monte carlo simulation of pulverized coal-fired power plants ...

MONTE CARLO SIMULATION OF PULVERIZED COAL-FIRED POWER PLANTS:

EFFICIENCY IMPROVEMENT AND CO2 CAPTURE OPTIONS

A Thesis

Submitted to the Faculty of Graduate Studies and Research

In Partial Fulfillment of the Requirements

for the Degree of

Master of Applied Science

in Industrial Systems Engineering

University of Regina

by

Teerawat Sanpasertparnich

Regina, Saskatchewan

November, 2007

Copyright© 2007: T. Sanpasertparnich

Reproduced with permission of the copyright owner. Further reproduction prohibited without permission.

MONTE CARLO SIMULATION OF PULVERIZED COAL-FIRED POWER PLANTS:

EFFICIENCY IMPROVEMENT AND C 0 2 CAPTURE OPTIONS

A Thesis

Submitted to the Faculty o f Graduate Studies and Research

In Partial Fulfillment o f the Requirements

for the Degree o f

Master o f Applied Science

in Industrial Systems Engineering

University o f Regina

by

Teerawat Sanpasertpamich

Regina, Saskatchewan

November, 2007

Copyright© 2007: T. Sanpasertpamich


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1*1 Library and Archives Canada

Published Heritage Branch

395 Wellington Street Ottawa ON K1A0N4 Canada

Bibliotheque et Archives Canada

Direction du Patrimoine de I'edition

395, rue Wellington Ottawa ON K1A0N4 Canada

Your file Votre reference ISBN: 978-0-494-42361-5 Our file Notre reference ISBN: 978-0-494-42361-5

NOTICE:The author has granted a nonexclusive license allowing Library and Archives Canada to reproduce, publish, archive, preserve, conserve, communicate to the public by telecommunication or on the Internet, loan, distribute and sell theses worldwide, for commercial or noncommercial purposes, in microform, paper, electronic and/or any other formats.

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The author retains copyright ownership and moral rights in this thesis. Neither the thesis nor substantial extracts from it may be printed or otherwise reproduced without the author's permission.

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CanadaReproduced with permission of the copyright owner. Further reproduction prohibited without permission.

UNIVERSITY OF REGINA

FACULTY OF GRADUATE STUDIES AND RESEARCH

SUPERVISORY AND EXAMINING COMMITTEE

Teerawat Sanpasertparnich, candidate for the degree of Master of Applied Science in Industrial Systems Engineering, has presented a thesis titled Monte Carlo Simulation of Pulverized Coal-Fired Power Plants: Efficiency Improvement and CO2 Capture Options, in an oral examination held on November 6, 2007. The following committee members have found the thesis acceptable in form and content, and that the candidate demonstrated satisfactory knowledge of the subject material.

External Examiner: Dr. G. Zhao, Faculty of Engineering, PSE

Supervisor: Dr. A. Aroonwilas, Faculty of Engineering, ISE

Committee Member: Dr. P. Gu, Faculty of Engineering, PSE

Committee Member: Dr. D. de Montigny, Faculty of Engineering, EVSE

Chair of Defense: Dr. A. Wee, Department of Chemistry and Biochemistry


UNIVERSITY OF REGINA

FACULTY OF GRADUATE STUDIES AND RESEARCH

SUPERVISORY AND EXAMINING COMMITTEE

Teerawat Sanpasertpamich, candidate for the degree of Master of Applied Science in Industrial Systems Engineering, has presented a thesis titled Monte Carlo Simulation of Pulverized Coal-Fired Power Plants: Efficiency Improvement and C02 Capture Options, in an oral examination held on November 6, 2007. The following committee members have found the thesis acceptable in form and content, and that the candidate demonstrated satisfactory knowledge of the subject material.

External Examiner: Dr. G. Zhao, Faculty of Engineering, PSE

Supervisor: Dr. A. Aroonwilas, Faculty of Engineering, ISE

Committee Member: Dr. P. Gu, Faculty of Engineering, PSE

Committee Member: Dr. D. de Montigny, Faculty of Engineering, EVSE

Chair of Defense: Dr. A. Wee, Department of Chemistry and Biochemistry


Abstract

This study investigated the effects of operating and design parameters of coal-

fired power plants on net efficiency of power generation as well as a rate of CO2

emission. The key parameters were identified and used to determine optimal design and

operating conditions that would offer the maximum power plant efficiency. The

investigation focused on both subcritical and supercritical pulverized coal-fired power

plants. The study also examined how the net efficiency of the power plants responds to

changes in performance of an integrated CO2 capture unit, thus helping identify the

optimal capture target providing the least energy penalty per unit of the CO2 captured.

