Simulation of a Subcritical Power Plant using a Boiler ... · Simulation of a Subcritical Power Plant using a Boiler Following Control sequence Carbon Capture and Storage networks

Simulation of a Subcritical Power Plant using a BoilerFollowing Control sequence

Carbon Capture and Storage networks

Ricardo Miguel Ferreira Fernandes

Dissertation for the degree of Master of

Chemical Engineering

JuriPresident: Prof. Dr. Sebastiao Manuel Tavares da Silva AlvesSupervisor: Prof. Dr.a Carla Isabel Costa PinheiroCo-Supervisor: Engr. Jose Alfredo Ramos PlasenciaVogal: Dr. Vitor Manuel Vieira Lopes

Dr. Javier Rodriguez

October 2012

Simulation of a Subcritical Power Plant using a BoilerFollowing Control sequence

Carbon Capture and Storage networks

Ricardo Miguel Ferreira Fernandes

Dissertacao para grau de Mestre em

Engenharia Quımica

JuriPresidente: Prof. Dr. Sebastiao Manuel Tavares da Silva AlvesOrientador: Prof. Dr.a Carla Isabel Costa PinheiroCo-Orientador: Engr. Jose Alfredo Ramos PlasenciaVogal: Dr. Vitor Manuel Vieira Lopes

Dr. Javier Rodriguez

Outubro 2012

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

Acknowledgments

I would like to thank Prof. Dr. Carla Pinheiro and Engr. Alfredo Ramos, my supervisors, for all

the availability and readiness to help during the internship and thesis development. To Dr. Adekola

Lawal, my direct supervisor, I also want to give a special thanks for the help he gave me during the

work for the thesis. For all the gCCS team I want to say thank you for the close cooperation on the

development of the flowsheets and library models during the 7 months of progress, because without

a team like that the thesis would be even more hard working.

For all the PSE people in general, I want to say that I appreciated the reception and sympathy.

To finish, I would like to thank my family, specially to my girlfriend and mother, for all the support

given to me for being far from home.

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Abstract

The objective of this work is to model a pulverized coal power plant and some of its component

units and to apply control based in the boiler following control approach, in order to analyse the

control system and the power plant performance at different operational conditions. The ETI-CCS

project comprises the modelling of the several components of the carbon capture and storage chain,

starting with the pulverized coal power plant, the basis of the thesis.

The modelling is developed in gPROMS and consists building some units to be added to the power

plant library. Some of the models are grabbed from this library to be connected and to represent a

pulverized coal power plant. The building of a flowsheet like the PCPP is a challenge, since the

number of recirculations, between the great number of units, is great.

By controlling the system, it was possible to represent, for example, the typical behaviour of the

key variables of the system in load changes, representing the daily cycle. From the performance

study it was concluded that for lower loads the power plant’s efficiency decreases, consuming more

resources per MW, and that the LHV of the coal and the efficiency of the turbines increase the net

efficiency.

Keywords

Boiler Following Control, Pulverized Coal Power Plant, Carbon Capture and Storage, Modelling,

gPROMS

v

Resumo

O objectivo do trabalho e modelar uma estacao termoelectrica de carvao pulverizado, e algumas

das suas unidades, e aplicar controlo utilizando o modo boiler following, de forma a analisar o controlo

do sistema e a performance da estacao termoeletrica a diferentes condicoes operacionais. O projecto

ETI-CCS inclui a modelacao dos diversos componentes da linha de captura e armazenamento de

CO2, iniciando pela estacao termoelectrica de carvao pulverizado, a base da tese.

A modelacao e desenvolvida em gPROMS e consite em construir algumas unidades para serem

adicionadas a biblioteca da power plant. Alguns dos modelos desta biblioteca sao conectados entre

si de forma a representar a estacao termoeletrica em causa. A construcao do flowsheet e um desafio,

uma vez que o numero de recirculacoes entre as inumeras unidades e bastante elevado.

Ao controlar o sistema foi possıvel, por exemplo, representar o comportamento tıpico das variaveis

chaves do sistema em alteracoes de load, representando um ciclo diario. Do estudo de performance

foi concluıdo que para menores loads a eficiencia do sistema baixa, consumindo dessa forma mais

recursos para obter a mesma potencia, e que o LHV do carvao e a eficiencia das turbinas aumentam

a eficiencia lıquida.

Palavras Chave

Controlo Boiler Following, Estacao Termoelectrica de Carvao Pulverizado, Captura e Armazena-

mento de CO2, Modelacao, gPROMS

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Contents

1 Introduction 1

1.1 Motivation and Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

1.2 State of The Art . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

1.3 Original Contributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

1.4 Thesis Outline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

2 Background 5

2.1 Pulverized Coal Power Plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

2.1.1 Steam Cycle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

2.1.1.A Boiler . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

2.1.1.B Governor Valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

2.1.1.C Steam Turbine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

2.1.1.D Generator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

2.1.1.E Heat Transfer Cycle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

2.1.2 Flue Gas Treatment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

2.1.2.A Electrostatic Precipitator . . . . . . . . . . . . . . . . . . . . . . . . . . 18

2.1.2.B Selective Catalytic Reduction . . . . . . . . . . . . . . . . . . . . . . . . 18

2.1.2.C Air Pre - Heater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

2.1.2.D Gas - Gas Heater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

2.1.2.E Flue Gas Desulfurization . . . . . . . . . . . . . . . . . . . . . . . . . . 19

2.1.2.F Blower . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

2.2 Pulverized Coal Power Plant Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

2.2.1 Boiler / Turbines System Control . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

2.2.1.A Boiler Following Control . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

2.2.1.B Turbine Following Control . . . . . . . . . . . . . . . . . . . . . . . . . . 22

2.2.1.C Coordinated Boiler Turbine Control . . . . . . . . . . . . . . . . . . . . . 22

2.2.1.D Integrated Boiler Turbine - Generator Control . . . . . . . . . . . . . . . 22

2.2.2 Boiler Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

2.2.2.A Superheat and Reheat Steam Temperature Control . . . . . . . . . . . 23

2.2.2.B Boiler Drum Level Control . . . . . . . . . . . . . . . . . . . . . . . . . . 24

2.2.3 Heat Transfer Cycle Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

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2.2.3.A Condenser Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

2.2.3.B Feedwater Heater Control . . . . . . . . . . . . . . . . . . . . . . . . . . 25

2.2.3.C Deaerator Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

2.3 Carbon Capture and Storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

2.3.1 Post - Combustion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

2.3.1.A Absorption . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

2.3.1.B Adsorption . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

2.3.1.C Membranes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

2.3.2 Pre - Combustion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

2.3.2.A Chemical Absorbents . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

2.3.2.B Physical Absorbents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

2.3.2.C Other Options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

2.3.3 Oxy-combustion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

2.3.4 Interaction With PCPP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

3 Modelling PCPP components 32

3.1 Deaerator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

3.1.1 Inlets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

3.1.2 Outlets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

3.1.3 Variables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

3.1.4 Equations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

3.1.5 Degrees of freedom . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

3.2 SCR (Selective Catalytic Reduction) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

3.2.1 Inlets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

3.2.2 Outlets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

3.2.3 Parameters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

3.2.4 Variables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

3.2.5 Equations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

3.2.6 Degrees of freedom . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

3.3 Blower . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42

3.3.1 Inlets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

3.3.2 Outlets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

3.3.3 Parameters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

3.3.4 Variables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

3.3.5 Equations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

3.3.6 Degree of freedom . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

3.4 Controller . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

3.4.1 Inlets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

3.4.2 Outlets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

x

3.4.3 Variables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

3.4.4 Initial Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

3.4.5 Equations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46


3.5 Drum . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

3.5.1 Inlets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

3.5.2 Outlets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

3.5.3 Parameters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

3.5.4 Variables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

3.5.5 Initial Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50

3.5.6 Equations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50


4 Modelling a PCPP 53

4.1 Design Mode . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

4.1.1 Model description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

4.1.2 Results and Discussion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58

4.2 Operational Mode . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60



4.3 Control Mode . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61



4.3.2.A Controller Calibration . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62

4.3.2.B Daily Cycle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64

4.3.2.C Disturbances . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69

4.4 Sensitivity Analyses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70

4.4.1 Heating Value of the Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70

4.4.2 Steam Turbine’s Efficiency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71

5 Conclusions and Future Work 73

5.1 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74

5.2 Future Work . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75

Bibliography 77

Appendix A gCCS Model Library A-1

A.1 BoilerSubcritical . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-2

A.1.1 Ports structure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-2

A.1.2 Ports specifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-2

A.1.3 Specification Dialog . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-3

xi

A.2 GovernorValve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-4




A.3 SteamTurbineStage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-6




A.4 Generator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-7




A.5 BoilerSteamCondenser . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-8




A.6 FeedWaterHeater . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-9




A.7 PumpUtility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-11




A.8 ElectrostaticPrecipitator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-12




A.9 FGD . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-13




A.10 GGH . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-14




A.11 ControlValve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-15



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Appendix B Source data B-1

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List of Figures

2.1 Pulverized Coal Power Plant blocs diagram. . . . . . . . . . . . . . . . . . . . . . . . . . 6

2.2 Steam cycle flowsheet. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

2.3 Rankine cycle flowsheet and T-S diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . 8

2.4 Rankine cycle with reheat flowsheet and T-S diagram. . . . . . . . . . . . . . . . . . . . 9

2.5 Regenerative Rankine cycle flowsheet and T-S diagram. . . . . . . . . . . . . . . . . . . 10

2.6 Combined reheat and regenerative Rankine cycle flowsheet and T-S diagram. . . . . . . 10

2.7 Combustion gas concentrations at percent of the theoretical combustion air. . . . . . . . 12

2.8 Typical flue gas treatment line. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

2.9 One element feedwater control. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

2.10 Two element feedwater control. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

2.11 Three element feedwater control. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

2.12 Post-Combustion capture diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

2.13 PCC’s absorption flowsheet. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

2.14 Pre-Combustion capture diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

2.15 Pre-Combustion capture absorption flowsheet (AGR). . . . . . . . . . . . . . . . . . . . 29

2.16 Oxy-Combustion capture diagram. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

2.17 Interaction between MEA and PCC. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

3.1 Deaerator model in gPROMS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

3.2 SCR model in gPROMS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

3.3 Blower model in gPROMS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

3.4 Controller model in gPROMS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

3.5 Drum model in gPROMS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

4.1 Design flowsheet model in gPROMS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56

4.2 Control flowsheet model. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62

4.3 Megawatt load change and throttle pressure deviation. . . . . . . . . . . . . . . . . . . . 63

4.4 Load and pressure responses to different tunings. . . . . . . . . . . . . . . . . . . . . . 63

4.5 Grid and power plant’s load curves. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65

4.6 Power load and governor valve stem position. . . . . . . . . . . . . . . . . . . . . . . . . 65

4.7 Superheated steam pressure deviation from SP and coal flowrate deviation from 100%

load . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65

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4.8 Boiler feedwater flow and governor valve’s outlet pressure deviation from 100% load . . 66

4.9 Heated feedwater temperature and steam flow deviations from 100% load, in the Heater2. 66

4.10 Condenser’s pressure and cooling water flowrate deviations from 100% load. . . . . . . 67

4.11 Deaerator’s and condenser’s tank level deviations from SP. . . . . . . . . . . . . . . . . 67

4.12 Condensate valve’s stem position. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68

4.13 Power load and governor valve stem position. . . . . . . . . . . . . . . . . . . . . . . . . 69

4.14 Superheated steam pressure and coal flowrate deviations from 100% load. . . . . . . . 70

A.1 BoilerSubcritical model in gPROMS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-2

A.2 GovernorValve model in gPROMS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-4

A.3 SteamTurbineStage model in gPROMS. . . . . . . . . . . . . . . . . . . . . . . . . . . . A-6

A.4 Generator model in gPROMS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-7

A.5 BoilerSteamCondenser model in gPROMS. . . . . . . . . . . . . . . . . . . . . . . . . . A-8

A.6 FeedWaterHeater model in gPROMS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-10

A.7 PumpUtility model in gPROMS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-11

A.8 ESP model in gPROMS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-12

A.9 FGD model in gPROMS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-13

A.10 GGH model in gPROMS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-14

A.11 ControlValve model in gPROMS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-15

B.1 Flowsheet of the modelled Pulverized Coal Power Plant’s Steam Cycle. . . . . . . . . . B-2

xvi

List of Tables

1.1 Electricity market share (%). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

2.1 Steam conditions in the different power plant critical types. . . . . . . . . . . . . . . . . . 7

3.1 Variables of the Deaerator model. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

3.2 DOF analysis to the Deaerator model. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

3.3 Parameters used in the SCR model. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

3.4 Variables of the SCR model. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

3.5 Case to distinguish modes in theSCR model. . . . . . . . . . . . . . . . . . . . . . . . . 39

3.7 Case to distinguish ammonia types in the SCR model. . . . . . . . . . . . . . . . . . . . 41

3.8 DOF analysis to the SCR model. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42

3.9 Parameters used in theBlower model. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

3.10 Variables of the Blower model. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

3.11 DOF analysis to the Blower model. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

3.12 Variables of the Controller model. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

3.13 Set Point assignment modes in the Controller model. . . . . . . . . . . . . . . . . . . . . 46

3.14 Action (Manipulated-Controlled) in the Controller model. . . . . . . . . . . . . . . . . . . 46

3.15 DOF analysis to the Controller model. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

3.16 Parameters used in the Drum model. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

3.17 Variables of the Drum model. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

3.18 DOF analysis to the Drum model. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

4.1 Key models used in the flowsheets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54

4.2 Control models used in the flowsheets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

4.3 Auxiliary models used in the flowsheets. . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

4.4 Key specifications in design mode. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57

4.5 Average and maximum of the absolute stream deviations from Alstrom (relative deviation). 58

4.6 Flue gas composition compared to Alstrom (relative deviation, in %). . . . . . . . . . . . 59

4.7 gPROMS key performance indicators compared to Alstrom (relative deviation, in %). . . 59

4.8 Key models used in the flowsheets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60

4.9 Average and maximum of the absolute steam deviations from design (relative deviation). 61

4.10 Parameters used in the control system. . . . . . . . . . . . . . . . . . . . . . . . . . . . 64

xvii

4.11 Average and maximum of the absolute stream deviations from operational (relative

deviation, in %). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64

4.12 Part-load key performance indicators compared to full-load (relative deviation, in %). . . 68

4.13 Errors in the final steady-state (relative errors, in%). . . . . . . . . . . . . . . . . . . . . 70

4.14 Key performance indicators compared to the normal LHV (relative deviation, in %). . . . 71

4.15 Key performance indicators compared to the normal efficiency (relative deviation, in%). 72

B.1 Steam cycle data from Lawrence. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-2

B.2 Key performance indicators from the Alstrom report. . . . . . . . . . . . . . . . . . . . . B-3

B.3 Coal ultimate analysis from the Alstrom report. . . . . . . . . . . . . . . . . . . . . . . . B-3

B.4 Flue gas composition from the Alstrom report. . . . . . . . . . . . . . . . . . . . . . . . . B-3

B.5 Boiler’s streams conditions from the Alstrom report. . . . . . . . . . . . . . . . . . . . . B-3

xviii

xix

Abbreviations

Abbreviation Description

AGR Acid Gas RemovalASU Air Separation UnitAUSC Advanced Ultra Supercritical Power PlantBFW Boiler feedwaterCCGT Combined Cycle Gas TurbineCCS Carbon Capture and StorageDCA Drain Cooler ApproachDOF Degrees of freedomDFGD Dry Flue Gas DesulfurizationEDF Electricite de FranceE.ON E.ON Energy LimitedESP Electrostatic PrecipitatorETI Energy Technologies InstituteEU European UnionFD Forced DraftFG Flue GasFGD Flue Gas DesulfurizationFWH Feedwater HeatergCCS CCS system modelling toolkit, based on gPROMSGGH Gas-Gas HeatergPROMS gPROMS® ModelBuilderGQCS Combustion/Heat Transfer/Gas Quality Control SystemHP High Pressure Steam TurbineID Induced DraftIP Intermediate Pressure Steam TurbineIGCC Integrated Gasification Combined CycleKPI Key performance indicatorsLHV Lower Heating ValueLP Low Pressure Steam TurbineLSFO Limestone Forced OxidizedMDEA Methyl DiethanolamineMEA MonoEthanolAmineMSD Model Specification DialogOSTG Once-Through Steam GenerationP Proportional ControllerPCC Pos Combustion CapturePCPP Pulverized Coal Power PlantPI Proportional plus Integral ControllerPID Proportional plus Integral plus Derivative ControllerPSE Process Systems EnterpriseRH Reheat SteamSCR Selective Catalytic ReductionSH Superheat SteamTTD Terminal Temperature DifferenceUK United KingdomUSC Ultra Supercritical Power PlantWFGD Wet Flue Gas Desulfurization

xx

List of Symbols

Latin Symbols

Variable Description Units

B Bias –D Diameter mE Error –F Mass flowrate kg/sgn Gravitational constant m/s2

H Level (tank) mH Head (compression) J/kgh Mass specific enthalpy J/kgI Integral term WK Gain –M Mass hold-up kgMV Measured variable –N Number of streams –n Polytropic index –Occ Occupation percentage %OP Manipulated variable –P Power WP Proportional term (controller) Wp Pressure Papratio Pressure ratio across the unit –Q Heat duty Wr Reaction mole consume mol/sratioi,j Ratio between i and j –SP Set Point –T Temperature KtR Residence time sU Energy hold-up JV Volume m3

v Velocity m/sM Molecular weight g/molW Work Ww Mass fraction –x Mole fraction –z Height m

xxi

Greek Symbols

Variable Description Units

α Kinetic coefficient –Γ Mole percentage %γ Isentropic index (Blower) –γi,j Stoqueometric coefficient of the component i in the reaction j –γ Mass concentration mg/Nm3

∆ Differential –∆hr,i Specific enthalpies of reaction i –∆p Pressure drop or pressure increment –η Efficiency %ρ Mass density kg/m3

τI Reset time sφbleed Bleed fraction –

Subscripts

Variable Description

E Externalfluid FluidI Inlernali Component iideal Idealin Inlet streamis Isentropiciso IsothermalL Liquid phaselim LimitMAX MaximumMIN Minimumout Outlet streamP ,pol Polytropicreal Actualswt SwitchV Vapour phase

Superscripts

Variable Description

BFW Boiler feedwaterdry Dry basisj Stream jNH3 NH3 streamN NormalSteam Steam′ Deviation

xxii

1Introduction

Contents1.1 Motivation and Objectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31.2 State of The Art . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31.3 Original Contributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41.4 Thesis Outline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

1

On the first three decades of the 21st century the global energy demand is projected to grow about

1.7% per year. Between the energy investments, the electricity production represents 60%, against

oil (19%), gas (19%) and coal (2%). This shows the electricity importance in the energy market. [1]

In terms of world’s electricity itself, the demand is expected to duplicate from 2000 to 2030, growing

at an annual rate of 2.4%. Although, it is expected loss of market share by the coal (essentially to

gas), in 2030 it continues to be the main electricity source in the world. The natural gas power plants

have higher efficiency than the coal ones, but the coal has the advantage to be more abundant in

many parts of the world and to have a more stable price. Other conclusion is that the fossil fuel power

stations dominate the electricity sector [1].

