal Percentage

• Quick opening

3. Pressure drop

• Pressure drop known (specify stem position)

• Specify flow coefficient

4. Initial condition specification

• Steady state

• Dynamics:

Specify actual valve stem position

A.2 Auxiliary power plant models

The auxiliary models used in the flowsheet were: the drum, the pump, the blower, the generator,

the recycle breaker, the source coal, source air, source utility, sink utility, sink waste, the stack and the

junction.

A.2.1 Drum

The drum model configuration is represented in figure A.5, with the ports connections. The drum

has one inlet and outlet port for the water and one control port for measurement of liquid height.

Figure A.5: gCCS drum model configuration.

A-5



1. Design mode

• Residence time

• Volume liquid occupation

2. Operational mode

• Total volume

• Residence time

• Initial conditions:

Liquid height

Drum pressure

A.2.2 Pump

The drum model configuration is represented in figure A.6, with the ports connections. The drum

has one inlet and outlet port for the water and one control port for measurement of liquid height.

Figure A.6: gCCS pump model configuration.



1. Design mode

• Residence time

• Volume liquid occupation

2. Operational mode

• Total volume

• Residence time

• Initial conditions:

Liquid height

Drum pressure

A-6

A.2.3 Blower

The drum model configuration is represented in figure A.7, with the ports connections. The blower

has one inlet and outlet port for the flue gas and one power connection port.

Figure A.7: gCCS blower model configuratio.



• Isentropic efficiency

• Outlet pressure or pressure ratio or pressure difference

A.2.4 Generator

The drum model configuration is represented in figure A.8, with the ports connections. The gen-

erator has one control port for power measurement and one array of power port, with the objective of

getting all the power generated.

Figure A.8: gCCS generator model configuration.



1. Total power demand

• Electrical power

• Efficiency

2. Specify efficiency

• Efficiency

A.2.5 Recycle breaker

The recycle breaker model configuration is represented in figure A.9, with the ports connections.

The recycle has one inlet and outlet port and can have any connections type (utilityfluid, power,

control, etc).

A-7

Figure A.9: gCCS recycle model configuration.


The model can be in closed mode where the model doesn’t do anything. In open mode works like

a sink and a source at the same time. And have a mode to help initialize the flowsheets and solve

the recirculation problems, for reasons of intellectual property no other specific option will be further

explained.

A.2.6 Source, sink and junction

An example of a source and a sink are presented in the figureA.10, this are the simple models

in the gCCS library the only function is to specify the inlet conditions (source) or receive the results

(sinks). These models can be for water, flue gas, and coal or air. The coal or air are more specific

having typical specifications such as the humidy of the air or the ultimate analysis option for the

coal.The stack is just a different type of sink to symbolized the outlet of the flue gas from the power

plant. The junction model is a simple model that allows the user to join or divide to streams.

Figure A.10: gCCS recycle model configuration.

A.3 Controller models

The controller models is a generic model, that can receive any type of measure variable and ma-

nipulate a valve, the model is prenseted in the figure . The controller can be proportional and integral

but does not have the derivative option. A set point specification or a cascade control can set the con-

troller objective. The model is presented in the figure A.11, has one inlet port for the measured varible,

another inlet port if a cascade controller is implemented and an outlet port manipulated variable.

A-8

Figure A.11: gCCS controller model configuration.


The Controller will include the following obligatory specifications:

1. Stop integration:

• Active or inactive

2. Action:

• Direct or reverse

3. Set point specification:

• User or port specification

4. Controller parameters:

• Bias (initial value for manipulated variable)

• Gain

• Reset time

• Maximum and minimum input

• Maximum and minimum output

A-9

BMain Operating Conditions and

Results

B-1

B.1 Main operating conditions from Romeo et al.[2].