This study was carried out by first developing a process-based computer model of the

pulverized coal-fired power plants that were built on the principles of coal combustion,

combustion chemistry, heat transfer from a combustion zone, combined material and

energy balances and thermodynamics of a steam power cycle. Simulation of the

developed model was then performed for a sensitivity analysis using rank correlation

coefficient and Monte Carlo simulation approaches in order to arrive at the optimal

operating and design conditions.

It was found from the study that the major influential parameters were moisture

content in coal, steam pressures throughout a turbine system, boiler efficiency,

temperature of preheated air, and temperatures of both main steam and reheated steam.

The obtained parametric effects were quantified and translated into a series of empirical

correlations of the net efficiency that could be readily utilized by power industries and

engineers. Besides the net efficiency, the magnitude of the energy penalty due to the CO2


Abstract

This study investigated the effects o f operating and design parameters o f coal-

fired power plants on net efficiency o f power generation as well as a rate o f CO2

emission. The key parameters were identified and used to determine optimal design and

operating conditions that would offer the maximum power plant efficiency. The

investigation focused on both subcritical and supercritical pulverized coal-fired power

plants. The study also examined how the net efficiency o f the power plants responds to

changes in performance o f an integrated CO2 capture unit, thus helping identify the

optimal capture target providing the least energy penalty per unit o f the CO2 captured.

This study was carried out by first developing a process-based computer model o f the

pulverized coal-fired power plants that were built on the principles o f coal combustion,

combustion chemistry, heat transfer from a combustion zone, combined material and

energy balances and thermodynamics o f a steam power cycle. Simulation o f the

developed model was then performed for a sensitivity analysis using rank correlation

coefficient and Monte Carlo simulation approaches in order to arrive at the optimal

operating and design conditions.

It was found from the study that the major influential parameters were moisture

content in coal, steam pressures throughout a turbine system, boiler efficiency,

temperature o f preheated air, and temperatures o f both main steam and reheated steam.

The obtained parametric effects were quantified and translated into a series o f empirical

correlations o f the net efficiency that could be readily utilized by power industries and

engineers. Besides the net efficiency, the magnitude o f the energy penalty due to the CO2

i


capture integration was evaluated and also the optimal level of the CO2 capture target was

identified. The sensitivity analysis for cost of electricity was also performed in this study

based on different scenarios, i.e., base subcritical pulverized coal-fired power plant

without the CO2 capture, subcritical pulverized coal-fired power plant with the CO2

capture using alkanolamine solvent, base supercritical pulverized coal-fired power plant

without the CO2 capture, and supercritical pulverized coal-fired power plant with the CO2

capture using alkanolamine solvent.

ii


capture integration was evaluated and also the optimal level o f the CO2 capture target was

identified. The sensitivity analysis for cost o f electricity was also performed in this study

based on different scenarios, i.e., base subcritical pulverized coal-fired power plant

without the CO2 capture, subcritical pulverized coal-fired power plant with the CO2

capture using alkanolamine solvent, base supercritical pulverized coal-fired power plant

without the CO2 capture, and supercritical pulverized coal-fired power plant with the CO2

capture using alkanolamine solvent.

ii


Acknowledgement

I would like to sincerely acknowledge Dr. Adisorn Aroonwilas, my supervisor,

and Dr. Amornvadee Veawab for their constructive guidance, valuable time and effort

throughout my whole thesis. Their willingness to mentor is greatly appreciated.

I wish to express my gratitude to Dr. Nader Mahinpey and Dr. Amr Henni for

superior classes. They instructed me on how to create mathematical modeling. I was

able to perform my research without relying on commercial chemical process simulators.

I have enjoyed my time at the University of Regina since I joined the International Test

Centre for CO2 Capture (ITC) and the Toastmasters International club.

I am grateful to my advisory committee, Dr. Peter Gu and Dr. David deMontigny,

for their valuable questions and recommendations that were helpful in improving my

thesis.

Importantly, I would like to recognize the Natural Sciences and Engineering

Research Council of Canada (NSERC), the Faculty of Graduate Studies and Research

(FGSR), and the Faculty of Engineering for their financial support.

iii


Acknowledgement

I would like to sincerely acknowledge Dr. Adisom Aroonwilas, my supervisor,

and Dr. Amomvadee Veawab for their constructive guidance, valuable time and effort

throughout my whole thesis. Their willingness to mentor is greatly appreciated.