Table 1.1: Electricity market share (%) [1].

Electricity source 2000 2010 2020 2030

Coal 38.9 35.6 35.5 36.8Oil 8.1 6.7 5.4 4.2Natural Gas 17.4 24.7 30.1 31.5H2 fuel cells 0 0 0.1 1.1Nuclear Energy 16.8 14.4 9.6 8.6Hydro Energy 17.2 15.9 14.9 13.5Other Renewable Energies 1.6 2.6 3.4 4.4Losses 1.5 1.5 1.5 1.5

Between the fossil fuel power stations, the most common are:

• Pulverized Coal Power Plant - PCPP.

• Integrated gasification combined cycle - IGCC.

• Combined Cycle Gas Turbine - CCGT.

In the Kyoto Protocol, in 1997, the EU countries committed themselves to reduce the greenhouse

gases emissions by at least 5% below 1990 levels until 2008-2012. However this target was redefined

to a reduction of 80% until 2050 [2] [3].

Since the CO2 is the main concern gas between the greenhouse gases, it is imperative to improve

technologies to reduce the CO2 emissions. This will pass for increasing renewable energies and

implementing carbon capture and storage (CCS) in the fossil power plants, because the power plants

are responsible for around 25% of the global emissions. CCS is an important option in the portfolio of

available solutions to combat this problem, because it allows to reduce the CO2 emissions from fossil

systems, significantly [4].

The most important technologies to apply CCS in fossil power plants are:

• Post Combustion Capture - PCC

• Pre Combustion Capture

• Oxy-Combustion

Because the coal is fossil fuel most widely used in power plants, and the most unclean, it is

especially important to develop the carbon capture and storage in the pulverized coal power plants

(PCPP).

2

Although the CCS reduces the efficiency in the energy production in the power plants, investments

must be done in this area to improve the technologies and achieve the CCS objective without com-

promising the electricity sector. At the current state of technology, units retrofitted with carbon capture

would suffer a decrease around 12% in the efficiency and an increase between 20 and 30% in the

coal consume to supply the same electricity output [5] [6].

Due to this panorama, in September 2011, ETI (Energy Technologies Institute), responsible for

projects to improve the energy sector, founded the CCS project to study this problem and to accelerate

the carbon capture and storage in UK, a technology that will become increasingly important because

the emissions capital penalty will reach the CCS investment and efficiency penalty in applying capture.

1.1 Motivation and Objectives

PSE integrated the ETI-CCS project in September 2011 with the objective to build the gCCS toolkit

in collaboration with important “stakeholders” in this area, such as E.ON, EDF and Rolls Royce. This

tool incorporates the modelling in gPROMS of power generation and CO2 capture, compression,

transmission, injection and storage.

The final tool will be important to study this new theme. For example, it will allow to design, to

simulate, to control and to optimize the full chain. The models’ flexibility and robustness is really

important to let the all chain respond to different consumers’ demands as quick as possible.

Since the gCCS project is in the pulverized coal power plant (PCPP) modelling phase, this thesis

is incorporated in the construction of a pulverized coal power plant modelling kit, the most problematic

power plant in terms of CO2 emissions.

The thesis objective is to design a power plant with operational data and to simulate the operation

of the designed power plant, with control incorporated. It is used operational data from a subcritical

PCPP ’s steam cycle ([7]), it is implemented one of the different types of control (boiler following

control) and the simulations consist in set point changes (daily cycle, e.g.) and disturbances to the

system.

To do the final flowsheet several gCCS models are required. Some of the models that need to be

developed to the gCCS library are done in the scope of the thesis: Deaerator, SCR, Blower, Controller

and Drum.

1.2 State of The Art

A lot of work has been developed in the scope of power plant modelling.

Lots of reports focused in performance studies to the different kinds of power plants have been

done. In these studies the performance of power plants when connected to the several CCS tech-

nologies is commonly analysed , both for retrofit and for newly built.

An example of this kind of study applied to a PCPP is a report done by the US Department

of Energy. Using test data, it was developed a steady-state model for the boiler of an existing power

3

plant, and it was used to study the base case (power plant without capture) and three capture concepts

[8].

Also developed by the US Department of Energy and inserted in the problem of CO2 capture, is

the study of cost and performance of a power plant with and without capture, using for it the ASPEN

Plus modelling program. For example, PCPP with different technologies and conditions were target

of this study [9].

In terms of power plant control modelling one interesting work was developed is the University

of Rostock. The dynamic model was focused on the water/steam circuit, the combustion chamber

and the coal mills. It’s based on a real 550 MW power plant (Rostock), and it was develop using a

non-commercial Modelica library ThermoPower [10].

Another case found is the ”modelling and control of a supercritical coal fired boiler”, where it is

applied the coordinated control system to control the steam generation’s system [11].

By way of conclusion, the power plants have been the target of several modeling projects and the

most recent developments have been in the framework of CCS. The gross of the models done for

power plants are linked to the study of performances, but there is also some work done in dynamic

modelling with control to simulate shut-down, start-up and load changes.

1.3 Original Contributions

The thesis presents the modelling of a pulverized coal power plant and some of its units, using the

gPROMS as modelling program, a work never done before in this software. Besides that, the thesis

is inserted in an innovative project in the framework of CCS.

It was modeled some models that compose the power plant, which were connected together to

represent the real power plant. The main objective of this thesis is to simulate dynamic control and to

study the performance at different operational conditions (different loads, e.g.), something never done

before nor in the scope of the ETI-CCS project nor in gPROMS.

1.4 Thesis Outline

This thesis is organised in the following way.

It is presented, in the Chapter 2, the background on the subject, describing the pulverized coal

power plant and its equipments, as well as its control system. It was also done a brief description of

the CCS technologies. The next Chapter (3) consists in the mathematical description of the several

developed component models. In the chapter 4 is presented the main objective of the thesis. Here are

explained the flowsheet models for design, operational and control modes and submitted the results.

To finish this chapter it’s done some sensitivity analyses to the system. The conclusions and future

work are summarized in the 5.

4

2Background

Contents2.1 Pulverized Coal Power Plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62.2 Pulverized Coal Power Plant Control . . . . . . . . . . . . . . . . . . . . . . . . . . 212.3 Carbon Capture and Storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

5

2.1 Pulverized Coal Power Plant

Pulverized Coal Power Plant is a thermal power plant that uses the chemical energy of the coal to

produce electric energy. It starts by converting the chemical energy of the coal (heat of combustion)

into thermal energy (steam), then converts the thermal energy into mechanical energy (turbines’

rotation) and finishes producing electric energy in the generator using the mechanical energy [12].

The Pulverized Coal Power Plant is one of the most used methods to produce energy, and has the

following advantages [12]:

• High efficiency (table 2.1)

• Lower capital cost

• Adaptability to burn every types of coal

• Technologies to clean the flues gas are established

• Low consume of water (closed cycle minimizes the mass lost)

• Easy and reliable access to coal in many parts of the world

Energy efficiency (same as “net” efficiency) of a power plant is the useful work output over the heat

input. The heat input is the coal chemical heat and the useful work is the electrical power produced,

deducting the electrical power used (e.g., pumps and refrigerating tower). The thermal (or “gross”)

efficiency does not take into account the power spent for own use [6].

This type of power plant must have the following units (figure 2.1):

Figure 2.1: Pulverized Coal Power Plant blocs diagram [12].

Regarding the current technologies, the power plant can be subcritical, supercritical, advanced

supercritical or ultra supercritical. In the first case the steam conditions are bellow the critical point

(374°C and 220bar), while on the other three types of power plants the steam is above those condi-

tions. On the following table (2.1), it is presented the typical steam conditions, efficiencies and CO2

emissions for the four cases:

6

Table 2.1: Steam conditions in the different power plant critical types [6] [13] [14] [15].

Critical Type T (°C) p (bar) Efficiency LHV (%) gCO2/kWh

Subcritical 455 <220 38-40 900Supercritical 538-566 >220 40-42 740Ultra Supercritical (USC) 593-624 593-621 43-46 600Advanced Ultra Supercritical (AUSC) 700-760 375-380 >45 N/A

The turbine cycle efficiency is improved with high temperatures because this will reduce the coal

consumption, gas emissions and capture costs, which is especially important when CCS is applied.

However, the steam generator, turbine and piping system must be of nickel-based alloys materials,

and that’s why the supercritical power plant is the most used until now [13].

Another advantage of the advanced ultra supercritical power plants is the opportunity to apply

double reheat system, due to the high pressure steam. However, this idea is also in study for now.

Obviously, efficiency is dependent on other factors, and the coal type is an example. A plant

operating with high-moisture and high-ash coal can’t have the same efficiency of one using low-ash

and low-moisture coal. Carbon capture also decreases the efficiency (the penalty is 12%) [6]. The

progress in the ultra supercritical projects will be very important to allow the power plants to maintain

the efficiencies when the CCS is applied.

The heat integration cycle is also a key factor to improve the efficiency, because it interferes on

the coal and condenser utility consumes.

2.1.1 Steam Cycle

In figure 2.2 a typical flowsheet of the power plant steam cycle is represented . The steam draw-

offs from the turbines enter a heat transfer cycle, where their heat is integrated, and where they are

mixed to enter in the boiler as boiler feed water. The boiler feed water enters boiler to produce the

superheated steam, that is used in the High Pressure turbine. Furthermore, there is a reheat cycle

that consists of a recirculation of a high pressure exhaust steam (cold reheat steam) to the boiler

be heated into hot reheat steam, which is used in the Intermediate Pressure Turbine. Part of the IP

turbine last draw-off is used in the Lower Pressure turbine.

7

Figure 2.2: Steam cycle flowsheet [16].

There are some applicable types of steam cycles to the pulverized coal power plant. The basic

cycle is the Rankine cycle, with the following flowsheet and respective T-S diagram (figure 2.3):

Figure 2.3: Rankine cycle flowsheet and T-S diagram [17].

The ideal basic steps are:

• Isentropic expansion of superheat steam (3) in a turbine, decreasing its pressure and tempera-

ture (4).

• Condensation of the turbine’s exhaust steam (4) to saturation point (1).

• Isentropic Compression from low (1) to high pressure (2).

• Vaporization and heat of the high pressure liquid (2) at constant pressure in the boiler to super-

heat conditions (3).

It is better to apply this cycle in the power plant instead of the Carnot Cycle, because avoids water

8

in the pump and in the turbines (1 and 4).

When steam reheat (4 to 5) is added to the cycle, it is named Rankine cycle with reheat and

the main objective is to have the condenser at lower pressures avoiding, or reducing, liquid droplet

formation in the turbine (6 in spite of 4’). So, it is possible to achieve lower pressures in the last

turbine and produce more work. Although the thermal efficiency isn’t significantly increased because

the heat spent in the boiler will also increase. The flowsheet and its thermodynamic diagram for this

cycle is (figure 2.4):

Figure 2.4: Rankine cycle with reheat flowsheet and T-S diagram [17].

The regenerative cycle insertion (Regenerative Rankine Cycle) avoids the need to condensate all

the steam, saving energy in the condenser. This amount of saved energy is used to integrate the

draw-offs (draw-off 6 heats the condensate 2), heat the boiler feedwater (3) and use less coal in the

boiler. Because of the draw-offs, the work output is decreased but even this way the cycle thermal

efficiency increases, because the condenser cooling duty and the boiler coal flowrate are reduced.

Generally, the more feedwater heaters, the higher the efficiency. In figure 2.5 the flowsheet and T-S

diagram are represented.

Combined Reheat and Regenerative Rankine Cycle is the best and the most widely used cycle,

and is illustrated in the figure 2.6 .

In the steam turbines the inlet superheated steam (6) and the hot reheat steam (8) undergo

isentropic expansions that generate saturated or superheated steam (a, b). The last stage is an

exception, since the exhaust steam (9) may have a vapor fraction greater than 85-90% [18]. The

last turbine stage exhaust steam (9) is condensed in the condenser at constant pressure until the

saturation point (1), while the other draw-offs (a, b) are integrated with the condensate in the feedwater

heaters to heat the boiler feedwater (5). In this process, the isentropic compressions in the pumps

also takes place (2, 4). Both the superheat (6) and reheat steam (8) are heated at constant pressure

(5, 7 ), and are then sent to the expansion turbines.

It is in the condenser that the heat is removed(QL) using a cold fluid and the provided heat come

9

Figure 2.5: Regenerative Rankine cycle flowsheet and T-S diagram [17].

Figure 2.6: Combined reheat and regenerative Rankine cycle flowsheet and T-S diagram [17].

from the coal (QH ). There is also the work produced in the turbines (WT ), converted to electric power

in the generator, and the work spent in the pumps (WP1 and WP2).

2.1.1.A Boiler

The steam is generated in the boiler, using the heat generated by burning coal. In the most used

steam cycle (with regenerative and reheat cycles), superheated and hot reheat steam are generated,

which are high pressure and intermediate pressure steams, respectively [19].

Water Side

The superheated steam is produced by heating and boiling the boiler feed water above the sat-

uration temperature. The water-steam mixture comes from the boiler wall tubes and is separated in

a steam drum (partial steam generation), which consists of a large cylindrical vessel. The steam is

10

then heated in the superheater(s), and the water recirculates to the boiler tubes by natural or forced

circulation. The wall tubes increase the transfer heat and help to avoid the furnace material to high

temperatures.

In spite of a steam drum, the OTSG system can be used (”once-through steam generation”), which

has a coordinated control of the water flow and of heat input to assure that no water leaves with the

steam.

Futhermore, the boiler includes an economizer that pre-heats the boiler feed water, before entering

the boiler wall tubes, using waste heat that remained in the flue gas. This flue gas is typically between

180 and 260°C, and most of the economizers are able to raise the feedwater temperature from 11

to 17°C. The flue gas cooling is limited by the dew point, around 163°C, to avoid condensation and

formation of corrosive acids (mainly carbonic acid and sulfuric acid) [20].

The hot reheat steam is obtained by heating the cold reheat steam in the reheater. The super-

heaters and reheater consist of bundles of tubes, with steam passing inside the tubes and flue gas

passing outside, and the heat is transferred by convection.

Flue Gas Side

The boiler heat comes from the combustion of pulverized coal with air, in the furnace. In the

furnace, the flue gas evaporates the feedwater in the wall tubes, and then it passes to the convec-

tion zone, where the flue gas contacts with the superheaters, the reheater and the economizer heat

surfaces. When it leaves the boiler, it passes through the air pre-heater.

An important variable is the coal’s LHV (Lower Heating Value), that measures its specific combus-

tion energy.

In the furnace, pre-heated hot air and burners are used to burn the pulverized coal. The air is

classified as primary or secondary air. The primary air is 20-30% of the total air, and is used to dry

and pneumatically transport the coal to the burners, while the remaining air (secondary air) is directly

mixed in the burners with the coal/primary air mixture. To burn pulverized coal the type of furnace

used is a chamber fired furnace and the type of burners are chosen according to the conditions [12].

The following picture (figure 2.7) illustrates the influence of the excess air in the combustion pro-

cess.

11

Figure 2.7: Combustion gas concentrations at percent of the theoretical combustion air [20].

To a low quantity of air (below 100%) the combustion is not complete and that is why the CO level

is high, while when the theoretical air approximates 100%, the efficiency increases and the CO is

converted rapidly to CO2. However, the best level involves an excess of 15-20%, because the CO

reaches ppm level, which means an optimal efficiency. In this range, the CO2 level decreases due to

dilution in the excess air [20].

For excess levels from 25 to 45%, the NOx formation increases, and for higher levels the temper-

ature decreases and the NOx formation decreases [21].

In order to have a complete burn, the furnace must fulfill the following conditions [12]:

• The flame temperature must be enough to ignite the coal and air.

• The coal and the air must be thoroughly mixed.

• The needed residence time of the coal must be meet.

• The correct air fuel ratio must be achieved.

• The equipment must have means to hold and discharge the ash, discontinuously.

• The control system must be capable to regulate the coal feed flow.

The gross of the ash is removed in the bottom grate of the furnace and since it is too hot, it’s

common to quench it with water. The dust that remains in the flue gas after the dust collector is fly

ash, and is removed in the dust collector [12]. The unburnt carbon exits in the bottom ash, and may

be from 80 to 98%, depending on the residence time of the coal in the furnace [8].

2.1.1.B Governor Valve

The Governor Valve is a key unit to control the power plant, being located in the superheated steam

that leaves the boiler and goes to the first HP turbine stage. It operates the steam valve, adjusting

the flow according to the control objectives. Besides the steam flow, the pressure drop changes too,

which will modify the turbine rotor speed and, consequently, the power achieved.

12

This operation is a throttling process, since there occurs a pressure drop, the temperature de-

creases, but no energy change occurs (isenthalpic) [22].

2.1.1.C Steam Turbine

The steam turbine is an important equipment because it produces the mechanical energy.

There is usually a high pressure (HP), an intermediate pressure (IP) and a low pressure (LP)

steam turbine, each one with varied number of extraction points. The extraction points location is a

function of the power plant optimization, since it will change the work produced and the integrated

heat in the heat integration zone.

The force applied in the turbine is proportional to the change of the momentum, so the principle

of the turbine is to use the high velocity of the jet steam to impact the turbine’s curve blades and to

move them. The steam enters the turbine through a nozzle, where the pressure falls and is converted

into kinetic energy, resulting in a high velocity jet [12].

The turbine is designed to maintain the steam velocity and not to produce power, if the blade is

locked. On the other hand, if the blade is allowed to speed up the power increases and the outlet

velocity decreases due to the momentum change that caused the force. The power reaches the

maximum when the blade velocity is 50% of the steam velocity, at which the outlet velocity is near

zero. The turbine includes a row of nozzles, a row of moving blades and the casing (cylinder).

Nowadays, on the PCPP it’s always used single pressure and reheat turbines. The single pressure

is the most common (there is a single source of steam supply), and the reheat is used in the reheat

cycle (the steam is taken from, reheated and returned to the turbine). In terms of heat rejection,

regenerative and condensing turbines are used, the first to send draw-offs to the heat transfer cycle

and the second to be used on the last stage. The condensing turbine has its exhaust pressure fixed

by the condenser.

If there is a capture plant, intermediate pressure draw-off is usually sent to its reclaimer.

In an isentropic expansion there aren’t energy losses due to friction or other thermodynamic

losses, which means that the steam entropy doesn’t change. This is a good assumption to calcu-

late the ideal power (equation 2.1) [22]:

Wis = F (hin − his,out) (2.1)

To calculate the actual power, it’s used the isentropic efficiency, which relates the actual work with

the work obtained in the ideal case (equation 2.2)[22]:

ηis =Wreal

Wis=

hin − hout

hin − his,out(2.2)

2.1.1.D Generator

The generator is directly coupled to the steam turbine and converts the turbines’ rotating mechani-

cal power into electrical power to supply to the grid. The generator rotor is magnetized and its rotation

generates the electrical power in the generator stator.

13

2.1.1.E Heat Transfer Cycle

The heat transfer cycle has the simplified objective of mixing all the turbine steam draw-offs, in-

tegrating their heat, and sending the material to the boiler as boiler feed water. It’s also named the

regenerative cycle, and it was described in section 2.1.1 [23].