Table B.1: Main operating conditions deviation from reference [2].(for stream identification please see fig 5.1)

Stream T(oC) p(bar) F (kg/s) Stream T(oC) p(bar) F (kg/s)

1 590.0 300.0 350.0 19 79.4 22.0 22.22 379.8 81.8 22.1 20 80.0 22.0 251.53 342.4 62.2 26.0 21 108.0 1.6 13.74 342.4 62.2 301.9 22 110.0 22.0 251.55 610.0 60.9 301.9 23 150.4 22.0 13.66 496.2 29.9 17.3 24 140.4 22.0 265.17 365.8 11.8 38.1 25 36.2 0.1 18.68 365.8 11.8 18.6 26 186.2 11.5 350.09 365.8 11.8 19.5 27 192.4 344.0 350.010 261.8 4.9 13.6 28 206.1 29.3 65.411 152.8 1.7 13.7 29 306.7 29.9 17.312 82.2 0.5 8.6 30 225.4 60.9 48.113 60.4 0.2 10.7 31 219.4 344.0 350.014 32.9 0.1 199.9 32 261.7 80.2 22.115 57.0 0.2 10.7 33 255.7 344.0 350.016 32.9 0.1 229.3 34 281.7 344.0 350.017 33.0 22.0 229.3 35 286.2 344.0 350.018 58.0 22.0 229.3

Table B.2: Key performance indicators (KPI) and flue gas composition from reference [2].

KPI Value Flue gas compostion %

Gross power (MW) 479.5 CO2 14.44Net Power (MW) 455.5 N2 75.50Specific CO2 emissions (gCO2/kwh gross) 702.2 H2O 6.64Gross efficiency (%) 47.2 O2 3.37Coal flowrate (kg/s) 38.5 SO2 0.05Flue gas flowrate (kg/s) 438.6

B-2

B.2 Design Results

Table B.3: Main operating conditions from design results.(for stream identification please see fig 5.1)

gCCS results Deviation to Romeo et al.[2]

Stream T(oC) p(bar) F (kg/s) Stream T(oC) p(%) F(%)

1 591,1 303,5 350,0 1 1,1 1,2 0,02 379,8 81,8 22,1 2 0,0 0,0 0,03 342,4 62,2 26,1 3 0,0 0,0 0,34 342,4 62,2 301,8 4 0,0 0,0 0,05 610,0 60,9 301,8 5 0,0 0,0 0,06 496,2 29,9 18,3 6 0,0 0,0 5,57 365,8 11,8 37,8 7 0,0 0,0 -0,78 365,8 11,8 18,6 8 0,0 0,0 0,09 365,8 11,8 19,2 9 0,0 0,0 -1,410 261,8 4,9 13,6 10 0,0 0,0 -0,111 152,8 1,7 13,4 11 0,0 0,0 -1,912 82,2 0,5 8,6 12 0,0 0,0 -0,113 60,4 0,2 10,1 13 0,0 0,0 -5,614 32,9 0,1 200,0 14 0,0 0,0 0,115 57,0 0,2 10,1 15 0,0 0,0 -5,616 32,9 0,1 228,7 16 0,0 0,0 -0,317 32,9 22,0 228,7 17 -0,1 0,0 -0,318 58,0 22,0 228,7 18 0,0 0,0 -0,319 79,5 22,0 22,0 19 0,1 0,0 -0,720 80,4 22,0 250,8 20 0,4 0,0 -0,321 108,0 1,6 13,4 21 0,0 0,0 -1,922 110,0 22,0 250,8 22 0,0 0,0 -0,323 150,4 22,0 13,6 23 0,0 0,0 -0,124 140,5 22,0 264,3 24 0,1 0,0 -0,325 36,2 0,1 18,6 25 0,0 0,0 0,026 186,0 11,5 350,0 26 -0,2 0,0 0,027 190,8 344,0 350,0 27 -1,6 0,0 0,028 206,1 29,3 66,4 28 0,0 0,0 1,629 315,1 29,9 18,3 29 8,4 0,0 5,530 225,4 60,9 48,2 30 0,0 0,0 0,231 219,4 344,0 350,0 31 0,0 0,0 0,032 261,7 80,2 22,1 32 0,0 0,0 0,033 255,7 344,0 350,0 33 0,0 0,0 0,034 281,7 344,0 350,0 34 0,0 0,0 0,035 286,2 344,0 350,0 35 0,0 0,0 0,0

Table B.4: Key performance indicators (KPI) and flue gas composition from design results.



B-3

Table B.5: Equipment parameters for the feedwater heaters and the condenser.