I wish to express my gratitude to Dr. Nader Mahinpey and Dr. Amr Henni for

superior classes. They instructed me on how to create mathematical modeling. I was

able to perform my research without relying on commercial chemical process simulators.

I have enjoyed my time at the University o f Regina since I joined the International Test

Centre for CO2 Capture (ITC) and the Toastmasters International club.

I am grateful to my advisory committee, Dr. Peter Gu and Dr. David deMontigny,

for their valuable questions and recommendations that were helpful in improving my

thesis.

Importantly, I would like to recognize the Natural Sciences and Engineering

Research Council o f Canada (NSERC), the Faculty o f Graduate Studies and Research

(FGSR), and the Faculty o f Engineering for their financial support.

iii


Dedication

I would like to state that this thesis is dedicated to my parents and my sisters for

their encouragement, especially to my dad. Although he was physically unhealthy, he had

never given me a notice about his painful illness when I was studying here in Canada.

Finally, I would like to thank Bhurisa Thitakamol, my greatest partner, for her brilliantly

technical advice through my thesis from the beginning to the end.

iv


Dedication

I would like to state that this thesis is dedicated to my parents and my sisters for

their encouragement, especially to my dad. Although he was physically unhealthy, he had

never given me a notice about his painful illness when I was studying here in Canada.

Finally, I would like to thank Bhurisa Thitakamol, my greatest partner, for her brilliantly

technical advice through my thesis from the beginning to the end.