”Condensate” is the water leaving the condenser and passing through the low pressure feedwa-

ter heaters, while the water leaving the deaerator and passing through the high pressure feedwater

heaters is called ”boiler feedwater”. In most of the modern heat cycles there are feedwater heaters, a

condenser and a deaerator, which use extracted steam from the steam turbine.

The turbines’ draw-offs have different temperatures and pressures, due to the different outlet pres-

sure in each turbine stage. Because of this the draw-offs are used to heat the feedwater in different

feedwater heaters.

After the integration in the low pressure feedwater heaters line, the condensates are mixed in the

deaerator. The deaerator’s outlet is sent to the boiler, after being heated in the high pressure feedwa-

ter heaters line.

Condenser

The condenser is the single unit inside the heat integration cycle responsible of removing heat by

an external utility. The amount of heat duty is crucial to the power plant operation to allow the heat

integration and the draw-offs condensation in the consequents feedwater heaters, and that’s why the

saturated condensate pressure must be very low. The fact that the work output in the turbines and,

consequently, the power plant efficiency, increase with lower exhaust temperatures is also a reason

to lower the condenser pressure [12] [23] [24].

Usually the condensation heat removal is done using cooling water, and only in few occasions,

when water isn’t available, air is used as a cooler. If water is used it’s advantageous to have a cooling

water closed cycle to control water quality.

The most common condenser type is a tube and shell heat exchanger, with the water passing

through the tubes and the steam through the shell from the top downward, which is characterized

as a surface condenser. Some of the advantages of this type of condenser are the possibility to use

impure water because it doesn’t contact the condensate, to use to condensate as boiler feedwater and

to do high vacuum. Although it requires more space, the capital cost is larger and the maintenance

and running cost is high.

Another type of condenser is the jet condenser, which mixes directly the steam and the cooling

water.

Feedwater Heater

The number of feedwater heaters depends mainly on the size of the turbines, on the inlet and

exhaust steam conditions, on the overall plant size and on the economic considerations. Because the

number of feedwater heaters influences the heat integration, it plays a key role and must be part of

the design to optimize the plant efficiency [23].

14

The feedwater heater must have water passing through the cold side (tubes) and draw-off steam

passing for the hot side (shell), in counter current. Besides that, it can have one inlet as drains, which

is the draw-off steam condensate from other feedwater heater (with higher pressure steam). In this

case, the drain and the draw-off steam are mixed in the hot side, and the drain is vaporized due to the

pressure decrease.

In the feedwater heater the steam condensates in its chamber and the cold steam passes through

the tubes. Along the unit there are three main zones [25]:

• Desuperheating: cooling of the superheated steam to the saturation point.

• Condensing: energy from the steam/water mixture condensation is used to preheat the boiler

feedwater.

• Sub-cooling: used to capture additional energy from the liquid.

It is possible to exchange the heat mixing all the streams (”open” FWH). However, it’s not advan-

tageous because it will require another pump in the outlet.

In the shell side it must be maintained a liquid level that optimizes the heat transfer from the steam

to the boiler feedwater.

The performance of the feedwater heater can be evaluated measuring the feedwater temperature

rise, the terminal temperature difference (TTD) or the drain cooler approach (DCA). The first one is

the temperature increase in the cold side, while the second one is difference between the draw-off

steam saturation temperature and the cold side outlet temperature. DCA is the difference between

the drains and the inlet cold side temperatures.

Deaerator

The main Deaerator’s objective is to remove dissolved gases from the water, to avoid the ac-

cumulation due to gas leakage into the system. That’s important because, for example, the excess

oxygen and carbon dioxide increases the metal corrosion. To prevent corrosion (carbonic acid) volatile

neutralizing amines are usually used to adjust the pH. In order to remove oxygen sodium sulfite, Hy-

droquinone Hydrazine, Diethylhydroxyamine and/or Methyl ethyl ketoxime are used [20] [23] [24] [26]

[27].

Besides the gas removal, it’s also usual to remove the hard salts here. The hard salts deposit in the

surfaces (”scale”) and decrease the heat transfer quality in the heat exchangers, preventing and ad-

equate flow the tubes and forcing blowdown in the boiler. Calcium and magnesium bicarbonate form

an alkaline solution (”alkaline” hardness), and are easily removed by boiling (”temporary” hardness).

The most problematic are the calcium and magnesium sulfates, chlorides and nitrates (”non alkaline”

hardness) that must be removed with reagents (Polyphosphates and Sodium Meta Phosphate).

The secondary purposes of this unit are to accumulate water to feed the boiler (usually 5 minutes

of feedwater content), and to provide proper suction conditions for the boiler feed pump. It receives

the condensates to be treated, that come from the condenser and/or feedwater heaters, and a steam

stream (turbine or boiler draw-off). The deaerator is composed by three sections: the heat section,

15

the vent condenser and the storage section.

The gases are removed by two mechanisms that occur in the heating section.

• On the first one, the water is heated in the heater section, in direct contact with the steam. This

decreases gases solubility in water due to reduction of gas partial pressure in the gas phase;

• On the second mechanism, the water enters the deaerator head through a nozzle (spray type

deaerator) and contacts with the rising steam to increase the mass and heat transfer rate, in

order to remove the gases from the water to the steam, to achieve the saturation point and to

condensate the majority of the steam. The same principle can be achieved passing the water

through a set of layers in counter current with the steam (layer type deaerator).

In the vent condenser the incoming condensates pass through the tubes of a heat exchanger

mounted on the top of the deaerator to condensate part of the steam that escaped through the vent.

The heated and deaerated condensate, along with the condensate steam, falls to the storage section

located below the deaerator. This last section has the purpose of accumulating feedwater.

The steam that escapes with the gases is compensated with make-up water, which has to be ex-

ternally treated.

Pump

The pump is used to transport the water in the heat cycle. Usually it’s only needed one pump to

pump the condensate and another to pump to the feedwater, through the FWH tubes. This is not true

if there is any ”open” feedwater heater which requires a pump on its outlet.

Pumps increase the velocity, the pressure, the mechanical energy, or all of them. The most used

pumps are positive-displacement and centrifugal pumps. The first applies pressure by a reciprocating

piston or rotating member in a chamber, which is alternately filled and emptied of liquid. The centrifu-

gal one uses rotational high velocities and convert the kinetic energy into pressure energy. The work

delivered to the fluid is calculated from the mass flowrate and the head development (equation 2.3)

[28]:

Wfluid = F∆Hp (2.3)

Power supplied to the pump is calculated with the efficiency (equation 2.4) [28]:

Wreal =Wfluid

η(2.4)

The head comes from the Bernoulli equation and is(equation 2.5) [28]:

Hp =p

ρ+ gnz + α

v2

2(2.5)

The pumps represent a large fraction of the auxiliary power consumed in the plant, since their

flows are very big and the boiler feedwater pump pressure increase is from low to high pressures.

Water make-up [20]

Although the steam cycle is a closed cycle, there are material losses due to, for example:

16

• Boiler blowdown

• Deaerator steam vent losses

• Unreturned condensate (lost in the vacuum system)

• Leakage

Because of these losses a water make-up is performed in the condenser tank. This make-up water

must be chemically treated.

2.1.2 Flue Gas Treatment

The flue gas coming from the boiler is treated before being sent to the capture plant (with CCS)

or to the stack (without CCS). In the power plant, the ash, the NOx and the SO2 flue gas content are

all removed to a concentration below the limit. Ash is mainly coal’s non-combustible matter and is

partially removed in the bottom of the furnace (bottom ash). The ash leaving the furnace in the flue

gas is named fly ash.

SO2 emissions are due to the coal’s sulphur, while NOx appears from the air’s N2 combustion at

high temperatures. The first one can be controlled limiting the allowable sulphur content in the coal,

and the second one by manipulating the combustion.

The other major pollutants are CO2 and CO. The first is removed in the CCS process, while for

the second one the ammount is minimized by manipulating the combustion process. The carbon

monoxide in the flue gas must be in the range of 0 to 400 ppm, and is a measure of the combustion’s

efficiency.

For the flue gas treatment in the power plant side it is used a SCR (Selective Catalytic Reduction),

an ESP (Electrostatic Precipitator) and a FGD (Flue Gas Dessulfurizer). In the gas line there is

also an air heater, a gas-gas heater and a blower. The following picture (2.8) is an example of a

configuration of the flue gas treatment line.

Figure 2.8: Typical Flue Gas treatment line [19].

17

2.1.2.A Electrostatic precipitator

The flue gas that comes from the furnace has particulate matter that has as majority compo-

nent fly ash, which must be collected. To this end, a Electrostatic Precipitator (ESP), Fabric Filters

(Baghouses), mechanical collectors and venture scrubbers are employed. The most used is the dry

electrostatic precipitator [19].

Dry Electrostatic Precipitator

The ESP creates an electric field (between CEs - positive polarity - and DEs - negative polarity)

where the flue gas passes, and the particulates are electrically charged. The negatively charged ash

particles migrate toward the CEs. Depending on the particles size, the electrification may be easy to

perform and the flue gas velocity is a key factor to the particles have enough residence time to be

charged and collected. Plates are installed to collect the ash layer, and this particle layer must be

discontinuously removed (by raping) to prevent the ash to reenter in the flue gas. The ash falls from

the plates to hoppers.

2.1.2.B Selective Catalytic Reduction

Because the NOx contributes to acid rain and ozone formation and to health concerns and be-

cause the NOx emissions are very tied to combustion processes, the NOx must be removed from the

flue gas. SCR is the most effective process, allowing to reduce the levels by 90% or greater. The NOx

is converted into water vapor and nitrogen, in a catalytic gaseous reaction, reacting with ammonia.

The predominant reactions are [19]:

4NO + 4NH3 +O2 → 4N2 + 6H2O (2.6a)

NO +NO2 + 2NH3 → 2N2 + 3H2O (2.6b)

The flue gas NO content is much greater than the NO2 content, and the NO2 is preferentially

converted (greater selectivity to NO2 than to NO) [29] [30].

For a good operational performance it’s important to consider the factors:

• Reaction temperature range

• Residence time (space velocity)

• Degree of mixing between the reagent and the flue gas

• Catalyst activity, selectivity and deactivation

• Pressure drop across the catalyst

• NH3/NOx Stoichiometric ratio and ammonia slip

The reagents most commonly used (ammonia) are anhydrous ammonia, aqueous ammonia and

urea, being in all the cases diluted with air (95% of air), in a mixing chamber. The catalyst used can be

metal catalysts or zeolites. The most common is a mixture of TiO2, V2O5, WO2 and MoO3 (”titania -

18

vanadia”). Usually the reactor is a vertical vessel with fixed catalyst layers, but can also be a fluidized

bed.

The optimal temperature depends on the catalyst and on the flue gas composition, but for most

of the used catalyst (metal oxides) the optimum temperature is between 250 and 427°C. At tem-

peratures below the optimal range the activity is low, NOx is not efficiently removed and ammonia

passes through the SCR (ammonia slip). On the other hand, for temperatures above the optimum the

selectivity is limited and the catalyst is deactivated.

Depending on the localization of the unit, it can be called:

• Hot Side/High Dust: The NOx treatment is done between the boiler and the ESP, taking advan-

tage of the flue gas temperature

• Hot Side/Low Dust: In units with hot side ESP the SCR can be located between the ESP and

the air heater avoiding problems of the ash in the catalyst

• Cold Side/Low Dust: When the SCR is installed in retrofit and there is no other way, the SCR can

be installed between the air heater and the FGD. Because of the low temperatures, the unit must

include a method to increase the flue gas temperature: high pressure steam heat exchanger,

gas-to-gas air heater and / or duct burners. The advantage is that this conformation allows a

constant temperature when the boiler load changes, what makes the SCR control easier

2.1.2.C Air Pre - Heater

Because the temperature of the flue gas leaving the SCR is still quite high,the flue gas is cooled

in the air heater, where the air is pre-heated before entering the furnace. The air and the flue gas

exchange heat in counter current [20].

It’s also important to heat the air because it’s necessary to dry the coal and increases the boiler

efficiency. The most used is the regenerative type, which has a rotative cylinder that transfers heat

from the flue gas to the air. The major operating problem is the air leakage to the flue gas side that

is between 5 and 15%. Because the air passing through the boiler is fixed, the flue gas will increase

and with it the energy costs in the flue gas blower.

2.1.2.D Gas - Gas Heater

The gas-gas heater (GGH) is used to integrate the heat between the flue gas that enters and the

flue gas that exits the FGD unit, using the exothermic heat of the desulphurization reactions. It’s really

important to control the temperature entering the unit, because it’s a key variable.

2.1.2.E Flue Gas Desulfurization

Another important impurity to be removed from the flue gas is the SO2. This can be done either

by wet flue gas desulfurization (WFGD) or by dry flue gas desulfurization (DFGD), being the first one

the main technology (around 85% of installed capacity) [19].

The most used reagent in WFGD is limestone, but other alkaline reagents can be used. The

process can be non-regenerable or regenerable, with the difference of renewing the reagent and pro-

19

ducing a byproduct (e.g., elemental sulphur) in the second case. The most popular is the Limestone

forced oxidized (LSFO), which is a non-regenerable one.

Limestone forced oxidized (LSFO)

This process uses limestone as reagent and is composed of four steps: reagent preparation, SO2

absorption, slurry dewatering and final disposal.

The reagent is slurry of limestone and the unit to do the absorption and SO2 removal is an absorber

where the ascending gas reacts with the descending reagent slurry in perforated trays. Hydrociclones

and vacuum filters separate the water from the gypsum being possible to obtain a cake with 10%

moisture. The water can be reutilized to prepare the reagent stream.

In terms of chemistry, an acid-base reaction takes place in aqueous environment, forming mainly

calcium sulfate dehydrate (CaSO4.2H2O) and calcium sulfite hemi-hydrate (CaSO3.1/2 H2O), which

represent the gypsum.

2.1.2.F Blower

The blower compresses a gas in order to transport it through the downstream units, and it’s also

named fan. In the PCPP it is usual to have Forced Draft (FD) blower in the air stream that feeds the

furnace, while in the flue gas it’s often used an Induced Draft (ID) Blower. Typically the ID Fan controls

the furnace air flow and FD Fans controls the furnace pressure[19].

If the compression isn’t isothermal, the temperature rises, which has a number of disadvantages.

The work increases with the temperature and excessive temperatures lead to problems with materials

of constructions and lubricants. This temperature rise increases with the pressure ratio. However,

since the pressure ratio in blowers is typically small, the adiabatic temperature rise is not large and

no special provision is made.

Because the mechanical, kinetic and potential energies don’t change appreciably and assuming

that the compressor is frictionless, the ideal work can be calculated by (equation 2.7) [28]:

Wideal =

∫ pout

pin

dp

ρ(2.7)

To calculate the actual power it’s used the blower efficiency, which is between 80 and 85% to re-

ciprocating blowers and up to 90% to centrifugal blowers.

Isentropic compression

For ideal gases the relation between the density and the pressure between the inlet stream and a

general point is given by (equation 2.8) [28]:

p

ργ=pin

ργin(2.8)

20

Using the equations 2.8 and 2.7, the ideal isentropic work equation becomes (equation 2.9) [28]:

Wis =pinγ

(γ − 1)ρin

[(pout

pin

)1−1/γ

− 1

](2.9)

Isothermal compression

With complete cooling in order to maintain the temperature, the relation between the pressure and

density is (equation 2.10) [28]:p

ρ=pin

ρin(2.10)

Substituting the density into the equation 2.7 it’s obtained the isothermal work (equation 2.11)[28]:

Wiso =pin

ρinln

(pout

pin

)(2.11)

Polytropic compression

In large compressors the path of the fluid is between the isentropic and isothermal compression.

The relation between the density and pressure is (equation 2.12) [28]:

p

ρn=pin

ρnin(2.12)

With the polytropic index being (equation 2.13) [28]:

n =ln(pout/pin)

ln(ρout/ρin)(2.13)

The polytropic work equation is (equation 2.14) [28]:

Wpol =pinn

(n− 1)ρin

[(pout

pin

)1−1/n

− 1

](2.14)

For a blower it’s possible to have a pressure increase of 1bar [31]. Because the pressure increases

are low, there isn’t cooling and because of that the better compression to describe he blower is the

isentropic one.

2.2 Pulverized Coal Power Plant Control

Control strategies are vital for the power plant to be able to have a robust and quick response to the

energy demands, maintaining a high efficiency. It’s also very important to operate in safe conditions.

On the flue gas side control has the objective of maintaining the optimal conditions on the furnace

and of achieving the proper removal efficiency on the treatment units. However this side’s control isn’t

detailed in the thesis because it was only implemented control on the water cycle. For the steam cycle

a superficial study was carried out for all the systems and unites.

21

2.2.1 Boiler / Turbines System Control

The boiler and turbines must be controlled as a coordinated system, to optimally achieve the

power requirement, maintaining a stable pressure and temperature in the boiler. As the most popular

control modes there is the boiler-following control and the turbine-following control. There are also the

coordinated boiler turbine control and the integrated boiler turbine-generator control, which are more

complex control systems[19].

This system has the purpose to control the electric power and the superheated steam pressure

leaving the boiler, using for it the firing rate (coal flowrate valve) and the governor valve to manipulate

them.

2.2.1.A Boiler Following Control

In this mode the boiler responds to turbine operating changes. The power plant load demand is

responsibility of the throttle pressure control system, which changes the turbine valves’ positioning.

The changes in the valve(s) will change the boiler’s load that will be reposed by modifying the boiler

firing rate.

This system has the advantage of being quicker, but it’s more unstable. In fact, the boiler stored

energy allows to achieve rapidly the energy demand. However, the firing rate will take time to replace

the pressure in the boiler (the coal handling units have very slow dynamics), what will unsettle the

steam pressure and temperature.

2.2.1.B Turbine Following Control

In turbine following control the turbines follow the boiler control system. The energy load is accom-

plished by changing the firing rate in the boiler, while the boiler pressure is maintained by the throttle

pressure control system.

This operating mode is slower because the energy will be steadily changed in parallel with the

slow firing rate dynamic. However it has the advantage of stabilizing the boiler pressure because the

turbines will follow the slow firing rate changes, adjusting the valves to the load.

2.2.1.C Coordinated Boiler Turbine Control

This system combines the boiler following control and turbine following control in order to take

advantage of their advantages and minimize their problems.

2.2.1.D Integrated Boiler Turbine - Generator Control

The integrated boiler turbine-generator control controls several pairs of controlled inputs, using

ratio control.

22

2.2.2 Boiler Control

The steam outlet temperatures, the steam drum level and the boiling pressure (equivalent to the

superheat pressure) are controlled in the boiler. The temperatures and level controls are explained in

this chapter, while the pressure is controlled in the boiler/turbines system (section 2.2.1).

2.2.2.A Superheat and Reheat Steam Temperature Control

The steam temperature maintenance is also important, for example, for a safe and efficient op-

eration in the turbines. This variable is disturbed for the load changes, for example. To control the

temperature there are two distinct strategies: water side or gas side.[19] [32]

Water side control

In this strategy the operation consists in decreasing the steam temperature in a desuperheater

that can be located between two superheaters or in the last superheater outlet. Desuperheaters are

contact or spray type, while the attemperator is a non contact shell type heat exchanger.