Parameters Feedwater Heaters Condenser1 2 3 4 5 6 7 8

TTD (K) 2.1 0.9 3.3 11.1 13.1 20.9 13.5 – –Area (m2) 509.6 673.6 180.3 86.8 590.4 922.6 259.4 15.8 7343.3

Table B.6: Equipment parameters for the turbines.

Parameters HP 1 HP 2 IP 1 IP 2 LP 1 LP 2 LP 3 LP 4 LP 5 Turpump

η (%) 89.3 88.5 88.9 89.3 87.9 91.6 62.1 26.5 98.5 88.1Stodola’sconstant 20235.2 1008.6 779.4 270.7 65.9 16.1 2.8 0.3 0.06 13912.3

B.3 Operational Results

Table B.7: Main operating conditions from operational results.(for stream identification please see fig 5.1)


Stream T(oC) p(bar) F (kg/s) Stream T(oC) p(%) F(%)1 590,0 300,0 350,0 1 0,0 0,0 0,02 379,8 81,8 22,1 2 0,0 0,0 0,03 342,4 62,2 26,1 3 0,0 0,0 0,34 342,4 62,2 301,8 4 0,0 0,0 0,05 610,0 60,9 301,8 5 0,0 0,0 0,06 496,2 29,9 18,3 6 0,0 0,0 5,57 365,8 11,8 37,8 7 0,0 0,0 -0,78 365,8 11,8 18,6 8 0,0 0,0 0,09 365,8 11,8 19,2 9 0,0 0,0 -1,4

10 261,8 4,9 13,6 10 0,0 0,0 -0,111 152,8 1,7 13,4 11 0,0 0,0 -1,912 82,2 0,5 8,6 12 0,0 0,0 0,013 60,4 0,2 10,1 13 0,0 -0,2 -5,714 32,9 0,1 200,0 14 0,0 0,0 0,115 57,0 0,2 10,1 15 0,0 -0,2 -5,716 32,9 0,1 228,7 16 0,0 0,0 -0,317 32,9 22,0 228,7 17 -0,1 0,0 -0,318 58,0 22,0 228,7 18 0,0 0,0 -0,319 79,5 22,0 22,0 19 0,1 0,0 -0,720 80,4 22,0 250,8 20 0,4 0,0 -0,321 108,0 1,6 13,4 21 0,0 0,0 -1,922 110,0 22,0 250,8 22 0,0 0,0 -0,323 150,4 22,0 13,6 23 0,0 0,0 -0,124 140,5 22,0 264,3 24 0,1 0,0 -0,325 36,2 0,06 18,6 25 0,0 0,0 0,026 186,0 11,5 350,0 26 -0,2 0,0 0,027 190,8 344,0 350,0 27 -1,6 0,0 0,028 206,1 29,3 66,4 28 0,0 0,0 1,629 315,1 29,9 18,3 29 8,4 0,0 5,530 225,4 60,9 48,2 30 0,0 0,0 0,231 219,4 344,0 350,0 31 0,0 0,0 0,032 261,7 80,2 22,1 32 0,0 0,0 0,033 255,7 344,0 350,0 33 0,0 0,0 0,034 281,7 344,0 350,0 34 0,0 0,0 0,035 286,2 344,0 350,0 35 0,0 0,0 0,0

B-4

Table B.8: Key performance indicators (KPI) and flue gas composition from operational results.


Gross power (MW) 471.3 CO2 14.53Net Power (MW) 452.4 N2 75.41

Specific CO2 emissions (gCO2/kwh gross) 718.7 H2O 6.64Gross efficiency (%) 46.4 O2 3.37Coal flowrate (kg/s) 38.5 SO2 0.05

Flue gas flowrate (kg/s) 438.7

B.4 Daily Cycle Results

B.4.1 Results for 95% load operation

Table B.9: Main operating conditions for 95% load.(for stream identification please see fig 5.1)



1 585,2 284,7 332,1 1 -4,8 -5,1 -5,12 377,1 78,0 20,4 2 -2,7 -4,7 -7,83 340,1 59,4 24,2 3 -2,3 -4,5 -7,04 340,1 59,4 287,5 4 -2,3 -4,5 -4,85 610,0 58,1 287,5 5 0,0 -4,6 -4,86 496,5 28,5 17,0 6 0,3 -4,5 -1,87 366,1 11,3 36,2 7 0,3 -4,6 -5,08 366,1 11,3 17,7 8 0,3 -4,6 -4,79 366,1 11,3 18,5 9 0,3 -4,6 -5,3