iv


Table of Contents

page

Abstract

Acknowledgement iii

Dedication iv

Table of Contents

List of Tables viii

List of Figures

Acronym and Abbreviation xiii

Nomenclature xv

Chapter One: Introduction 1

1.1 Electricity Generation by Coal 1

1.2 Coal-Fired Power Plants and the Environment 3

1.3 GHG Mitigation Strategies for Coal-Fired Power Plants 6

1.3.1 Improvement in Net Efficiency 7

1.3.2 CO2 Capture Technologies 12

1.4 Research Objectives 14

Chapter Two: Literature Review and Fundamental 16

2.1 Development of Combustion Process 16

2.2 Chemistry of Coal Combustion 17

2.3 Heat of Combustion 18

2.4 Steam Power Cycle 19


Table of Contents

page

Abstract i

Acknowledgement iii

Dedication iv

Table of Contents v

List of Tables viii

List of Figures x

Acronym and Abbreviation xiii

Nomenclature xv

Chapter One: Introduction 1

1.1 Electricity Generation by Coal 1

1.2 Coal-Fired Power Plants and the Environment 3

1.3 GHG Mitigation Strategies for Coal-Fired Power Plants 6

1.3.1 Improvement in Net Efficiency 7

1.3.2 CO2 Capture Technologies 12

1.4 Research Objectives 14

Chapter Two: Literature Review and Fundamental 16

2.1 Development o f Combustion Process 16

2.2 Chemistry o f Coal Combustion 17

2.3 Heat o f Combustion 18

2.4 Steam Power Cycle 19

v


2.5 Design and Operation of Pulverized Coal-Fired Power Plants

2.6 CO2 Capture from Coal-Fired Flue Gas

Chapter Three: Development of Coal-Fired Power Plant Model

22

27

30

3.1 Model Development 30

3.1.1 Furnace 31

3.1.2 Once-through Boiler 32

3.1.3 Turbines and Pumps 32

3.1.4 Feedwater Heaters 33

3.2 Model Validation 38

3.3 Sensitivity Analysis and Performance Optimization 38

3.3.1 Monte Carlo Simulation 40

3.3.2 Rank Correlation Coefficient 43

3.3.3 Ranges of Input Parameters 45

Chapter Four: Results and Discussions: Subcritical Coal-Fired Power Plant 52

4.1 Maximum-Minimum Ranges of Plant Performance 52

4.2 Sensitivity Analysis 54

4.3 Individual Effects of Process Parameters on Plant Performance 57

4.3.1 Effect of Moisture Content in Coal 58

4.3.2 Effect of Preheated Air Temperature 58

4.3.3 Effects of Main Steam Temperature and Reheating Temperature 60

4.3.4 Effects of Boiler and Turbine Efficiencies 62

4.3.5 Effect of Excess Air Supply 62

4.3.6 Effect of Pressure Drop across the Steam Cycle 65

4.3.7 Effects of Pressure and Pressure Distribution in the Turbine Series 65

4.4 Efficiency Correlations for Subcritical Pulverized Coal-fired Power Plant 71

4.5 Optimum Operating Conditions 78

4.6 Efficiency Drop due to CO2 Capture 81

4.6.1 Application of CO2 Capture Process 81

4.6.2 Effect of CO2 Removal Efficiency 83

vi


2.5 Design and Operation o f Pulverized Coal-Fired Power Plants 22

2.6 CO2 Capture from Coal-Fired Flue Gas 27

Chapter Three: Development of Coal-Fired Power Plant Model 30

3.1 Model Development 30

3.1.1 Furnace 31

3.1.2 Once-through Boiler 32

3.1.3 Turbines and Pumps 32

3.1.4 Feedwater Heaters 33

3.2 Model Validation 38

3.3 S ensitivity Analysis and Performance Optimization 3 8

3.3.1 Monte Carlo Simulation 40

3.3.2 Rank Correlation Coefficient 43

3.3.3 Ranges o f Input Parameters 45

Chapter Four: Results and Discussions: Subcritical Coal-Fired Power Plant 52

4.1 Maximum-Minimum Ranges o f Plant Performance 52

4.2 Sensitivity Analysis 54

4.3 Individual Effects o f Process Parameters on Plant Performance 57

4.3.1 Effect o f Moisture Content in Coal 58

4.3.2 Effect o f Preheated Air Temperature 58

4.3.3 Effects of Main Steam Temperature and Reheating Temperature 60

4.3.4 Effects of Boiler and Turbine Efficiencies 62

4.3.5 Effect o f Excess Air Supply 62

4.3.6 Effect o f Pressure Drop across the Steam Cycle 65

4.3.7 Effects o f Pressure and Pressure Distribution in the Turbine Series 65

4.4 Efficiency Correlations for Subcritical Pulverized Coal-fired Power Plant 71



4.6.1 Application of CO2 Capture Process 81

4.6.2 Effect o f CO2 Removal Efficiency 83

vi


Chapter Five: Results and Discussions: Supercritical Coal-Fired Power Plant 87

5.1 Individual Parametric Effects 90

5.2 Efficiency Correlations for Supercritical Pulverized Coal-fired Power Plant99



Chapter Six: Economic Assessment 112

6.1 Economic Basis 112

6.1.1 Allowance for Funds Used during Construction 113

6.1.2 Levelized Fixed Charge Rate of Capital Cost 114

6.1.3 Levelized Operating Cost 116

6.1.4 Present Worth Cost 116

6.2 Cost of Electricity of Pulverized Coal-Fired Power Plants 117

6.3 Sensitivity Analysis for Electricity Cost 123

Chapter Seven: Conclusions and Future Work 126

7.1 Conclusions 126

7.2 Future Work 128

List of References 129

Appendix

Appendix A

vii

134

134


Chapter Five: Results and Discussions: Supercritical Coal-Fired Power Plant 87

5.1 Individual Parametric Effects 90

5.2 Efficiency Correlations for Supercritical Pulverized Coal-fired Power Plant99



Chapter Six: Economic Assessment 112

6.1 Economic Basis 112

6.1.1 Allowance for Funds Used during Construction 113

6.1.2 Levelized Fixed Charge Rate o f Capital Cost 114

6.1.3 Levelized Operating Cost 116

6.1.4 Present Worth Cost 116

6.2 Cost o f Electricity o f Pulverized Coal-Fired Power Plants 117

6.3 Sensitivity Analysis for Electricity Cost 123

Chapter Seven: Conclusions and Future Work 126

7.1 Conclusions 126

7.2 Future Work 128

List of References 129

Appendix 134

Appendix A 134

vii


List of Tables

page

Table 1.1 Comparison of PC, CFB, PFB and IGCC 4

Table 1.2 Research studies on improvement of power plant efficiency 8

Table 3.1 Comparison between simulation results in this study and published data 39

Table 3.2 Type of distribution curves used in this study 41

Table 3.3 Main input for subcritical and supercritical PCs 48

Table 4.1 Maximum-minimum performance of subcritical PC 53

Table 4.2 Characteristics of Illinois#6 bituminous coal 55

Table 4.3 Characteristics of coal used for simulation 76

Table 4.4 Optimal process operations for subcritical PC 80

Table 4.5 Comparison of subcritical PC with and without MEA-based CO2

absorption unit 84

Table 5.1 Maximum-minimum performance of supercritical PC 88

Table 5.2 Optimal process operations for supercritical PC 106

Table 5.3 Comparison of supercritical PC with and without MEA-based CO2

absorption unit 109

Table 6.1 Economic inputs 118

Table 6.2 Results of economic analysis for subcritical and supercritical PCs with

and without MEA-based CO2 absorption unit 119

Table 6.3 Ranges of Economic inputs for analysis of electricity cost 124

viii


List of Tables

page

Table 1.1 Comparison of PC, CFB, PFB and IGCC 4

Table 1.2 Research studies on improvement o f power plant efficiency 8

Table 3.1 Comparison between simulation results in this study and published data 39