There are the following options:

• Desuperheater - spraying cold water: injection water is used as manipulated variable to cool

the steam and control its temperature. The injection water is a draw from the main feedwater

stream, before it enters the economizer or before it enters the feedwater heaters.

• Attemperator - Diverting part of the steam: part of the superheated steam is diverted and cooled

in an attemperator. The amount of steam diverted is the manipulated variable, to control the

main stream temperature.

• Attemperator - Diverting part of the feedwater: part of the feedwater is diverted to an attemper-

ator where it cools the superheated steam, and controls its temperature.

For the water side one stage and two stages are possible. In the first case, a simple feedback

controller is applied, while for the two stages there are two controllers in series, one for each desu-

perheater. For large size boilers, it’s usual to split the total saturated steam, to control them with a two

stage system, and then join them together.

Fire side control

This methodology consists in changing the flue gas conditions, either the flowrate or the tempera-

ture. There are the following options:

• Excess air control: The excess percentage of air is manipulated in order to control the steam

temperature, changing the heat transfer. The heat transfer changes due to the combustion

efficiency dependence with the air.

• Flue gas by-pass control: with the flue gas by-pass it’s manipulated the quantity of flue gas

passing through the superheaters.

23

• Adjustable burner or burner tilting control: the burners are tilted up or down, changing the flue

gas temperature entering the superheater.

2.2.2.B Boiler Drum Level Control

One-Element Feedwater Control

In single element control, the level is controlled changing the water flow. The only measured

variable is the level and the controller is usually a proportional controller. This system performance is

affected by ”swell” and ”shrink” phenomena.[19] [33]

The ”swell” is the decrease of the density of the water/steam mixture in the drums, and is caused

by the increase of the steam flowrate which reduces the pressure. The ”shrink” is the opposite of

”swell”. These phenomena are problematic is when rapid steam demand change occurs, because

the level measurement will provide the contrary indication of the water flow demand. For example, if

the steam flowrate increases much, the water is supposed to increase. However, because the density

decreases (”swell”), the level may increase and the flowrate of water provided would be lower.

Due to this problem, this control system is usually only used in small boilers, where the load

changes are small.

Figure 2.9: One element feedwater control. [32]

Two-Element Feedwater Control

The two-element control uses the steam flowrate measurement in addition to the level measure-

ment, to avoid the ”swell” and ”shrink” problem. The two variables are usually controlled using feed-

forward-plus-feedback cascade control.

Variations in the steam flow will adapt the feedwater flow and the level is measured to changes

caused by discrepancies in the flows.

24

Figure 2.10: Two element feedwater control. [32]

Three-Element Feedwater Control

In the three-element control it’s measured the feedwater flowrate, in parallel with the level and the

steam flowrate. The steam flowrate is compared with the feedwater flowrate in order to equal both.

In this system it’s possible to change the water and steam speed, by changing the steam set point

Figure 2.11: Three element feedwater control. [32]

2.2.3 Heat Transfer Cycle Control

2.2.3.A Condenser Control

The crucial control is the pressure control because it will be the key factor to allow the integration

cycle and to fix the last turbine exhaust conditions. The cooling water flowrate acts as manipulated

variable [34] [35].

That’s also important to control the condenser tank level, in order to assure the condensate flow.

This control is done manipulating the make-up water feed to this tank.

2.2.3.B Feedwater Heater Control

The most important control aspect in the feedwater control is a precise and reliable level control to

all operating conditions. For example, if the level increases and the tubes become submerged, heat is

transferred to the condensate rather than the tubes, resulting in poor heating efficiency. On the other

side if the level decreases and there is no drain, steam blows through and the FWH doesn’t condense

the turbine draw-offs[36].

For this control, historically, it has been used mechanical displacement type level systems with

mechanically driven pneumatic controllers. To eliminate density problems, the drains’ temperature

can be measured and taken in account in this control system to eliminate the errors caused by density

variations [37].

25

2.2.3.C Deaerator Control

The most important variables to be controlled are the level and the pressure. The level control is

very important to ensure that the deaerator has a reserve capacity to the boiler, and the pressure is

fundamental to work in the right temperature range to efficiently remove the gases [34].

The major level disturbance is the variation of lost steam in the vent gases, and the control is done

adjusting the condensate flowrate coming from the condenser. The pressure is controlled manipulat-

ing the steam admitted to the deaerator. It’s usual to extract stream from another point or to decrease

the pressure’s set point, if the steam’s pressure is lower than the deaerator’s operating pressure. This

happens usually in part-load operations.

Besides that, it’s controlled the water chemistry to dosage the right quantity of the treatment

reagents.

2.3 Carbon Capture and Storage

CCS is composed by CO2 capture, compression, transportation and injection. The implementation

of CCS reduces the power output which leads to a negative effect on the power plant economical

efficiency of the project, because the same costs are spread over less energy. Although the most

important contribution to increase the efficiency comes from the power plant improvement, the carbon

capture technologies development is also very important [38] [39] [40].

For carbon capture in fossil power plants the main technologies are [5]:

• Post-combustion capture (PCC)

• Pre-combustion capture

• Oxy - combustion

The CO2 coming from capture is wet and has some contaminants. The first compression line

has typically three compressors with intercoolers and knock-out-drums between stages. The water is

condensed and removed in the knock-out-drums after cooling and compression. After these stages

the flue gas passes through a dehydrator, where the remaining moisture is removed. The water

removal is extremely important to avoid problems in the pipeline. In the second compression line the

CO2 is compressed to the pressure required.

CO2 transportation can be done by pipeline or by ship in the following conditions:

• Gas Phase

• Dense phase

• Supercritical Phase

The storage is usually done injecting the CO2 in geological storages at depths around 800m or

more, in oil and gas reservoirs or saline aquifers.

26

2.3.1 Post - Combustion

Post-combustion capture (PCC) can be implemented to newly designed plants or to retrofitted

power plants, and the absorption processes are the most advanced currently. In this technology CO2

is captured from the flue gas that comes from the combustion of the fossil fuel with air, like is shown

in the figure 2.12, after being submitted to treatments to remove the Ash (ESP), NOx (SCR) and SO2

(FGD).

Figure 2.12: Post-Combustion capture diagram [5].

There are three main types of capture in PCC: absorption, adsorption and membranes. These

three techologies are described in the subsections 2.3.1.A, 2.3.1.B and 2.3.1.C.

2.3.1.A Absorption

In the absorption methods the CO2 is captured into the bulk phase of another material, which

generally contains a reagent that selectively reacts with it. All the near-term PCC are absorption

based, using an absorber-stripper configuration (showed in figure 2.13). In almost all the cases it’s

used either aqueous pure amine or aqueous blend of amines as absorbent.

Figure 2.13: PCC’s absorption flowsheet [41].

The process consists of doing the absorption in a typical gas-liquid contactor, where the CO2 rich

solution leaves through the bottom and is pumped to the stripper (regenerator vessel). In the stripper

the CO2 is liberated by heating and the lean solution is recirculated to the absorber. The CO2 stream

goes to drying, compression and transportation.

27

The most common technology uses 30wt% aqueous monoethanolamine (MEA), which increases

the cost of electricity around 60-90%. New solvents are currently being investigated, to reduce the

regeneration energy that is the main contributor to the energy penalty. Generically, the PCC drops

the efficiency from about 38 to 27%.

All of the near-term technologies require SO2 concentrations no higher than 10ppm to minimize

solvent degradation.

2.3.1.B Adsorption

Adsorption consists in capturing the CO2 onto the surface of another material, passing the flue

gas through a packed or fluidized bed containing the adsorbent. To regenerate the adsorbent and

liberate the CO2 the pressure is lowered and/or the temperature is increased. In packed bed the flue

gas is diverted to a second vessel while the regeneration is done in the first one, while in fluidized

bed the sorbent is circulated between an absorber vessel and a regenerator vessel. This technology

has the advantage of requiring less energy to the regeneration, because the heat capacity from the

solid sorbent is lower than from the solvent. However there are potential disadvantages like particle

attrition, handling the sorbent and thermal management of the vessels.

This technology is still in kW range tests.

2.3.1.C Membranes

In this capture process the CO2 is selectively permeated through the membrane material. The

CO2 migration only occurs if its partial pressure is higher on the flue gas side than on the CO2 side,

what can be obtained by pressurizing the flue gas, applying vacuum on the other side, or both.

This technology has the potential to be a low energy process. However few data exists on mem-

brane systems for PCC and some issues are yet to be resolved at laboratory scale. The major

challenge is to avoid fouling on the membrane surface and the uncertainty of performance/cost of

large scaled vacuum pumps and compressors required in this operation.

2.3.2 Pre - Combustion

Pre-combustion appeared relatively recently and its main application is on gasification based

power plants, namely IGCC. Its objective is to convert the gas from gasification to hydrogen and

CO2 (water gas shift reaction) and to remove the CO2 from syngas before the combustion in the gas

turbine. On the following scheme (figure 2.14) it’s represented the application of pre-combustion in

IGCC. The efficiency penalty is around 7-8%.

28

Figure 2.14: Pre-Combustion capture diagram.

The capture is accomplished at high pressures in an acid gas removal (AGR) process that consists

in an absorption operation in a solvent, followed by regenerative stripping. The process be classified

in two types according to the solvent: chemical (section 2.3.2.A) and physical (section 2.3.2.B). A flow

diagram is shown in figure 2.15.

Figure 2.15: Pre-Combustion capture absorption flowsheet (AGR) [5].

The process is composed by two absorber/stripper sections, the first to remove a H2S rich stream

(sent to Claus Unit to recover elemental sulphur) and the second to remove CO2.

2.3.2.A Chemical Absorbents

Acid gases are removed by reacting with chemical absorbents (e.g., MDEA) and are released

by heating. These processes have, typically, lower capital costs but use more steam in the solvent

regeneration.

2.3.2.B Physical Absorbents

In this process the acid gases are removed by dissolution in physical absorbents (e.g., Selexol and

Rectisol processes) by increasing the pressure, and are removed from the solvent by increasing the

temperature or decreasing the pressure. The steam required is significantly lower than in chemical

absorbent processes.

29

2.3.2.C Other Options

Other options (not yet tested ate pilot plants) to remove the CO2 in pre-combustion capture are:

• Membrane separation of H2 and CO2

• Cryogenic processes

• Chilled ammonia

2.3.3 Oxy-combustion

In this technology (figure 2.16) it’s removed the nitrogen from the air to obtain a rich flue gas in

CO2. The flue gas CO2 content will be about 90% (dry basis), which makes the CO2 capture much

easier. If the regulations permit the CO2 can be stored after dehydratation, otherwise the impurities

(O2, N2, Ar, essentially) may be removed by cooling the flue gas to a temperature at which the CO2

condenses and the impurities do not.

Figure 2.16: Oxy-Combustion capture diagram [5].

The main components in the oxy-combustion are:

• Air Separation Unit (ASU): separates O2 from air by cryogenic distillation

• Combustion/Heat Transfer/Gas Quality Control system (GQCS): combustion products are cooled

to recover heat and clean fly ash. There may be also units to remove impurities, nearly the same

components for an air-fired plant.

One important operational mechanism is the flue gas recycle that consists in recirculating the

flue gas with oxygen to the combustor to simulate the combustion and heat transfer properties of the

air. With this technique it’s possible to use the design, control and operational knowledge in air fired

equipments.

From flue gas leaving the furnace, up to 80% is recycled and the net flue gas (not recycled) flowrate

is 20-25% of the normal air-fired systems. However the disadvantage is the fact of the concentration

of the impurities increases (SO2, HCl, HF, moisture, fly ash), unless GQCS are employed inside the

recycle loop to remove these components, which increases the costs because the flue gas flow is

greater inside that outside the recycle loop.

Fly ash is usually removed inside the loop, as well as SO2, which must be maintained below the

limit to avoid metal corrosion. Because the NOx production comes only from the fuel nitrogen SCR,

it’s unlikely to be needed, like in air-fired power plants.

30

2.3.4 Interaction with PCPP

In pulverized coal power plant the most used technology to remove CO2 from the flue gas is the

post-combustion capture, using absorption process with MEA. The following picture (2.17) represents

the integration of this technology on the power plant [5].

Figure 2.17: Interaction between MEA and PCC [38].

The orange boxes represent the additional items due to carbon capture, that represent the most

used capture process (absorption with MEA) and the CO2 compression line.

The Plant efficiency decreases from around 38 to 27%, with a coal parasitic load between 20 and

30%. The greater efficiency penalty in a PCPP when capture is added refers to the energy loss in

solvent regeneration and in CO2 compression. The energy losses in the regeneration are due to the

decrease of the work output, because of the steam losses in the stripper reboiler. On the other hand,

the auxiliary power increases significantly due to the electricity used to compress the CO2.

31

3Modelling PCPP components

Contents3.1 Deaerator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 343.2 SCR (Selective Catalytic Reduction) . . . . . . . . . . . . . . . . . . . . . . . . . . 363.3 Blower . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 423.4 Controller . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 453.5 Drum . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

32

In this chapter there are the models developed by the author of the thesis: Deaerator (3.1), SCR

(3.2), Blower (3.3), Controller (3.4) and Drum (3.5). All the models used to develop the final flowsheets

are summarized in the tables 4.8 and 4.2.

In the gCCS project a standard and organized methodology was followed to develop each model

the most reliably possible.

To begin, for the models where relevant information is needed, it’s done a background review

concerning the unit that the model represent, to understand the relationships that describe it and the

assumptions to make.

In the next phase it’s done a first scratch of the model, writing the equations, variables and pa-

rameters that express it. Knowing all the equations, variables and parameters it’s possible to do the

degrees of freedom, taking in account for it the model architecture, also done, to know what variables

are ”assigned” from the ports (inlet stream, e.g.).

After the DOF analysis it’s choosen the specification options, that are the variable(s) that the user

has to specify to solve the problem. For example, the specification may differ either if is being done

design or operation of the unit.

To finish the building phase it’s written the equations, variables and parameters and it’s done the

interface (ports that allow connecting the model with other ones), the specification dialog (interface

where the user does the specifications) and the report (interface where the user can see the simulation

results).

The next phase is the test and validation that is done running the models to a wide range of

conditions to debug the problems that may appear to make the model the most robust possible. It’s

also done a simulation to compare the results with real data.

In parallel with the model development, it’s created a Model Specification Document (MSD) that

describes all the model details.

An important detail on the models contruction are the variables on the connections. The material

gCCS connections ”transport” the stream’s mass flowrate, pressure, temperature, composition and

enthalpy, and these are the variables that are possible to import to the model and required to export to

the outlet connection. For example, if there is needed an inlet temperature it’s obtained directly from

the port or using a thermodynamics foreign object that relates the temperature with the pressure,

enthalpy and composition. This is why it’s equivalent to say that to solve a model is needed either the

temperature or the enthalpy, because with one of them the other is obtained.

In this chapter it’s described each model structure (inlet and outlet ports), also the degree of

freedom analysis and finally it’s shown the specification options. To do the DOF analysis there are

summarized the variables and the equations. A list of the parameters used in the equations is also

presented with their meaning.

In general all the model assumptions and special relations can be seen in the units description in

the chapter 2.1.

33

3.1 Deaerator

The Deaerator model is a steady-state model that assumes an adiabatic mixing of all inlet streams

(one steam and any number of boiler feedwaters), with the outlet boiler feedwater and bleed steam

streams at equilibrium and at saturation conditions, which determines the outlet temperature and

outlet pressure. The flowrate of the bleed stream is given by the bleed fraction.

gCCS doesn’t take account of oxygen and non-condensable gases in the water streams, what

means that there isn’t modelling of the deaeration operation.

The model calculates the ammount of inlet steam to maintain the required operating pressure or

calculates the operating pressure if the inlet steam mass flowrate is known.

Figure 3.1 shows the model icon and connectivity in gPROMS.

Figure 3.1: Deaerator model in gPROMS.

3.1.1 Inlets

• One array of UtilityFluid inlet ports representing the inlet boiler feedwaters (BFWs) to Deaerator.

• One UtilityFluid inlet port representing the inlet steam to Deaerator.

3.1.2 Outlets

• One UtilityFluid outlet port representing the outlet boiler feedwater (BFW ) from the Deaerator.

• One UtilityFluid outlet port representing the outlet bleed steam from the Deaerator.

• One ControlSignal outlet port representing the pressure measurement signal of the Deaerator.

3.1.3 Variables

Table 3.1: Variables of the Deaerator model.

Symbol Definition Units Array Size

F Steamin Mass flowrate of the inlet steam kg s−1 –

FBFW,jin Mass flowrate of inlet BFW j kg s−1 NBFW

in

F Steamout Mass flowrate of the outlet bleed steam kg s−1 –

FBFWout Mass flowrate of the outlet BFW kg s−1 –

T out Temperature of the outlet streams K –pSteam

in Pressure of the inlet steam Pa –Continued on next page

34

Table 3.1 – Continued


pBFW,jin Pressure of inlet BFW j Pa NBFW

in

pout Pressure of the outlet streams Pa –∆p Pressure drop Pa –hSteam

in Specific enthalpy of the inlet steam J kg−1 –hBFW,j

in Specific enthalpy of inlet BFW j J kg−1 NBFWin

hSteamout Specific enthalpy of the outlet bleed steam J kg−1 –hBFW

out Specific enthalpy of the outlet BFW J kg−1 –φbleed Bleed fraction – –

3.1.4 Equations

Overall mass balance for the Deaerator :

F Steamin +

NBFWin∑j=1

FBFW,jin = F Steam

out + FBFWout (3.1)

The Bleed Fraction equation calculates the bleed steam mass flowrate:

φbleed =F Steam

out

F Steamin

(3.2)

Energy Balance for the Deaerator :

F Steamin hSteam

in +

NBFWin∑j=1

[FBFW,jin hBFW,j

in ] = F Steamout hSteam

out + FBFWout hBFW

out (3.3)

The outlet specific enthalpies are calculated using a foreign object for water, with the assumption

that the outlets’ temperature and pressure are equal.

hSteamout = PhysProp.VapourEnthalpy(Tout, pout, 1) (3.4)

hBFWout = PhysProp.LiquidEnthalpy(Tout, pout, 1) (3.5)

Equilibrium equation to relate the pressure and temperature inside the Deaerator:

pout = PhysProp.DewPressure(Tout, 1) (3.6)

Relation between the outlet pressure and the pressure drop:

pout = minj

(pSteamin , pBFW,j

in )−∆p (3.7)

3.1.5 Degrees of freedom

The number of degree of freedom is calculated in table 3.2 by counting the number of variables

from the table 3.1 and the equations from the section 3.1.4.

Table 3.2: DOF analysis to the Deaerator model.

Number of variables Number of equations Degrees of freedom

11 + 3NBFWin 7 4 + 3NBFW

in

To solve the model the number of specifications must be equal to the DOF. The Deaerator model

will include the following obligatory specifications:

35

1. Inlet Steam : temperature (or specific enthalpy) and pressure.

2. Inlet BFWs : temperature (or specific enthalpy), pressure and mass flowrate.

3. Bleed Fraction.

Additional Specifications:

One of the following options for additional specifications must be also specified:

1. With pressure specified:

• Any one of: Deaerator ’s pressure or pressure drop.