10 262,3 4,7 12,7 10 0,5 -4,5 -6,911 153,3 1,6 12,6 11 0,5 -4,4 -8,112 82,9 0,5 8,2 12 0,7 -4,2 -4,913 61,2 0,2 9,2 13 0,8 -3,9 -14,114 32,9 0,1 191,7 14 0,0 0,0 -4,115 48,7 0,2 9,2 15 -8,3 -3,9 -14,116 32,9 0,0 218,6 16 0,0 0,0 -4,617 32,9 22,0 218,6 17 -0,1 0,0 -4,618 57,1 22,0 218,6 18 -0,9 0,0 -4,619 77,1 22,0 20,8 19 -2,3 0,0 -6,520 79,2 22,0 239,4 20 -0,8 0,0 -4,821 102,4 1,5 12,6 21 -5,6 -4,6 -8,122 108,6 22,0 239,4 22 -1,4 0,0 -4,823 142,8 22,0 12,7 23 -7,6 0,0 -6,924 138,5 22,0 252,1 24 -1,9 0,0 -4,925 36,1 0,1 17,7 25 -0,1 -0,1 -4,726 183,9 11,0 332,1 26 -2,3 -4,7 -5,127 188,6 344,0 332,1 27 -3,8 0,0 -5,128 201,9 27,9 61,5 28 -4,2 -4,6 -5,929 307,8 28,5 17,0 29 1,1 -4,5 -1,830 221,8 58,1 44,6 30 -3,6 -4,6 -7,431 216,8 344,0 332,1 31 -2,6 0,0 -5,132 257,2 76,4 20,4 32 -4,5 -4,8 -7,833 252,6 344,0 332,1 33 -3,1 0,0 -5,134 278,3 344,0 332,1 34 -3,4 0,0 -5,135 282,9 344,0 332,1 35 -3,3 0,0 -5,1

B-5

Table B.10: Key performance indicators (KPI) and flue gas composition for 95% load.


Gross power (MW) 447.69 CO2 14.53Net Power (MW) 429.77 N2 75.41

Specific CO2 emissions (gCO2/kwh gross) 723.06 H2O 6.64Gross efficiency (%) 42.86 O2 3.37Coal flowrate (kg/s) 39.56 SO2 0.05

Flue gas flowrate (kg/s) 419.10

B.4.2 Results for 90% load operation

Table B.11: Main operating conditions for 90% load.(for stream identification please see fig 5.1)



1 580,3 269,4 314,2 1 -9,7 -10,2 -10,22 374,3 74,1 18,7 2 -5,5 -9,4 -15,33 337,7 56,5 22,3 3 -4,7 -9,1 -14,14 337,7 56,5 273,1 4 -4,7 -9,1 -9,55 610,0 55,2 273,1 5 0,0 -9,3 -9,56 496,9 27,2 15,8 6 0,7 -9,1 -8,97 366,5 10,7 34,5 7 0,7 -9,1 -9,48 366,5 10,7 16,9 8 0,7 -9,1 -9,39 366,5 10,7 17,6 9 0,7 -9,1 -9,610 262,8 4,5 11,8 10 1,0 -8,9 -13,411 153,8 1,6 11,8 11 1,0 -8,7 -14,212 83,5 0,5 7,7 12 1,3 -8,4 -10,013 62,1 0,2 8,4 13 1,7 -7,7 -21,814 32,9 0,1 183,3 14 0,0 0,0 -8,315 43,5 0,2 8,4 15 -13,5 -7,7 -21,816 32,9 0,0 208,5 16 0,0 0,0 -9,117 32,9 22,0 208,5 17 -0,1 0,0 -9,118 56,3 22,0 208,5 18 -1,7 0,0 -9,119 74,7 22,0 19,5 19 -4,7 0,0 -12,220 78,0 22,0 228,0 20 -2,0 0,0 -9,321 97,1 1,5 11,8 21 -10,9 -9,2 -14,222 107,1 22,0 228,0 22 -2,9 0,0 -9,323 135,7 22,0 11,8 23 -14,7 0,0 -13,424 136,5 22,0 239,8 24 -3,9 0,0 -9,625 36,2 0,1 16,9 25 0,0 0,1 -9,326 181,7 10,4 314,2 26 -4,5 -9,4 -10,227 186,3 344,0 314,2 27 -6,1 0,0 -10,228 197,7 26,6 56,8 28 -8,4 -9,3 -13,129 300,3 27,2 15,8 29 -6,4 -9,1 -8,930 218,2 55,2 41,1 30 -7,2 -9,3 -14,631 214,1 344,0 314,2 31 -5,3 0,0 -10,232 252,8 72,5 18,7 32 -8,9 -9,6 -15,333 249,4 344,0 314,2 33 -6,3 0,0 -10,234 274,8 344,0 314,2 34 -6,9 0,0 -10,235 279,5 344,0 314,2 35 -6,7 0,0 -10,2

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Table B.12: Key performance indicators (KPI) and flue gas composition for 90% load.



B.5 Reheat Temperature Sensitivity Results

B.5.1 Reheat temperature increase by 1.2%

Table B.13: Main operating conditions results for a reheat temperature increase of 1.2%.(for stream identificationplease see fig 5.1)



1 591,1 303,5 350,0 1 0,0 0,0 0,02 380,3 82,1 22,0 2 0,5 0,3 -0,43 343,1 62,5 26,1 3 0,7 0,6 0,24 343,1 62,5 301,8 4 0,7 0,6 0,05 618,8 61,2 301,8 5 8,8 0,6 0,06 504,3 30,1 18,3 6 8,1 0,6 0,17 372,9 11,9 37,8 7 7,1 0,6 -0,18 372,9 11,9 18,6 8 7,1 0,6 0,09 372,9 11,9 19,2 9 7,1 0,6 -0,210 268,0 4,9 13,5 10 6,2 0,7 -0,811 157,9 1,7 13,3 11 5,1 0,7 -0,812 86,8 0,5 8,7 12 4,6 0,8 0,813 65,0 0,2 9,9 13 4,6 0,8 -1,614 32,9 0,1 200,4 14 0,0 0,0 0,215 45,6 0,2 9,9 15 -11,4 0,8 -1,616 32,9 0,1 228,9 16 0,0 0,0 0,117 32,9 22,0 228,9 17 0,0 0,0 0,118 58,1 22,0 228,9 18 0,2 0,0 0,119 79,7 22,0 22,0 19 0,2 0,0 -0,220 80,6 22,0 250,9 20 0,2 0,0 0,121 105,0 1,6 13,3 21 -3,0 0,8 -0,822 110,2 22,0 250,9 22 0,2 0,0 0,123 148,0 22,0 13,5 23 -2,4 0,0 -0,824 140,7 22,0 264,4 24 0,1 0,0 0,025 37,5 0,1 18,6 25 1,3 7,4 0,026 186,3 11,6 350,0 26 0,3 0,6 0,027 191,1 344,0 350,0 27 0,3 0,0 0,028 206,4 29,5 66,4 28 0,3 0,6 0,029 316,6 30,1 18,3 29 1,5 0,6 0,130 225,8 61,2 48,2 30 0,4 0,6 -0,131 219,7 344,0 350,0 31 0,3 0,0 0,032 261,9 80,5 22,0 32 0,2 0,4 -0,433 256,1 344,0 350,0 33 0,4 0,0 0,034 281,9 344,0 350,0 34 0,2 0,0 0,035 286,6 344,0 350,0 35 0,4 0,0 0,0

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Table B.14: Key performance indicators (KPI) and flue gas composition for a reheat temperature increase of1.2%.




Table B.15: Main operating conditions results for a reheat temperature increase of 7.4%.(for stream identificationplease see fig 5.1)



1 591,1 303,5 350,0 1 0,0 0,0 0,02 382,0 83,2 21,7 2 2,2 1,7 -1,93 345,8 63,9 26,4 3 3,4 2,7 1,24 345,8 63,9 301,9 4 3,4 2,7 0,05 654,2 62,6 301,9 5 44,2 2,8 0,06 536,6 30,8 18,3 6 40,4 2,9 0,37 401,3 12,2 37,7 7 35,5 3,1 -0,48 401,3 12,2 18,6 8 35,5 3,1 0,29 401,3 12,2 19,0 9 35,5 3,1 -1,0