2. With pressure calculated:

• Inlet Steam : mass flowrate.

3.2 SCR (Selective Catalytic Reduction)

The SCR model is a steady-state model to remove nitric oxide (NO) and nitrogen dioxide (NO2)

from the flue gas to a certain specification level of NOx or with a certain efficiency.

The model estimates the reagent stream requirements that can be in the form of Anhydrous Am-

monia, Aqueous Ammonia or Urea, and are always diluted with air.

The following reactions will take place in the model:

4NO + 4NH3 +O2 → 4N2 + 6H2O (3.8a)

NO +NO2 + 2NH3 → 2N2 + 3H2O (3.8b)

The model doesn’t take into account nor the reactions selectivity nor the kinetics, so some as-

sumptions had to be made.

The conversion is calculated based on the user performance specifications, and refers to the

ammount removed of nitric oxide and nitrogen dioxide (NOx). In basic mode, or can specify the outlet

NOx content in the outlet flue gas stream or the unit efficiency. In advanced mode the user specifies

the design temperature and the design efficiency, and the actual efficiency is calculated based on

the difference between the temperature and the design temperature, which causes a decrease in the

efficiency. In parallel, ammonia slip (ammonia in the outlet flue gas) occurs because the reagent

requirement is calculated based on the design efficiency.

First of all, because reaction 2 is faster than reaction 1, it is assumed that reaction 2 occurs first

and, consequently, reaction 1 only occurs if all NO2 is fully converted.

Because the typical flue gas has much more NO than NO2 and because in reaction 2 the stoi-

chiometric coefficients for NO and NO2 are both 1, it was assumed that if the quantity of NOx to be

removed is greater than the ammout of NOx to complete reaction 2, it is possible to consume all of

the NO2 in reaction 2 and then reaction 1 takes place.

Figure 3.2 shows the model icon and connectivity in gPROMS.

36

Figure 3.2: SCR model in gPROMS.

3.2.1 Inlets

• One ProcessFluid inlet port representing the flue gas inlet to the SCR.

3.2.2 Outlets

• One ProcessFluid outlet port representing the flue gas outlet from the SCR.

3.2.3 Parameters

The values and the meaning of the parameters used in the model equations are summarized in

table 3.3:

Table 3.3: Parameters used in the SCR model.

Parameter Definition Value Default units

∆hr1 Specific enthalpy change of reaction 1 -406868.0 J kg−1

∆hr2 Specific enthalpy change of reaction 2 -756720.9 J kg−1

Tstandard Standard temperature 298.15 Kpstandard Standard pressure 101325 PaA Parameter for design mode curve 0 –B Parameter for design mode curve -0.0396 –C Parameter for design mode curve 0.2044 –D Parameter for design mode curve - 0.75 –Γ1 Mole percentage of O2 in dry basis 21 %Γ2 Mole percentage of O2 in air 6 %ratioair,NH3 Air mole ratio in dilution of the ammonia stream 0.95 –xUreaNH3

Mole fraction of NH3 in urea ammonia solution 0.3 –xUreaCO2

Mole fraction of CO2 in urea ammonia solution 0.2 –xUreaH2O Mole fraction of H2O in urea ammonia solution 0.5 –xAqueousNH3

Mole fraction of NH3 in aqueous ammonia solution .2 –xAqueousH2O Mole fraction of H2O in aqueous ammonia solution .8 –ratioNOx,NH3

Excess of NH3 to NOx 1 –cb1 Curve Bound 1 -47.5 %cb2 Curve Bound 2 52.5 %νi,j Stoqueometric coefficient of component i in reaction j – –Mi Molecular Mass of component i Equation 3.46 g mol−1

Continued on next page

37



NC Number of compounds in the flue gas – –

3.2.4 Variables

Table 3.4: Variables of the SCR model.


Fin Mass flowrate of the inlet flue gas kg s−1 –Fout Mass flowrate of the outlet flue gas kg s−1 –FNH3 Mass flowrate of the ammonia stream kg s−1 –Tout Temperature of the outlet flue gas K –TNH3

Temperature of the ammonia stream K –pin Pressure of the inlet flue gas Pa –pout Pressure of the outlet flue gas Pa –pNH3

Pressure of the ammonia stream Pa –∆p Pressure drop Pa –win,i Mass fraction of the inlet flue gas - Cwout,i Mass fraction of the outlet flue gas - CwNH3,i Mass fraction of the ammonia stream - Cxout,i Mole fraction of the outlet flue gas - CxNH3,i Mole fraction of the ammonia stream - Chin Specific enthalpy of the inlet flue gas J kg−1 –hout Specific enthalpy of the outlet flue gas J kg−1 –hNH3

Specific enthalpy of the ammonia stream J kg−1 –η Removal efficiency % –wNOx

Mass fraction of NOx in the outlet flue gas - –xNOx Mole fraction of NOx in the outlet flue gas - –γNOx Concentration of NOx in the outlet flue gas mg Nm−3 –xdry

O2Mole fraction of O2 in the outlet flue gas (dry basis) - –

ρNout Normal density of the outlet flue gas kg m−3 –ηdesign Design NOx removal efficiency % –Tdesign Design Temperature K –ηdeviation NOx removal efficiency deviation to design % –Tdeviation Temperature deviation to design % –rdesign,1 Rate of reaction 1, at design conditions moles s−1 –rdesign,2 Rate of reaction 2, at design conditions moles s−1 –r1 Rate of reaction 1 moles s−1 –r2 Rate of reaction 2 moles s−1 –

3.2.5 Equations

The following two equations calculate the efficiency deviation (3.9) and the temperature deviation

(3.10), using the real and design temperatures and efficiencies.

ηdeviation =η − ηdesign

ηdesign100% (3.9)

Tdeviation =Tout − Tdesign

Tdesign100% (3.10)

There are two modes (Basic and Advanced) that differ in the use or not of the deviations to design

calculations.

38

Table 3.5: Case to distinguish modes in theSCR model.

CASE: sMode

Basic ηdeviation = 0 (3.11)

Advanced ηdeviation =

−100 if Tdeviation < cb1

AT 3deviation +BT 2

deviation + CTdeviation +D if cb1 ≤ Tdeviation ≤ cb2−100 if Tdeviation > cb2

(3.12)

The reaction rates are calculated for the two conditions (reaction 1 and 2 taking place, or only

reaction 2), depending on the flue gas content.

If the required amount of NOx to be consumed is greater than the amount needed to convert all

the NO2 in reaction 2, both reactions occur; otherwise only reaction 2 takes place. To express the first

condition the following ”if” condition is defined:

η

(win,NO

Mi,NO+win,NO2

MNO2

)> −[γNO,2 + γNO2,2]

win,NO2

MNO2

(3.13)

If the restriction 3.13 is fulfilled the equations to be used are:

Finwin,NO2

MNO2

+ γNO2,2r2 = 0 (3.14)

r2 = rdesign,2 (3.15)

ηFin

(win,NO

MNO+win,NO2

MNO2

)+ (γNO,1 + γNO2,1) r1 + (γNO,2 + γNO2,2) r2 = 0 (3.16)

ηdesignFin

(win,NO

MNO+win,NO2

MNO2

)+ (γNO,1 + γNO2,1) rdesign,1 + (γNO,2 + γNO2,2) r2 = 0 (3.17)

The equations mean that:

• Reaction 2 consumes all of the NO2, so its real rate is equal to the flow of NO2 in the flue gas

(3.14)

• The design rate of reaction 2 is equal to the actual rate because the reaction is complete (3.15).

• The design rate and actual rate of reaction 1 are calculated using the design and actual removal

efficiency (3.16 and 3.17).

Otherwise, if the restriction 3.13 is not fulfilled, the following equations are applied to calculate the

consumption rates:

r1 = 0 (3.18)

rdesign,1 = 0 (3.19)

ηFin

(win,NO

MNO+win,NO2

MNO2

)+ (γNO,2 + γNO2,2) r2 = 0 (3.20)

ηdesignFin

(win,NO

MNO+win,NO2

MNO2

)+ (γNO,2 + γNO2,2) rdesign,2 = 0 (3.21)

The equations for this case mean that:

39

• The reaction 1 does not take place (3.18 and 3.19).

• The design and actual rate of reaction 2 are calculated using the real and design removal effi-

ciency (3.20 and 3.21).

The Ammonia stream flowrate is calculated with the design consumptions, because the amount of

ammonia is based on ideal conditions, and taking into account the excess (ratioNOx,NH3):

FNH3wNH3,NH3 + (γNH3,1rdesign,1 + γNH3,2rdesign,2)MNH3ratioNOx,NH3 = 0 (3.22)

Mass balance for the SCR unit for each component i:

Finwin,i + FNH3wNH3,i + [γi,1r1 + γi,2r2]Mi = Foutwout,i (3.23)

Energy Balance for the SCR unit:

Finhin + FNH3hNH3

= Fouthout + (∆hr1γNO,1r1 + ∆hr2γNO,2r2)MNO (3.24)

Definition of the several specification types:

wout,NOx= wout,NO + wout,NO2

(3.25)

xout,NOx= xout,NO + xout,NO2

(3.26)

γout,NOx = wout,NOxρNout

Γ1 − Γ2

Γ1 − xdryout,O2

(3.27)

Calculation of the O2 concentration in dry air basis and of the normal density in outlet conditions,

needed in the outlet NOx definition of dry basis mass concentration:

xdryout,O2=

xout,O2

1− xout,H2O(3.28)

ρNout = PhysProp.VapourDensity(Tstandard, pstandard, w

out) (3.29)

Because all the ammonia streams options are diluted with air in the same proportions, it’s defined

the mole fraction of O2 and N2 in the ammonia stream for all the cases:

xNH3,N2= ratioair,NH3

(1− Γ1) (3.30)

xNH3,O2 = ratioair,NH3Γ1 (3.31)

The difference is on the other components, and that’s why there is a case for this in table 3.7.

40

Table 3.7: Case to distinguish ammonia types in the SCR model.

CASE: sNH3 type

AnhydrousxNH3,NH3

= 1− ratioair,NH3(3.32)

xNH3,i = 0,∀i /∈ {NH3, O2, N2} (3.33)

Aqueous

xNH3,NH3= (1− ratioair,NH3

)xAqueousNH3(3.34)

xNH3,H2O = (1− ratioair,NH3)xAqueousH2O

(3.35)

xNH3,i = 0,∀i /∈ {NH3, O2, N2, H2O} (3.36)

Urea

xNH3,NH3 = (1− ratioair,NH3)xUreaNH3(3.37)

xNH3,H2O = (1− ratioair,NH3)xUreaH2O (3.38)

xNH3,CO2 = (1− ratioair,NH3)xUreaCO2(3.39)

xNH3.i = 0,∀i /∈ {NH3, O2, N2, H2O,CO2} (3.40)

Conversion between molar and mass fractions for the ammonia and outlet flue gas streams:

wout,i = xout,iMi∑

i∈C (Mixout,i),∀i ∈ C (3.41)

wNH3,i = xNH3,iMi∑

i∈C (MixNH3,i),∀i ∈ C (3.42)

Total composition restriction: ∑i∈C

xout,i = 1 (3.43)

The specific enthalpies are calculated using the foreign object for the gases. The inlet flue gas

specific enthalpy is known from the port, while the outlet flue gas and ammonia specific enthalpies

are calculated by:

hNH3= PhysProp.VapourEnthalpy(TNH3

, pNH3, wNH3,i) (3.44)

hout = PhysProp.VapourEnthalpy(Tout, pout, wout,i) (3.45)

The Molecular Mass is important to convert compositions between mass and molar mass:

Mi = PhysProp.MolecularWeight (3.46)

Pressure drop equation to calculate the outlet pressure:

pout = pin −∆p (3.47)

3.2.6 Degrees of freedom

The number of degree of freedom is calculated in table 3.8, by counting the number of variables


41

Table 3.8: DOF analysis to the SCR model.


26+5 NC 19 + 4 NC 7 + NC

To solve the model the number of specifications must be equal to the DOF. The SCR model will

include the following obligatory specifications:

• Inlet flue gas : temperature (or specific enthalpy), pressure, mass flowrate and mass fraction.

• Ammonia stream : temperature and pressure.

• Pressure Drop in the unit.


One of the following options for additional specifications must be also specified:

• Basic mode:

– One of: NOx removal efficiency, outlet NOx mass fraction, outlet NOx mole fraction or

outlet NOx concentration (in dry basis).

– Temperature deviation is set to 0.

• Advanced mode:

– Design NOx efficiency.

– Design temperature.

3.3 Blower

The Blower model is a steady-state model of a one stage blower, and because there is no cooling

(small compression) it is modeled as isentropic (equivalent to adiabatic compression). So, to calculate

the power needed for the compression the isentropic efficiency and the ideal isentropic work are used.

The efficiency is specified by the user and has a default value of 85%, a value in the range of

centrifugal and reciprocating blowers. The user also specifies the pressure increase.

The model is also modelled to take in account the maximum pressure increment of a blower (1

atm) and calculates the temperature increase during the compression.

The model icon and connectivity in gPROMS is shown in figure 3.3.

42

Figure 3.3: Blower model in gPROMS.

3.3.1 Inlets

• One ProcessFluid inlet port representing the gas inlet to Blower.

3.3.2 Outlets

• One ProcessFluid outlet port representing the gas outlet from the Blower.

• One Power outlet port representing the Power of the Blower.

3.3.3 Parameters

The values and the meaning of the parameters used in the model equations are summarized in

table 3.9:

Table 3.9: Parameters used in theBlower model.


∆plim Pressure increment limit 101325 PaNC Number of compounds in the gas – –

3.3.4 Variables

Table 3.10: Variables of the Blower model.


F Mass flowrate of the gas kg s−1 –Tout Temperature of the outlet K –pin Pressure of the inlet Pa –pout Pressure of the outlet Pa –pratio Pressure ratio – –∆p Pressure increment Pa –ρin Density of the intlet kg m−3 –ρout Density of the outlet kg m−3 –


43



wi Mass fraction of the gas – Chin Specific enthalpy of the intlet J kg−1 –hout Specific enthalpy of the outlet J kg−1 –ηis Isentropic efficiency % –Pis Isentropic power demand W –P Actual power demand W –γ Isentropic index – –

3.3.5 Equations

Energy balance for the Blower :

Fhin + P = Fhout (3.48)

Calculation of the isentropic power and of the total power:

Pis = Fpinγ

(γ − 1)ρin

[(pout

pin

)1−1/γ

− 1

](3.49)

P =Pis

ηis(3.50)

Isentropic index equation:

γ =ln (pout/pin)

ln (ρout/ρin)(3.51)

Calculation of the outlet specific enthalpy and of the densities using a foreign object for gases:

hout = PhysProp.VapourEnthalpy(Tout, pout, w) (3.52)

ρin = PhysProp.VapourDensity(Tin, pin, w) (3.53)

ρout = PhysProp.VapourDensity(Tout, pout, w) (3.54)

Calculation of the pressure increment and of the pressure ratio, variables needed for the specifi-

cations:

pratio = pout/pin (3.55)

pout = pin + ∆p (3.56)

3.3.6 Degree of freedom



Table 3.11: DOF analysis to the Blower model.


14+ NC 9 5+ NC

To solve the model the number of specifications must be equal to the DOF. The Blower model will


44

1. Inlet gas : temperature (or specific enthalpy), pressure, mass fraction and mass flowrate.

2. Isentropic Efficiency.


The following options for additional specifications must be also specified:

• Any one of: outlet pressure, pressure increment and pressure ratio.

3.4 Controller

The Controller model is a generic PI controller that can receive any kind of measured variable and

send any kind of manipulated variable. This model may be transformed to a P controller.

It’s also important to note that this model is dynamic and that the control may be done automatically

(SP specified by the user in the model) or by cascade (SP specified by another unit).

Both the measured variable error and the manipulated variable are relative and this is done in

order to have a gain defined around 1 with a good performance, because it does not need to account

for the difference in order of magnitude between the measured and manipulated variables.

To assure that the controller output lays within the upper and lower bounds, an anti windup reset

algorithm is included in the model. If the bounds are violated, the time derivative of the integral error

is set to zero and the controller output is clipped to the bounds.

In this work, the controller model was adapted to proportional (level control) and proportional-

integral (power and pressure control) controllers . In the thesis it’s explained the generic PI controller,

and its adaptation to P because for the adapted controllers the differences are in small details, line

variable types and units and default values in the specification dialog.

It can be seen the model icon and connectivity in gPROMS in the figure 3.4.

Figure 3.4: Controller model in gPROMS.

3.4.1 Inlets

• One Controlsignal inlet port representing the measured variable.

• One Controlsignal inlet port representing the external set point.

3.4.2 Outlets

• One Controlsignal outlet port representing the manipulated variable.

45

3.4.3 Variables

Table 3.12: Variables of the Controller model.


K Controller gain – –τI Controller reset time s –B Controller Bias – –P Proportional Term – –∆I Integral Term Change s−1 –I Integral Term – –Dswt Anti wind up Switch – –ε Error – –SPI Internal Set Point – –SPE External Set Point – –SP User Set Point – –MV Measured variable – –MVMIN Minimum measured variable – –MVMAX Maximum measured variable – –OPMIN Minimum manipulated variable – –OPMAX Maximum manipulated variable – –OPC Calculated manipulated variable – –OPreal Real manipulated variable – –

3.4.4 Initial Conditions

For the PI controller, the initial integral term is equal to zero:

I(0) = 0 (3.57)

3.4.5 Equations

There is a selector to get the Set Point from either the user specification (3.58) or the external port

(3.59):

Table 3.13: Set Point assignment modes in the Controller model.

CASE: sSP

User SPI = SP (3.58)

External SPI = SPE (3.59)

The measured variable error, depending if the action is direct (3.60) or reverse (3.61), is given by:

Table 3.14: Action (Manipulated-Controlled) in the Controller model.

CASE: sAction

Direct ε(MVMAX −MVMIN) = SPI −MV (3.60)

Reverse ε(MVMAX −MVMIN) = −(SPI −MV ) (3.61)

46

For a proportional-integral Controller the control equation becomes:

OPC = K(P + I)(OPMAX −OPMIN) +B (3.62)

With the proportional term:

P = ε (3.63)

In order to integrate the error in the PI controlller it’s used the equation:

dI

dt=

ε

τI(3.64)

To a P Controller the integral term is set to zero:

I = 0 (3.65)

The real manipulated value is constrained by its maximum and minimum values:

OPreal = max[OPMIN,min(OPMAX, OPC)] (3.66)

The anti windup reset algorithm consits in a selector that turns off and on the integral action:

∆I =

{EτI

if OPMIN −Dsw > OP > OPMAX +Dsw

0 otherwise(3.67)




Table 3.15: DOF analysis to the Controller model.


18 9 9

To solve the model the number of specifications must be equal to the DOF. The Controller will


1. Measured variable : signal.

2. Controller:

• Action : direct or reverse.

• Controller parameters : gain, bias, maximum and minimum input and maximum and mini-

mum output.



1. Proportional Controller:

• External Set-Point mode:

47

– External Set-Point : signal .

– Controller parameters : integral term set to 0.

• User Set-Point mode:

– Controller : Set-Point.

– Controller parameters : integral term set to 0.

2. Proportional-plus-Integral Controller:

• External Set-Point mode:

– External Set-Point : signal.

– Controller parameters : reset time.

– StopIntegrator : active or inactive.

• User Set-Point mode:

– Controller : Set-Point.

– Controller parameters : reset time.

– StopIntegrator : active or inactive.

3.5 Drum

The Drum is a model to store an ammount of water to stabilize the system and to assure that there

is water to feed the downstream units.

The model represents a vertically-orientated closed tank and because of that there is a liquid-

vapor equilibrium at saturation conditions. The hydrostatic pressure of the liquid in the drum is used

to calculate the outlet pressure.

In the model it’s possible to do design mode to design the tank (design volume) giving the res-

idence time and the oversizing factor (volume occupation) or operational mode to fix the drum size

and to perform it at a desired level or residence time, with or without control. It’s a dynamic model

when in operational model and a steady-state model in design mode.

It can be seen the model icon and connectivity in gPROMS in figure 3.5.

Figure 3.5: Drum model in gPROMS.

48

3.5.1 Inlets

• One UtilityFluid port representing the inlet water to the Drum.

3.5.2 Outlets

• One UtilityFluid port representing the outlet water from the Drum.

• One ControlSignal port representing the level signal of the Drum.

3.5.3 Parameters

The values and meaning of the parameters used in the model equations are summarized in the

following table (3.16):

Table 3.16: Parameters used in the Drum model.


gn Gravitational constant 9.811 m s−2

ratioD,h Ratio Diameter/Height of the drum 1/3 –

3.5.4 Variables

Table 3.17: Variables of the Drum model.


Fin Mass flowrate of the inlet water kg s−1 –Fout Mass flowrate of the outlet water kg s−1 –Tout Temperature of the outlet water K –pin Pressure of the inlet water Pa –pout Pressure of the outlet water Pa –pDrum Pressure of the drum Pa –hin Specific enthalpy of the intlet water J kg−1 –hout Specific enthalpy of the outlet water J kg−1 –hL Specific enthalpy of the liquid phase in the drum J kg−1 –hV Specific enthalpy of the vapour phase in the drum J kg−1 –ρL Density of the liquid phase in the drum kg m−3 –ρV Density of the vapour phase in the drum kg m−3 –tR Residence time of the water in the drum s –VL Volume of the liquid phase in the drum m3 –Vdesign Total design volume of the the drum m3 –D Diameter of the the drum m –h Height of the the drum m –HL Liquid height (level) of the the drum m –M Total mass hold-up kg –ML Liquid mass hold-up kg –U Total energy hold-up J –OccL Percentage of volume occupation by the liquid % –

49

3.5.5 Initial Conditions

Since there are two differential equations (3.75 and 3.78), two initial conditions are required.

For design mode there is no dynamic, so the hold-ups don’t change. For this reason the initial

value for the hold-ups’ derivates are set to zero.

dM

dt(0) = 0 (3.68)

dU

dt(0) = 0 (3.69)

In operational mode it’s necessary to specify the initial values of:

• Liquid height.

• Any one of: Outler temperature or drum pressure.

3.5.6 Equations

The residence time equation calculates the residence time (in operational mode) or the liquid mass

hold-up (in design mode):

tRFout = ML (3.70)

To design the tank (design mode) the first step is to oversize it. In operational mode the equation

calculates the occupation by the liquid.

VdesignOccL100%

= VL (3.71)

The diameter and height of the drum area calculated with the volume equation for a cylinder and

the ratio between the two sizes:

Vdesign = hπD2

4(3.72)

D = hratioD,h (3.73)

The liquid mass hold-up is used to calculate the height of the liquid phase:

VL = hLπD2

4(3.74)

Mass balance for the drum with dynamics:

Fin = Fout +dM

dt(3.75)

The total mass hold-up is calculated summing the mass of the two phases:

M = VLρL + (Vdesign − VL)ρV (3.76)

And the liquid mass hold-up is calculated by the volume of liquid:

ML = VLρL (3.77)

50

Energy balance for the drum with dynamics:

Finhin = Fouthout +dU

dt(3.78)

The total energy hold-up is calculated summing the energy of the two phases:

U = VLρLhL + (Vdesign − VL)ρVhV (3.79)

The outlet pressure is taken with the hydrostatic pressure:

pout = pDrum + ρLgHL (3.80)

The mass densities, specific enthalpies and temperature-pressure equilibrium relation are calcu-

lated with the foreign object for the water:

ρV = PhysProp.VapourDensity(Tout, pDrum, 1) (3.81)

ρL = PhysProp.LiquidDensity(Tout, pDrum, 1) (3.82)

hV = PhysProp.VapourEnthalpy(Tout, pDrum, 1) (3.83)

hL = PhysProp.LiquidEnthalpy(Tout, pDrum, 1) (3.84)

hout = PhysProp.LiquidEnthalpy(Tout, pout, 1) (3.85)

Tout = PhysProp.DewTemperature(pDrum, 1) (3.86)


The number of degree of freedom is calculated in table 3.18m by counting the number of variables


Table 3.18: DOF analysis to the Drum model.


22 17 5

To solve the model the number of specifications must be equal to the DOF. The Drum will include

the following obligatory specifications:

1. Streams:

• Inlet water : temperature (or specific enthalpy) and pressure.

• Inlet or outlet water : mass flowrate.



1. Design mode:

• Residence time.

51

• Volume occupation.

2. Operational mode:

• Without level Control:

– Total volume.

– Residence time.

• With level Control:

– Total volume.

– Inlet or outlet water : mass flowrate (from control valve).

52

4Modelling a PCPP

Contents4.1 Design Mode . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 554.2 Operational Mode . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 604.3 Control Mode . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 614.4 Sensitivity Analyses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70

53

The main objective of the thesis is now addressed. This chapter describes the development of

a pulverized coal power plant flowsheet with control (and shown the respective results), that starts

with the design mode (4.1), passes to the operational mode (4.2) and finishes with the control mode

(4.3).Sensitivity analyses are done in the section 4.4.

The flowsheet models consist in connecting several models to represent the real power plant.

The bigger challenge is to study the whole system and its several recirculations in the steam cycle

to understand what to specify to do a correct simulation. For it, the author has to study, beyond his

own models, all the remaining needed models, developed by the gCCS team, and to do the DOF

analysis to the whole system. Except the tank and controller models (developed specially to the

control flowsheet), all the models are official models grabbed from the gCCS library.

Usually the development is done step by step that consists in putting the models one by one and

verifying that the results are the expected.

The steam cycle side was based on a subcritical power plant from now on referred to as Lawrence

[7], using the data from the steam cycle’s streams and the gross power output. So, from this source it

was possible to model all the steam cycle.

For the flue gas side, data from a report of a subcritical pulverized coal power plant were used,

referred to as Alstrom [8]. More precisely, the coal, air and boiler outlet flue gas composition and flow

were used. From this source were also used the efficiency and other key performance indicators to

compare with the results of the model. Since the Allstrom power plant has nearly the same conditions

in the boiler (appendixB) and the same number of feedwater heaters and turbine bleed steams, the

overlap its data with the Lawrence is justified.

The data used to create the model are in appendix B.

For the remaining equipment, essentially the flue gas treatment line (SCR, ESP, Blower, GGH

and FGD), was modelled taking into account the typical concentration limit of the NOX , Ash and SO2

in the flue gas sent to the stack, the typical pressure drops in the units and the typical compression

in the blower. The configuration that was adopted is similar to the one in figure 2.8, but with the air

heater inside the boiler and the SCR as cold side/high dust (2.1.2.B), because the boiler was created

this way [42].

The key models used and the units that they represent are in table 4.8.

Table 4.1: Key models used in the flowsheets.

Model Name Unit Chapter

BoilerSteamCondenser Condenser A.5BoilerSubcritical Boiler Subcritical A.1Deaerator Deaerator 3.1Drum Tank 3.5FeedWaterHeater Feedwater Heater A.6Generator Generator A.4GovernorValve Governor Valve A.2PumpUtility Pump A.7SteamTurbineStage Steam Turbine A.3Blower Blower 3.3


54



ElectrostaticPrecipitator Electrostatic Precipitator A.8FGD Flue Gas Desulfurization unit A.9GGH Gas-Gas Heater A.10SCR Selective Catalytic Reduction unit 3.2

In control mode the models presented in table 4.2 were used. Some other auxiliary models were

also used and are shown in table 4.3.

Table 4.2: Control models used in the flowsheets.


ControlValve Control Valve A.11PIDLevel Level P controller 3.4PIDPower Power PI controller 3.4PIDPressure Pressure PI controller 3.4

Table 4.3: Auxiliary models used in the flowsheets.

Model Name Unit

SourceAir Air SourceSourceCoal Coal SourceStack StackSinkWaste Ash SinkSourceUtility Water SourceJunctionUtility Water SplitterSinkUtility Water SinkRecycle breaker base utility –

A description of the models not developed by the author is presented in appendix A, including how

they have to be specified (specification dialog and ports) to understand how to connect them in the

flowsheet.

4.1 Design Mode

In design mode, the first step, since the equipment sizes were unknown, the power plant was

designed to the conditions of 100% load, at steady state conditions. The design is not detailed but is

representative (areas and efficiencies, e.g).

A detailed description of how the model was built is given in the section 4.1.1, and the important

results are presented and discussed in the section 4.1.2.

4.1.1 Model description

It’s represented the design flowsheet in gPROMS in figure 4.1.

55

Figure 4.1: Design flowsheet model in gPROMS.

56

The construction is done connecting the several models, but the major challenge is to specify the

model in the right way. Some important details to choose the right specifications are:

• The last turbine stage exhaust pressure is fixed by the pressure of the condenser, so there is an

extra equation that equates the two pressures.

• To specify the power plant energy production is equivalent to specify or the power produced or

the ammount of water that is needed as boiler feedwater.

For this flowsheet, the key specifications used in the key steam cycle models that compose the

flowsheet (inputs) are summarized in table 4.4.

Table 4.4: Key specifications in design mode.

Model Variables specified

Boiler Superheated and hot reheat temperatureSuperheated pressure and reheat pressure drop

HPTurbine1IPTurbine1IPTurbine2 Inlet design pressureLPTurbine1 Exhaust design temperatureLPTurbine2IPTurbine3IPTurbine4

IPTurbine5 Inlet design pressureExhaust vapour fraction

Heater1Heater2Heater3 Heated feedwater temperatureHeater4 Steam condensate temperatureHeater6Heater7

Condenser Condenser PressureMinimum temperature difference

DEA5 Deaerator pressure

Drum FW Residence timeDrum Codensate Volume occupation by the liquid

Pump FW Discharge pressurePump Condensate

RB FW Boiler Feedwater Mass Flowrate

Since the exhaust pressure of the last turbine stage is known, all the turbines (except the last

one) were specified in “design mode”, assigning the inlet design pressure and the outlet design tem-

perature. So, the turbines calculate the outlet temperature and the inlet pressure and the superheat

steam outlet pressure and the reheat steam pressure drop of the boiler are specified. The governor

valve is specified in “pressure known” mode because the inlet and outlet pressure are known, from

HPTurbine1 and Boiler.

The assigned temperature and pressure of the SH steam leaving the Boiler were calculated be-

fore, to match the conditions to enter in the HPTurbine1 after passing the GovernorValve, because

57

there is pressure and temperature drop in the valve, even when it is fully opened.

Analyzing again the turbines, the flow that passes through them is known because the boiler

feedwater flow (RB FW ) is specified and because the FWHs calculate the extraction steam. This is

because the feedwater heaters are specified in “design” mode with “steam flowrate calculated”. The

condenser is specified in “design” mode.

The Deaerator is specified in “pressure specified” mode, which also calculates the corresponding

extraction steam flowrate, and in the pumps it is specified the discharge pressure. The drum was

specified in ”design” mode with a typical residence time of 5 minutes.

Another important specification is on the last turbine stage, where, to achieve the correct gross

power, the vapour fraction was specified in spite of the outlet design temperature (”two phase” mode).

This was done because the gross efficiency was too low without condensation in the turbine. So,

the outlet vapour fraction was calculated by specifying the total gross power of the power plant. The

vapour fraction obtained was 95.24%, which is on safety conditions [18].

So, with these specifications all the pressures and temperatures are expected to be achieved,

except the pumps’ outlet temperatures and the outlet temperature of the LPTurbine5. Because the

vapour fraction in the last turbine was replaced by the gross power, this is expected to be achieved.

On the flue gas side, the correct variables in the boiler was assigned to satisfy the mass balance

in the furnace and, consequently, the flue gas composition. Some of the variables were: ash splitting

fraction, excess air and unburned carbon carried in the bottom ash. The boiler efficiency was also

specified with a typical value of 88.13%, the same efficiency of the Alstrom subcritical boiler.

4.1.2 Results and Discussion

Table 4.5 shows indicators of the deviation of the steam cycle’s conditions. The deviations are

relative, and for this specific case the reference is the Alstrom data from the literature.

Table 4.5: Average and maximum of the absolute stream deviations from Alstrom (relative deviation).

∆ T (K) ∆ p (%) ∆ F (%)

Average 0.03 0.00 0.49Maximum 0.87 0.00 4.01

As it can be noted in table 4.5 the very small deviations in the temperatures and pressures are as

expected. The flowrates have some deviations because they are calculated and the gCCS models

use a different tool to calculate the thermodynamic properties than that used by the Lawrence authors.

On the flue gas side it is important to show the flue gas composition deviations obtained, when

compared to Alstrom:

58

Table 4.6: Flue gas composition compared to Alstrom (relative deviation, in %).

Compound ∆ w (%)

CO2 -0.10N2 0.02H2O 0.30O2 0.00SO2 0.00Ash -0.19

Using the same coal and air conditions, the same flue gas composition was obtained (table 4.6),

which shows that the mass balance in the boiler is correct.

For the previous two analysis it’s proved that the model is representing adequately the conditions

wanted.

To evaluate the modelled power plant, the deviations in the key performance indicators are also

shown in table 4.7, compared with the Alstrom.

Table 4.7: gPROMS key performance indicators compared to Alstrom (relative deviation, in %).

KPI Deviation (%)

Gross Efficiency (% LHV) 3.07Net Efficiency (% LHV) 6.37CO2 emissions (g/kW.h) -2.39Boiler’s flue gas (g/kW.h) -1.47Coal comsumption (g/kW.h) -1.98Feedwater rate (g/kW.h) -7.32Coal/FW (kg/kg) 5.76

The modelled power plant has a higher efficiency compared with the Alstrom power plant, with a

value of 39.14%, which is well within the typical range for a subcritical power plant (table 2.1). The

difference in the efficiency is because the Lawrence steam cycle is better optimized than the Alstrom

one (steam extraction points, e.g.).

The difference in the net efficiency is greater than in the gross efficiency, since the model is

missing some auxiliary powers, namely for the coal handling and for the cooling water system, units

that weren’t modelled).

The others KPIs are lower because the efficiency is greater, which decreases the need of coal

and water circulating in the steam cycle per megawatt. The flue gas and CO2 emissions are related

to the coal consumption.

To better understand the dramatic difference in the feedwater flow it the ratio of ammount of coal to

ammount of water is calculated. Due to the greater value for the simulated power plant, it is concluded

that the heat transfer from the coal to the water in the boiler is 5.76% greater for the gPROMS case,

So, because the steam “transports” more energy it is expected a minor quantity need of water (-

7.32%).

Taking into account the problems in calculating the auxiliary power in the model, these KPIs indi-

cate that the modelled power plant is working using similar resources to the example of a real power

plant and gives a similar typical efficiency.

59

4.2 Operational Mode

In the Operational simulation mode the objective is to change the specifications to operational

mode, replacing some specifications with the design variables obtained in the design simulation. The

flowsheet is exactly the same as the used in design mode (figure 4.1) and the simulation refers, once

again, just to 100% load.

A brief description of the differences between the operational and the design model is done in the

section 4.2.1, and the model is validated in the section 4.2.2.


The model used is the same but with differences in the specifications that change the correspon-

dent model specification mode (in general changed from ”design” to ”operational” mode). In the

following table the specification differences are highlighted in bold.

Table 4.8: Key models used in the flowsheets.

Model Variables specified

HPTurbine1IPTurbine1IPTurbine2 Stodola’s coefficientLPTurbine1 EfficiencyLPTurbine2IPTurbine3IPTurbine4IPTurbine5

Heater1Heater2Heater3 Heat transfer areaHeater4 Terminal temperature differenceHeater6Heater7

Condenser Condenser PressureHeat transfer area

DEA5 Pressure drop

Drum FW Liquid levelDrum Codensate Design volumeRB FW –

Generator Gross power


The key results to validate this model are presented in this chapter.

The operational results match very closely the design ones, as expected. As an example, in the

following table are shown the deviations of the steam cycle’s streams compared to the design mode.

60

Table 4.9: Average and maximum of the absolute steam deviations from design (relative deviation).

∆ T (K) ∆ p (%) ∆ F (%)

Average 0.00 0.00 0.02Maximum 0.00 0.00 0.06

The results obtained validate the model and it may be developed and simulated in the control

mode.

4.3 Control Mode

In control mode, the objective is to implement the controls that are actually used in a real power

plant to achieve the 100% load conditions and to simulate load changes and disturbances in the plant,

in order to evaluate the performance of the control system and of the global power plant.

At first some set point changes are made in order to analyse the control of the boiler/turbine

system, tunning the controllers (4.3.1). Then an example of a daily cycle is presented (4.3.2.B) and

some disturbances in the coal’s LHV are done to see how the control system performs (4.3.2.C).

The description of the model used to perform the control simulations is presented in the section

4.3.1. All the control simulations are shown in the section 4.3.2.


The model includes the control of the boiler/turbine system, condenser and drums. With this sys-

tem the boiler superheated steam’s pressure, the power, the condenser pressure and the deaerator

tank’s level are controlled. The boiler following mode is used in subcritical boilers, because those boil-

ers have steam drums with high hold-ups that are advantageous for this kind of control: the governor

valve is opened and the energy and mass hold-up is immediatly utilised to quickly achieve the power

requirement.

Drums are used and controlled to represent the real power plant (the deaerator and condenser

have tanks) and to accomodate the disturbances that occur in the upstream units. Because the steam

cycle is closed (no make-up water) the control can not be done for the condenser drum. In fact, if the

deaerator drum level is at the set point the condenser drum will also be, because these two models

are the only ones in which the model accounts for hold-up.

The way control is done in the real power plant is described in the section 2.2.

On the other hand, for example, the level control of the feedwater heaters and boiler is not done

because they are steady-state models and therefore do not have hold-ups.

The deaerator’s pressure can not be maintained in part-load operations because the inlet steam’s

pressure decreases below the deaerator’s operating pressure. A real control was too complex to apply

because it takes steam from an extraction point with greater pressure if the normal one is not enough,

and this would interfere with the whole power plant and cause problems in the model. Besides that,

the set point should vary in a complex and coordinated way to avoid the deaerator’s temperature to

61

be above the temperatures in the higher pressure feedwater heaters in part-load (these temperatures

decrease), and forbid heat exchange.