10 293,0 5,1 13,1 10 31,2 3,4 -3,711 178,5 1,8 13,0 11 25,7 3,7 -3,112 105,2 0,5 8,9 12 23,0 3,8 2,913 83,3 0,2 9,9 13 22,9 3,8 -1,914 32,9 0,1 201,1 14 0,0 0,0 0,515 35,5 0,2 9,9 15 -21,5 3,8 -1,916 32,9 0,1 229,6 16 0,0 0,0 0,417 32,9 22,0 229,6 17 0,0 0,0 0,418 58,8 22,0 229,6 18 0,8 0,0 0,419 80,6 22,0 21,9 19 1,1 0,0 -0,720 81,3 22,0 251,5 20 0,9 0,0 0,321 96,5 1,7 13,0 21 -11,5 3,9 -3,122 111,2 22,0 251,5 22 1,2 0,0 0,323 140,3 22,0 13,1 23 -10,1 0,0 -3,724 141,2 22,0 264,6 24 0,7 0,0 0,125 42,8 0,1 18,6 25 6,6 42,4 0,226 187,4 11,9 350,0 26 1,4 3,1 0,027 192,3 344,0 350,0 27 1,4 0,0 0,028 207,8 30,2 66,4 28 1,7 2,9 -0,129 322,4 30,8 18,3 29 7,3 2,9 0,330 227,1 62,6 48,1 30 1,7 2,8 -0,231 221,0 344,0 350,0 31 1,6 0,0 0,032 262,9 81,6 21,7 32 1,2 1,7 -1,933 257,5 344,0 350,0 33 1,8 0,0 0,034 282,9 344,0 350,0 34 1,2 0,0 0,035 288,2 344,0 350,0 35 2,0 0,0 0,0

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Table B.17: Main operating conditions results for a reheat temperature increase of 14.5%.(for stream identifica-tion please see fig 5.1)



1 591,1 303,5 350,0 1 0,0 0,0 0,02 384,2 84,5 21,3 2 4,4 3,3 -3,73 349,1 65,5 26,7 3 6,7 5,4 2,34 349,1 65,5 302,0 4 6,7 5,4 0,15 698,3 64,2 302,0 5 88,3 5,5 0,16 577,1 31,6 18,4 6 80,9 5,6 0,57 437,2 12,5 37,4 7 71,4 6,1 -1,18 437,2 12,5 18,7 8 71,4 6,1 0,39 437,2 12,5 18,8 9 71,4 6,1 -2,4

10 324,5 5,2 12,7 10 62,7 6,7 -6,711 204,7 1,8 12,8 11 51,9 7,2 -5,012 128,1 0,5 9,0 12 45,9 7,3 4,113 105,6 0,2 10,0 13 45,2 7,2 -0,914 32,9 0,1 201,9 14 0,0 0,0 0,915 33,4 0,2 10,0 15 -23,6 7,2 -0,916 32,9 0,1 230,5 16 0,0 0,0 0,817 32,9 22,0 230,5 17 0,0 0,0 0,818 59,5 22,0 230,5 18 1,5 0,0 0,819 81,6 22,0 21,7 19 2,1 0,0 -1,520 82,2 22,0 252,3 20 1,8 0,0 0,621 90,9 1,7 12,8 21 -17,1 7,7 -5,022 112,3 22,0 252,3 22 2,3 0,0 0,623 133,4 22,0 12,7 23 -17,0 0,0 -6,724 142,0 22,0 264,9 24 1,5 0,0 0,225 49,6 0,1 18,7 25 13,5 102,2 0,326 188,8 12,2 350,0 26 2,7 6,3 0,027 193,7 344,0 350,0 27 2,8 0,0 0,028 209,3 31,0 66,3 28 3,2 5,8 -0,229 329,7 31,6 18,4 29 14,6 5,6 0,530 228,8 64,2 48,0 30 3,4 5,5 -0,531 222,5 344,0 350,0 31 3,1 0,0 0,032 264,2 82,9 21,3 32 2,5 3,4 -3,733 259,2 344,0 350,0 33 3,5 0,0 0,034 284,1 344,0 350,0 34 2,4 0,0 0,035 290,2 344,0 350,0 35 4,0 0,0 0,0

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