Because of this, the pressure drop of the deaerator (difference between the steam and the deaera-

tor’s pressures) is assigned, giving the operating pressure. In the feedwater heaters the TTD (relation

between temperatures) is set. So, when decreasing the power all the system’s temperatures will

decrease parallelly to be possible to do all the heat integration.

Figure 4.2 shows the control flowsheet with the four controllers incorporated. All the controllers

are PI, except for the drum’s level controller where it’s used a P controller.

In terms of variable specifications, the location of the controlled variables is changed from the unit

models to the controllers. So, the parameters are tuned in order to obtain a typical response in the

system dynamics.

Figure 4.2: Control flowsheet model.


4.3.2.A Controller Calibration

In the first control simulation presented in the thesis, the objective is to adjust the control parame-

ters of the boiler/turbine system, around a typical value, to get a similar response to that expected for

boiler following control (figure 4.3).

This manual tuning had to be done because the models are steady-state, so the dynamics of the

responses are directly correlated to the controllers’ gains.

To represent the coal handling units dynamics, the power set point is changed with a ramp with a

typical rate of 4% of load per minute. This value was choosen because for a subcritical power plant it

is normal to ramp between 3 and 5% [43].

The single source found to help in the first guess for the parameters was a modelling study of

a supercritical power plant controlled by the coordinated control system [11]. Despite being a more

complex control system and a diferent power plant, this source was used to have an idea of a proper

reset time and gain for a system with similar dynamics in real life.

The reset time used in the two controllers (pressure and power) was equal to the literature and

the gain was adjusted, with the objective of choosing the most appropriate response. The response

62

Figure 4.3: Megawatt load change and throttle pressure deviation [19].

of the controlled variables, to a step change under different gains,are presented in figure 4.4.

Figure 4.4: Load and pressure responses to different tunings.

In the first test (gains equal to 0.015), the first plot of figure 4.4 shows that the response is not the

expected, since the power control is slow and the pressure control does not oscilate. Because of this,

the gain of the power controller is increased compared with the pressure one, to improve the power

control, relegating the pressure.

Analysing the other gains, it is concluded that when increasing the gain of the power controller,

the control of the load becomes better, following the set point ramp more quickly, with a much smaller

error. On the other hand, the pressure oscilates more. Since this type of control is known to be quick

in terms of power achievement (gets rapidly close to the set point) and unstable in terms of pressure

control, the increse of the power controler’s gain, as expected, seems to improve the similarities

between the simulation and the typical response.

The chosen parameters were the intermediate ones (gains of 0.01 and 0.2) because for a gain of

1 the pressure oscilation is larger (around -5% / 8.3 bar). Since the set point changes are expected

to be greater than 4%, the large pressure oscilation was taken into account.

63

Besides that, the stabilization time (time needed for the controlled variable converge within the

stabilization range of ± 0,5% - black lines in figure 4.4) for the chosen parameters is 4,2 and 5,5

minutes for the power and for the pressure, respectively, what is closer to the example in the figure

4.3 than the other case. The other parameters result in a stabilization time of 2,0 and 2,8 minutes,

which is too low.

Because the minimum allowable pressure in the boiler is not know, this tuning was not done taking

into account this condition. However, this is an imporant factor to consider and that is another reason

why the intermediate gain was choosen .

Analysing the dynamics in figure 4.4, can be seen that the responses are second order, which is

due to the controller dynamics and to the ramping in the power that “simulates” the dynamics in the

coal.

For the remaining controllers the respective tuning was done by trial and error. The final selected

parameters are:

Table 4.10: Parameters used in the control system.

Controller Gain Reset time (s)

Power 0.2 7.5Superheated pressure 0.01 7.5Tank level 10 –Condenser pressure 5 7.5

To prove that the control system is working, table 4.11 summarises the average and maximum

deviations of the control simulation, with the operational simulation as reference.

Table 4.11: Average and maximum of the absolute stream deviations from operational (relative deviation, in %).

∆ T (K) ∆ p (%) ∆ F (%)

Average 0.10 0.10 0.14Maximum 0.72 0.97 1.50

Analysing the previous table, the maximum deviations are high because the control system isn’t

perfect and the conditions, locally, may vary from the operational simulation. On the other hand,

because the average deviations are around 0.1% it’s concluded that the control flowsheet is well built

and that the control of the system has a good performance for the final steady-state conditions.

4.3.2.B Daily Cycle

The idea of the daily cycle is to simulate the operation of a pulverized coal power plant varying the

load along the day to match the power that the power plant is supposed to send to the grid. The set

point is changed, again, with a ramp with a rate of 4% of the load per minute.

PCPPs are base-load power plants, which means that they produce energy at a constant rate.

This means that the load of the plant does not change during the day to meet the grid responses,

because this task is responsability of the peaking power plants (typically gas turbine power plants).

However, a PCPP usually has two or three steps during the day to follow the grid load curve by

64

“distance”. The daily cycle was done adjusting the power plant load (green) to an example of grid

power (pink). The load steps were choosen as 85, 92.5 and 100%.

Figure 4.5: Grid and power plant’s load curves.

The key control variables of the boiler/turbine system, the boiler feedwater flow and the pressure

after the governor valve have the following responses during the daily cycle:

Figure 4.6: Power load and governor valve stem position.

Figure 4.7: Superheated steam pressure deviation from SP and coal flowrate deviation from 100% load .

65

Figure 4.8: Boiler feedwater flow and governor valve’s outlet pressure deviation from 100% load .

As expected, an increase in the power load opens the governor valve (figure 4.6) to increase

the flow and the pressure of the superheated steam to the first turbine (figure 4.8), which increase

the power produced in the turbines. As result, the turbine requires additional energy in the form of

superheated steam, and since the boiler is producing an energy level below the needed, the pressure

begins to drop (figure 4.7).

This energy need is compensated with the increase of the firing rate adjusting the coal flow, re-

turning the pressure to its set point - figure 4.7.

Obviously, all the rest of the system is now going to be affected because the boiler feedwater flow

and the governor valve pressure drop are now different.

To observe the effects on the rest of the system, more interesting variables are tracked: the

temperature of the heated feedwater and the steam flowrate in one feedwater heater (figure 4.9) and

the condenser pressure and the cooling water consumption (figure 4.10) .

Figure 4.9: Heated feedwater temperature and steam flow deviations from 100% load, in the Heater2.

Since the pressure of the superheated steam that enters HPTurbine1 increases with the load, the

temperatures and pressures of all the turbines’ exhaust steams increase as well. Because the heaters

and deaerator have, respectively, the TTDs and the pressure drop fixed, the temperatures increase in

the heat transfer zone, too. This is illustrated in figure 4.9. The steam flow also ramps up parallel to

66

the power and boiler feedwater flow.

Figure 4.10: Condenser’s pressure and cooling water flowrate deviations from 100% load.

As expected, the cooling water consumption decreases in part-load operations, because there is

less flow to be condensed, as can be seen in figure 4.10. The condenser pressure is well controlled,

with a positive peak due to the increase in the steam to condensate, when the power load increases.

The last controlled unit the Deaerator’s tank, being shown in figure 4.11 along with the level of the

condenser. The condensate valve’s stem position is also shown in figure 4.12.

Figure 4.11: Deaerator’s and condenser’s tank level deviations from SP.

First of all, the deaerator’s tank level is substantially disturbed by its outlet flow (boiler feedwater

flow) when the governor valve acts under load changes. The condenser’s tank is also disturbed by

the same phenomenon since its inlet flow is related to the governor valve position. So, an increase in

the load (and in the BFW flow) increases the level of the condenser’s tank and decreases the level in

the deaerator’s tank.

67

Figure 4.12: Condensate valve’s stem position.

It is also observed that the control of the deaerator’s tank is not perfect, and because of that the

deviation of the level from the set point in the condenser’s tank is not annulated too. The control isn’t

perfect because the controller is proportional and because of that it doesn’t eliminate the error that

was accumulate when the inlet flow and the outlet flow were different.

Finally, its concluded that the error that occurs during the load changes is “symmetric” and because

of that the level is the same in the two 85% load zones (at 0 and 24h). Since the tanks are the only

models where there is mass hold-up, the volume that one looses the other gains, and this explains

the symmetry between the two responses in figure 4.11.

As conclusion, to produce less energy, the flows, pressures and temperatures decrease across

the power plant. In addition, the deviations to 100% load are around the load change, for example, for

the boiler feedwater flow, for the governor valve outlet’s pressure and for the coal flow.

The effect of the load in the global system’s performance is analysed observing the key perfor-

mance indicators for the different loads. The 100% load KPIs are equal to those obtained in design

and operational mode and because of that they are not presented, while the part-load are presented

in deviation from the full-load KPIs (megawatt basis).

Table 4.12: Part-load key performance indicators compared to full-load (relative deviation, in %).

KPI Power Load

92.5 % 85 %

Gross Efficiency (%) -0.96 -1.98CO2 emissions (g/kW.h) 0.97 1.99Boiler’s flue gas (g/kW.h) 0.97 1.99Coal comsumption (g/kW.h) 0.97 1.99Feedwater rate (g/kW.h) 0.27 0.56Cooling water (g/kW.h) -5.05 -8.81Auxiliary Power (MW/MW) 0.38 0.85Boiler feedwater temperature (K) -0.78 -1.60

From table 4.12 it can be concluded that as the conditions deviate from full-load, the power plant

performance worsens and that is because the power plant works in conditions different from the ones

that designed the equipment (100% load). Two direct reasons are the decrease of the temperature of

68

the water to the boiler (the temperatures in the system decrease in part-load, as concluded before)

and the increase of the feedwater flow per MW, that will increase the ammount of coal needed per

MW.

In addition, the flows of coal and flue gas and the CO2 emissions decrease to produce less energy.

In terms of deviation, it’s almost symmetric to the efficiency deviation, because the coal changes to

directly counter the efficiency change.

The conclusion made for the coal (and flue gas and CO2) can not be extended to the feedwater

or to the cooling water because the conditions in the steam cycle, as shown in figure 4.9, change in

part-load operations, so the gross efficiency is not directly proportional to the water flows because the

system is extremely complex. Simplifying things, the feedwater flow per megawatt increases because

the steam used in the turbines has lower pressures in part-load, and the cooling water decreases

because the inlet streams to the condenser are colder.

The auxiliary power consumption per MW of gross power increases because the same happens to

the flows. The deviation (0.38 and 0.85%) is between the increase in the flue gas (0.97% and 1.99%)

and the increase in the feedwater (0.27% and 0.56%), because the power of the auxiliary units is

directly correlated with both of them.

4.3.2.C Disturbances

This chapter presents the responses for the cases of disturbances to the coal’s LHV in order to

see how the control system reacts to mantain the desired conditions if the coal quality changes. The

responses are analysed for the positive disturbances (+2.5 and +5%), since they are approximately

symmetric for the negative ones. The variables shown are of the boiler/turbine system (figures 4.13

and 4.14).

Figure 4.13: Power load and governor valve stem position.

69

Figure 4.14: Superheated steam pressure and coal flowrate deviations from 100% load.

An increase in theLHV of the coal, as expected, increases the power produced and the super-

heated steam pressure, as can be seen in figures 4.13 and 4.14. To counteract this disturbance, the

coal flow changes by roughly the same percentage as the LHV did, but in the opposite direaction,

and the governor valve acts while its controlled variable (boiler pressure) is not at the set point. By

the tim ethat the coal flow is correctly adjusted , the governor valve position has returned to the initial

value because all the conditions in the steam cycle are the same.

Basically, the control system adapts the coal to mantain the firing rate with the new LHV, and by

that time all the rest of the power plant returns to the previous conditions. The changes in the new

steady state occur only in the flue gas side (coal handling system, furnace and flue gas units), and

the control system has a good performance, since the controlled variables (boiler/turbine system)

stabilize at the set point, with the following errors (relative to the initial steady-state):

Table 4.13: Errors in the final steady-state (relative errors, in%).

Controlled variable LHV change

+5 % +2.5 % -5 % -2.5 %

Power Load 0.00 0.00 0.01 0.00Superheated steam pressure -0.01 0.00 0.00 0.00

4.4 Sensitivity Analyses

This chapter presents a sensitivity analysis on the power plant’s performances, analysing the KPIs.

It was changed the coal’s LHV (4.4.1) and the steam turbine’s efficiencies (4.4.2).

4.4.1 Heating Value of the Coal

The sensitivities are calculated using deviations in the LHV if the coal of -5, -2.5, +2.5 and +5%,

and the key performance indicators are presented in table 4.14, compared to the fulll load conditions

with the normal LHV.

70

Table 4.14: Key performance indicators compared to the normal LHV (relative deviation, in %).

KPI LHV change

+5 % +2.5 % -2.5 % -5 %

Gross Efficiency (%) 0.00 0.00 0.00 0.00Net Efficiency (%) 0.04 0.02 -0.02 -0.04CO2 emissions (g/kW.h) -4.76 -2.44 2.56 5.26Boiler’s flue gas (g/kW.h) -4.76 -2.44 2.56 5.26Coal comsumption (g/kW.h) -4.76 -2.44 2.56 5.26Feedwater rate (g/kW.h) 0.00 0.00 0.00 0.00Cooling water (g/kW.h) 0.00 0.00 0.00 0.00Auxiliary Power (MW) -1.04 -0.53 0.56 1.15Boiler feedwater temperature (K) 0.00 0.00 0.00 0.00

As it can be noted in the previous table a change in the LHV affects neither the gross efficiency

nor the boiler feedwater flow. The first of these is maintained because the power and the firing

rate remain approximately the same (the coal flow is adjusted according to its LHV ) and the second

because all the steam cycle conditions are maintained, which can be seen by the deviation in the

BFW temperature. The steam cycle conditions don’t change because the conditions of the steam

that leaves the boiler remain the same and because the only changes occur in the flue gas side, and

this explains the deviation of 0% in the cooling water flowrate per MW.

The coal, and consequently the flue gas and the CO2, vary aproximately the same percentage

of the LHV, with the opposite signal. This is because the firing rate is maintained (load and gross

efficiency do not vary) and because the firing rate is the coal flowrate times the emphLHVof the coal.

So if, for example, the LHV increases 5% the coal flowrate should be multiplied by a factor of -1/1.05

(-4,74%, in relative deviation), what really happens in the previous table.

The auxiliary power variations are, in this case, correlated to the flue gas flow, and that is why the

deviations are greater when the deviations on the flue gas increase. Obviously, the decrease in the

auxiliary power increases the net efficiency.

4.4.2 Steam Turbine’s Efficiency

Changes of -2, -1, +1 and +2% in the efficiency of all the turbines were implemented.

The power plant’s aging, naturally, affects its performance. During the power plant’s time the

equipment efficiencies tend to decrease, and because of this the turbine’s efficiencies were reduced to

study their influence on the overall system performance. The same studies were done for increases in

the efficiencies to take into account the development of the technologies and materials of the turbines.

The KPIs obtained are presented in table 4.15.

71

Table 4.15: Key performance indicators compared to the normal efficiency (relative deviation, in%).

KPI Efficiency change

+2 % +1 % -1 % -2 %

Gross Efficiency (%) 0.61 0.31 -0.56 -1.13CO2 emissions (g/kW.h) -0.60 -0.31 0.57 1.14Boiler’s flue gas (g/kW.h) -0.60 -0.31 0.57 1.14Coal comsumption (g/kW.h) -0.60 -0.31 0.57 1.14Feedwater rate (g/kW.h) -0.95 -0.48 0.77 1.55Cooling water (g/kW.h) -2.34 -1.20 2.26 4.62Auxiliary Power (MW) -0.86 -0.44 0.72 1.45Boiler feedwater temperature (K) -0.11 -0.06 0.08 0.17

When the efficiency increases the temperatures in the turbines and, consequently, in the heat in-

tegration zone decrease, as shown by the BFW ’s temperature. In fact, when the efficiency is greater

the enthalpy of the inlet steam to the turbine is further exploited, decreasing more the exhaust tem-

perature. The opposite happens with reduced efficiencies. Another phenomenon is the governor

valve’s action in the pressures of the system. For a higher efficiency the governor valve closes and

the pressures in the turbines decrease.

For a certain increase in the turbine’s efficiency it is confirmed that the global efficiency increase,

because less steam circulating is required, and consequently less coal, to achieve the same power.

The flue gas flow and CO2 emissions have once again a deviation equal to the coal because the

excess air is the same.

The cooling water consumption per MW is also correlated to the temperature variations. For ex-

ample, it increases in response to negative disturbances because the temperatures of the condenser

inlets are greater.

The effect of the deviation on the auxiliary power is consistently between the flue gas and the

water deviations.

The differences in the KPIs are not symmetric between positive and negative deviations because

the energy production is differently affected either if the pressure in the turbines increases or if it

decreases, since the steam conditions vary in different proportions.

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5Conclusions and Future Work

Contents5.1 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 745.2 Future Work . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75

73

5.1 Conclusions

The main objective of this work is to develop a model of a subcritical pulverized coal power plant,

to integrate with all the CCS chain in the future. Dynamic studies were performed to this power plant.

Additionally, the power plant’s performance under different operational conditions was analysed.

The steam cycle and the flue gas side are based on information obtained from the literature [7] [8],

and the gCCS current library is used to build the compound model that represents the power plant.

As additional work, some models that were missing were developed and added to the library.

For full-load operations, the simulated power plant has a gross power output of 769.9 MW, resulting

in a net power of 742.8 MW. Using a subcritical boiler with a typical efficiency of 88.1% [8], the gross

efficiency obtained was 39.6 %. There are no data in the literature for the gross efficiency of the

modelled power plant, but the value is in the typical range (38-40%). The boiler feedwater flow is

2839.8g/kWh.

In terms of the flue gas side, the power plant emits 828.25 g CO2 /kW.h to the atmosphere, a

typical value without capture. This flue gas sent to the stack has a concentration of 20 mg/Nm3 of

ash and 200 mg/Nm3 of SO2 and has no NOx, since the furnace does not produce NOx in the boiler

model. The flue gas emisson is 3870.6 g /kW.h and the coal consumption is 357.3 g /kW.h. The

deviations from the data reported in the literature (Allstrom) are -2.4, -1.5 and -2.0% for the CO2, flue

gas and coal, respectively. Both the flue gas and CO2 emissions and coal consumption are less than

the example used from the literature, because the efficiency is greater, which reduces the material

used per MW.

It is concluded that for part-load conditions the gross efficiency decreases, which indicates that

a pulverized coal power plant should work on the maximum load whenever possible. The gross ef-

ficiency is 39.2 and 38.8% for 92.2 and 85 % load, respectively, and the specific CO2 emissions

increased 1 and 2% (relative to 100% load) to 836.3 and 844.7 g/kWh. The coal consumption in-

creased to 360.8 and 364.5 g/kWh and the flue gas emissions to 3908.1 and 3947.8 g/kWh, the same

relative percentage than for the coal, because the CO2 is direcly correlated with the coal and flue

gas, since the flue gas composition is constant. This efficiency penalty is due to the boiler feedwater

temperature decrease, which increases the coal needed per MW.

For a coal with higher LHV, the gross efficiency is not affected, because the same firing rate is

needed per gross power. In terms of net efficiency, the “real” efficiency to consider from the optimiza-

tion point of view, a coal with a higher LHV improves the power plant, because the coal and flue gas

quantities to handle, and consequently the auxiliary power, are lower. For an increase of 2.5 and 5%

in the LHV, the flue gas (and CO2 emissions) and the coal consumption decrease 2.4 and 4.8%, ,

respectively.

On the other hand, upgrading the steam turbine’s efficiencies increases both the gross and the

net efficiency, because the resources in the steam cycle and in the flue gas side are lower to produce

the same energy.

For example, for an efficiency increase of 2% in the turbines, the gross efficiency increases 0.6%,

74

and for a decrease of 2% the penalty is around 1.1%. For the net efficiency, the advantage of a

turbine system with higher efficiency will be greater because it accounts for the energy savings in

all the auxiliary units. In fact, in the flue gas side the emissions change by -0.6 and +1.1% for each

case, and in the steam cycle the boiler feedwater varies -1.0 and +1.6. It is also concluded that the

improvement (for +2%) is lower than the penalty (for -2%) because the temperatures and pressures

in the system vary differently with the turbine efficiencies.

The sensitivity analyses show that the power plant performance is upgraded using a coal with

higher LHV and with more efficient turbines. However, only an optimization study can answer whether

the performance increase by the coal and turbinesis eventually beneficial, because there are some

implications such as:

• The coal flow per MW is lower but its cost increases with the LHV.

• The investment in the steam turbines increases with increasing turbine efficiency.

• The lower flows in the system decrease the units size and, consequently, the power plant cost.

In terms of control, it’s concluded that changing the load at a rate of 4% per minute, the control ap-

plied to the models has a similar performance when compared to the literature, with quick responses

and small errors.

One limitation of the work is the accuracy of the auxiliary power, and that’s why no values of net

efficiencies are provided in the conclusions.

Since the library models were all steady-state models, the control study is not reliable enought to

draw strong conclusions.From the control point of view this is the main limitation. For example, the

coal dynamics should be appplied because it has very slow dynamics, due to the fuel pulverization in

the mill.

These two limitations could be improved in future work.

5.2 Future Work

There are some details to be taken into account in order to improve the work done in the scope of

this thesis.

Since the gCCS project is at an early stage, the library used to develop the PCPP is in its first

version. Because of this, several issues could be changed in the models, so as to improve the final

conclusions. Actually, a lot of effort and time was spent testing the newly finished models and ensuring

they work together, and because of that some simplifications were made to the models.

As already concluded, the main issue in terms of control is the implementation of dynamics in

some models to improve the reliability of the dynamic responses, and to allow to be used all the

controls and operations that are practiced in the real power plant.

As an example, the implementation of dynamics in the deaerator and in the feedwater heater

would calculate the pressure according to the mass and energy hold-up in the equipment. The hold-

75

up would allow to control the level of these units, and the pressure would enable the equipment to

operate in “pressure-driven” mode, like in the real power plant.

On the other hand, boiler and coal handling units dynamics would also be an important step. This

improvement would allow to analyse the different boiler/turbine system control modes correctly, since

the main difference between them is the fast or slow use of the stored energy and mass in the steam

drum.

Another important improvement would be the insertion of leakage in the steam cycle to turn it into

an open cycle with make-up control.

The models could also be, in general, more detailed to improve the accuracy of the results. As

examples, the feedwater heater should take in account the different zones of heat exchange and

calculate accurately the overall heat transfer coefficient, and the deaerator should be modeled taking

into account the three Rdifferent zones that compose it. The boiler’s furnace should produce NOx

during the combustion, to be removed in the SCR, and to take in account the power consumption of

this removal.

Another important issue is the modelling of other units that would improve both the control and the

power plant performance studies. For example, the modelling of the cooling water and coal systems

would improve the veracity of the auxiliary power calculation to study the power plant’s performance

more accurately, while the modelling of the attemperators in the boiler model would permit control of

both the RH and the SH temperatures.

Connecting the entire CCS chain would be the perfect final step, sending the flue gas to the

capture plant to remove the CO2 before being set to the stack. With this tool, it would be possible to

study the performance of the power plant with capture, and to control all the CCS components.

An optimization of the power plant would be also an interesting work to be done in the future, when

the models allow sizing the most relevant units.

76

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August 2012.

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79

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29th August 2012.

80

AgCCS Model Library

A-1

A.1 BoilerSubcritical

The coal flowrate can be specified or not. If so, it will replace one of the water side specifications,

otherwise, all the water specifications must be given. Because the most used mode is the non-

specification of the coal flowrate, the specifications are explained for this case.

Figure A.1 shows the model icon and connectivity in gPROMS.

Figure A.1: BoilerSubcritical model in gPROMS.

A.1.1 Ports structure

The BoilerSubcritical has the following ports:

• One UtilityFluid inlet port representing the boiler feedwater to the BoilerSubcritical.

• One UtilityFluid inlet port representing the cold reheat steam to the BoilerSubcritical.

• One ProcessFluid inlet port representing the air to the BoilerSubcritical.

• One Coal inlet port representing the coal to the BoilerSubcritical.

• One UtilityFluid outlet port representing the superheat steam from to the BoilerSubcritical.

• One UtilityFluid outlet port representing the hot reheat steam from to the BoilerSubcritical.

• One ProcessFluid outlet port representing the flue gas from the BoilerSubcritical.

• One Coal outlet port representing the bottom ash from the BoilerSubcritical.

• One ControlSignal outlet port representing the superheat pressure measurement signal of the

BoilerSubcritical.

A.1.2 Ports specifications

The obligatory specifications in the ports are:

1. Feedwater - temperature.

2. Any one of:

• Feedwater - mass flowrate.

• Superheat steam - mass flowrate.

3. Cold reheat steam - temperature.

4. Any one of:

A-2

• Cold reheat steam - mass flowrate.

• Hot reheat steam - mass flowrate.

5. Air - Composition, temperature and pressure.

6. Coal - Temperature, composition and LHV (everything in the SourceCoal except mass flowrate).

Additional Specifications

The additional specifications depend on the pressure specification mode in the specification dia-

log:

1. Superheat and reheat steam pressure drop:

• Feedwater or superheat steam pressure.

• Cold reheat steam or hot reheat steam pressure.

2. Superheat and reheat steam outlet pressure:

• Feedwater pressure.

• Cold reheat steam pressure.

3. Superheat steam pressure drop and reheat steam outlet pressure:

• Feedwater or superheat steam pressure.

• Cold reheat steam pressure.

4. Superheat steam outlet pressure and reheat steam pressure drop:

• Feedwater pressure.

• Cold reheat steam or hot reheat steam pressure.

A.1.3 Specification Dialog

To better explain the specifications, the different tabs (”Boiler properties”, ”Steam Properties”, ”Air

heater properties” and ”Tramp air”) are separated.

Steam Properties

The user has to specify the following obligatory variables in the ”Steam Properties” tab:

1. Superheat steam - temperature.

2. Hot reheat steam - temperature.

The additional specifications depend on the pressure specification mode:

1. Superheat and reheat steam pressure drop.

2. Superheat and reheat steam outlet pressure.

3. Superheat steam pressure drop and reheat steam outlet pressure.

4. Superheat steam outlet pressure and reheat steam pressure drop.

Boiler Properties

The user has to specify the following obligatory variables in the ”Boiler Properties” tab:

1. Fraction of ash in the flue gas.

A-3

2. Fraction of carbon in the ash.

3. Pressure of the flue gas.

4. Temperature of the bottom ash.

5. Efficiency of the Boiler.

6. Any one of:

• Mass fraction of oxygen in the flue gas.

• Molar fraction of oxygen in dry flue gas.

• Excess of air.

Air heater properties

If the user chooses the have air heater in the boiler the following obligatory variables have to be

specified in the ”Air heater properties” tab:

1. Flue gas pressure drop.

2. Air pressure drop.

3. Air heater leakage fraction.

4. Air heater heat transfer efficiency.

5. Any one of:

• Heat exchanger effectiveness.

• Flue gas inlet temperature.

• Air outlet temperature.

Tramp air

The user has to specify the following obligatory variable in the ”Tramp air” tab:

1. Inlet tramp air fraction.

2. Tramp air temperature

3. Tramp air pressure.

A.2 GovernorValve


Figure A.2: GovernorValve model in gPROMS.

A-4


The GovernorValve has the following ports:

• One UtilityFluid inlet port representing the superheat steam inlet to the GovernorValve.

• One ControlSignal inlet port representing the stem position signal to the GovernorValve.

• One UtilityFluid outlet port representing the superheat steam outlet from the GovernorValve.



1. Inlet superheat steam - temperature.

2. Any one of:

• Inlet superheat steam - pressure.

• Outlet superheat steam - pressure.


1. Pressure drop known:

• Stem position specified:

– Inlet or outlet superheat steam - pressure.

• Stem position controlled:

– Inlet or outlet superheat steam - pressure.

– Inlet signal - stem position.

2. Specify flow coefficient:


– – .


– Inlet signal - stem position.

The additional specifications depend on the pressure specification mode in the specification dia-

log:


The user has to specify the following obligatory variables in the specification dialog:

1. Inherent characteristic.

Additional specifications

The additional specifications depend on the mode:

1. Pressure drop known:

A-5


– Stem position.


– –.

2. Specify flow coefficient:


– Stem position.

– Flow coefficient.


– Flow coefficient.

A.3 SteamTurbineStage


Figure A.3: SteamTurbineStage model in gPROMS.


The SteamTurbineStage has the following ports:

• One UtilityFluid inlet port representing the steam inlet to the SteamTurbineStage.

• One Power inlet port representing the mechanical power (1).

• One UtilityFluid outlet port representing the exhaust steam from the SteamTurbineStage.

• One Power bidirectional port representing the mechanical power (2).



1. Any one of:

• Inlet steam - mass flowrate.

• Exhaust steam - mass flowrate.

A-6


The additional specifications depend on the specification mode in the specification dialog:

1. Design Mode:

• Inlet temperature .

• Inlet or exhaust steam pressure (∗dialog).

2. Operational Mode:

• Any one of: Inlet temperature and exhaust temperature.

• Any one of: Inlet pressure and exhaust pressure.



1. Design Mode

• Inlet or exhaust design pressure (∗).

2. Operational Mode

• Isentropic efficiency.

• Stodola’s constant.


The additional specifications depend on the outlet phase:

1. Design Mode

• Vapour:

– Exhaust design temperature.

• Two phase:

– Exhaust vapour fraction.

A.4 Generator


Figure A.4: Generator model in gPROMS.

A-7


The Generator has the following ports:

• One Power inlet port representing the mechanical power to the Generator.

• One Control outlet port representing the electrical power from the Generator.



1. Mechanical Power



1. Efficiency.


The additional specifications depend on the power specification mode:

1. Power specified:

• Electrical Power.

2. Power non-specified:

• –.

A.5 BoilerSteamCondenser


Figure A.5: BoilerSteamCondenser model in gPROMS.


The BoilerSteamCondenser has the following ports:

• One array of UtilityFluid inlet ports representing the inlet steam to the BoilerSteamCondenser.

A-8

• One UtilityFluid inlet port representing the inlet cooling water to the BoilerSteamCondenser.

• One UtilityFluid outlet port representing the outlet steam condensate from the BoilerSteamCon-

denser.

• One UtilityFluid outlet port representing the cooling water return from the BoilerSteamCon-

denser.

• One Control outlet port representing the pressure measurement of the BoilerSteamCondenser.



1. Inlet Steam(s): Temperature, pressure and mass flowrate.

2. Inlet Cooling water: Temperature and pressure. Mass flowrate (∗dialog).



1. Overall heat transfer coefficient.

2. Cooling water pressure drop.


The additional specifications depend on the specification mode:

1. Condenser pressure:

• Design Mode:

– Condenser pressure.

– Any one of: Cooling water return temperature and minimum temperature difference.

• Operational Mode:

– Heat transfer area.

– Any one of: Condenser pressure, cooling water return temperature and minimum tem-

perature difference.

2. Cooling water flow known (∗):

• Design Mode:

– Condenser pressure.



A.6 FeedWaterHeater


A-9

Figure A.6: FeedWaterHeater model in gPROMS.


The FeedWaterHeater has the following ports:

• One UtilityFluid inlet port representing the inlet feedwater to the FeedWaterHeater.

• One UtilityFluid inlet port representing the inlet steam extracted from the Turbine.

• One array of UtilityFluid inlet ports representing the inlet drains to the FeedWaterHeater.

• One UtilityFluid outlet port representing the heated feed water from the FeedWaterHeater.

• One UtilityFluid outlet port representing the outlet steam condensate drain from the FeedWater-

Heater.



1. Inlet feedwater - temperature, pressure and mass flowrate.

2. Inlet drain - temperature, pressure and mass flowrate.

3. Inlet steam - temperature and pressure. Mass flowrate (∗dialog).



1. Overall heat transfer coefficient.

2. Pressure drop in the shell.

3. Pressure drop in the tubes.


The additional specifications depend on the specification mode:

1. With steam flowrate calculated:

• Design Mode:

– Any one of: Steam condensate temperature, drain cooler aproach and drain effective-

ness.

A-10

– Any one of: Heater feedwater temperature, terminal temperature difference and feed-

water temperature rise.



– Any one of: Drain cooler aproach, drain effectiveness,terminal temperature difference

and feedwater temperature rise.

2. With steam flowrate known (∗):

• Design Mode:

– Any one of:Steam condensate temperature, drain cooler aproach, drain effectiveness,

heater feedwater temperature, terminal temperature difference and feedwater temper-

ature rise.



A.7 PumpUtility


Figure A.7: PumpUtility model in gPROMS.


The PumpUtility has the following ports:

• One UtilityFluid inlet port representing the inlet water to the PumpUtility.

• One UtilityFluid outlet port representing the outlet water from the PumpUtility.

• One Power outlet port representing the electrical power from the PumpUtility.



1. Inlet - pressure and temperature.

2. Any one of:

A-11

• Inlet mass flowrate.

• Outlet mass flowrate.



1. Efficiency.

2. Discharge pressure.

A.8 ElectrostaticPrecipitator


Figure A.8: ESP model in gPROMS.


The ESP has the following ports:

• One ProcessFluid inlet port representing the inlet flue gas to the ESP.

• One ProcessFluid outlet port representing the outlet flue gas from the ESP.


The ports obligatory specifications are:

1. Inlet flue gas - Temperature, pressure, mass flowrate and composition.



1. Pressure drop.


The additional specifications depend on the performance specification mode:

1. Outlet ash concentration or removal efficiency.

A-12

A.9 FGD


Figure A.9: FGD model in gPROMS.


The FGD has the following ports:

• One ProcessFluid inlet port representing the inlet flue gas to the FGD.

• One ProcessFluid outlet port representing the outlet Flue gas from the FGD.



1. Inlet flue gas - Temperature, pressure, mass flowrate and composition.



1. Any one of:

• Pressure drop.

• Outlet pressure.

2. Any one of:

• Efficiency.

• Outlet SO2 mass fraction.

• Outlet SO2 mole fraction.

• Outlet SO2 concentration.

3. Limestone in slurry.



A-13

1. Basic Mode:

• –.

2. Advanced Mode:

• Molar ratio limestone/SO2 removed.

• Limestone purity.

• Slurry temperature.

• Solids content in gypsum

A.10 GGH


Figure A.10: GGH model in gPROMS.


The GGH has the following ports:

• One ProcessFluid inlet port representing the inlet cold gas to the GGH.

• One ProcessFluid inlet port representing the inlet hot gas to the GGH.

• One ProcessFluid outlet port representing the outlet cold gas from the GGH.

• One ProcessFluid outlet port representing the outlet hot gas from the GGH.



1. Inlet hot gas - Temperature, pressure and mass flowrate.

2. Inlet cold gas - Temperature, pressure and mass flowrate.



1. Hot gas pressure drop.

A-14

2. Cold gas pressure drop.


The additional specifications depend on the performance mode:

1. Any one of: Hot stream outlet temperature and heat duty.

A.11 ControlValve


Figure A.11: ControlValve model in gPROMS.


The ControlValve has the following ports:

• One UtilityFluid inlet port representing the inlet water or steam to the ControlValve.

• One ControlSignal inlet port representing the stemposition signal to the ControlValve.

• One UtilityFluid outlet port representing the outlet water ir steam to the ControlValve.



1. Inlet stream - Temperature and pressure.

2. Stem position.



1. Flow coefficient.

2. Maximum allowable flow across the valve.

3. Initial actual stem position (in dynamic mode).

4. Inherent characteristic.



A-15

1. Standart Mode:

• –.

2. Advanced Mode:

• Time constant.

• Leakage fraction.

• Flow exponent.

• Rangeability factor (only necessary in equal percentage inherent characteristic).

A-16

BSource data

B-1

Table B.1: Steam cycle data from Lawrence [7].

Stream T (K) P (bar) F (kg/s) Stream T (K) P (bar) F (kg/s)1 811.0 33.6 563.0 18 353.3 0.5 428.72 811.0 165.5 607.3 19 322.1 20.0 522.13 591.8 36.7 607.3 20 349.8 20.0 522.14 591.8 36.7 563.0 21 370.4 20.0 522.15 591.8 36.7 44.3 22 413.4 20.0 522.16 516.4 240.0 607.3 23 433.5 20.0 522.17 729.4 19.0 22.2 24 455.2 10.5 607.38 729.4 19.0 540.9 25 459.3 240.0 607.39 648.5 10.9 18.8 26 482.3 240.0 607.310 648.5 10.9 522.1 27 487.9 34.9 44.311 577.6 6.2 18.8 28 464.9 18.1 66.412 577.6 6.2 503.3 29 419.0 5.9 18.813 529.8 4.1 36.1 30 376.0 3.9 55.014 529.8 4.1 467.1 31 355.4 1.0 71.815 407.5 1.0 16.8 32 328.0 0.5 93.416 407.5 1.0 450.3 33 322.2 0.1 428.717 353.3 0.5 21.6 34 322.1 0.1 522.1

Figure B.1: Flowsheet of the modelled Pulverized Coal Power Plant’s Steam Cycle [7].

B-2

Table B.2: Key performance indicators from the Alstrom report [8].

KPI KPI

Gross Power (MW) 463.78Net Power (MW) 433.78Auxiliary Power (MW) 29.70Gross Efficiency (% LHV) 38.40Net Efficiency (% LHV) 35.90CO2 emissions (g/kW.h) 848.54Boiler’s flue gas (g/kW.h) 3928.31Coal comsumption (g/kW.h) 364.54Feedwater rate (g/kW.h) 3064.20Boiler efficiency (%) 88.13

Table B.3: Coal ultimate analysis from the Alstrom report [8].

Compound w (%)

C 63.2H 4.3N 1.3S 2.7O 7.1Moisture 10.1Ash 11.3

Table B.4: Flue gas composition from the Alstrom report [8].

Compound w (%)

CO2 21.42N2 69.10H2O 5.65O2 2.50SO2 0.50Ash 0.84

Table B.5: Boiler’s streams conditions from the Alstrom report [8].

Stream T (K) p (bar) F (kg/s)

Feedwater 529.25 218.2 394.5Superheated Steam 818.65 165.5 394.5Cold Reheat Steam 592.95 45.3 359.5Hot Reheat Steam 813.75 40.7 359.5

B-3

B-4

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