Table 3.2 Type o f distribution curves used in this study 41

Table 3.3 Main input for subcritical and supercritical PCs 48

Table 4.1 Maximum-minimum performance o f subcritical PC 53

Table 4.2 Characteristics o f Illinois# 6 bituminous coal 55

Table 4.3 Characteristics o f coal used for simulation 76

Table 4.4 Optimal process operations for subcritical PC 80

Table 4.5 Comparison o f subcritical PC with and without MEA-based CO2

absorption unit 84

Table 5.1 Maximum-minimum performance o f supercritical PC 8 8

Table 5.2 Optimal process operations for supercritical PC 106

Table 5.3 Comparison o f supercritical PC with and without MEA-based CO2

absorption unit 109

Table 6.1 Economic inputs 118

Table 6.2 Results o f economic analysis for subcritical and supercritical PCs with

and without MEA-based CO2 absorption unit 119

Table 6.3 Ranges o f Economic inputs for analysis o f electricity cost 124

viii


Table A.1 Emission factors for bituminous and subbituminous coal combustion

without control equipment

Table A.2 List of enthalpy and entropy correlations of streams

ix


Table A.1

Table A.2

Emission factors for bituminous and subbituminous coal combustion

without control equipment 138

List o f enthalpy and entropy correlations o f streams 139


List of Figures

page

Figure 1.1 Projected fuel share of world's electricity generation from 2002 to 2025 2

Figure 1.2 Scheme of pulverized coal-fired power plant 5

Figure 1.3 Flow diagram of MEA-based CO2 absorption unit 13

Figure 2.1 Simple scheme of Reheat-regenerative Rankine cycle 21

Figure 2.2 Scheme of "subcritical" pulverized coal-fired power plant 25

Figure 2.3 Scheme of "supercritical" pulverized coal-fired power plant 26

Figure 2.4 Schematic diagram of integration of environmental abatement units 28

Figure 3.1 Regression flowchart for correlating steam properties 35

Figure 3.2 Computational algorithm of developed power plant model 36

Figure 3.3 Developed power plant model and Monte Carlo simulation 42

Figure 3.4 Basic flowchart for ranking algorithm 44

Figure 3.5 Identified points of input parameters for subcritical PC 46

Figure 3.6 Identified points of input parameters for supercritical PC 47

Figure 4.1 Results of sensitivity analysis by an approach of rank correlation

coefficient 56

Figure 4.2 Effects of moisture content in coal and temperature of preheated air 59

Figure 4.3 Effects of main steam and reheated steam temperatures 61

Figure 4.4 Effects of boiler and turbine efficiencies 63

Figure 4.5 Effect of excess air for coal combustion 64

Figure 4.6 Effect of pressure drop in steam cycle 66

Figure 4.7 Effect of pressure in the HP stage 68

x


List of Figures

page

Figure 1.1 Projected fuel share o f world’s electricity generation from 2002 to 2025 2

Figure 1.2 Scheme o f pulverized coal-fired power plant 5

Figure 1.3 Flow diagram of MEA-based CO2 absorption unit 13

Figure 2.1 Simple scheme o f Reheat-regenerative Rankine cycle 2 1

Figure 2.2 Scheme o f “subcritical” pulverized coal-fired power plant 25

Figure 2.3 Scheme o f “supercritical” pulverized coal-fired power plant 26

Figure 2.4 Schematic diagram of integration o f environmental abatement units 28

Figure 3.1 Regression flowchart for correlating steam properties 35

Figure 3.2 Computational algorithm of developed power plant model 36

Figure 3.3 Developed power plant model and Monte Carlo simulation 42

Figure 3.4 Basic flowchart for ranking algorithm 44

Figure 3.5 Identified points o f input parameters for subcritical PC 46

Figure 3.6 Identified points o f input parameters for supercritical PC 47

Figure 4.1 Results o f sensitivity analysis by an approach o f rank correlation

coefficient 56

Figure 4.2 Effects o f moisture content in coal and temperature o f preheated air 59

Figure 4.3 Effects o f main steam and reheated steam temperatures 61

Figure 4.4 Effects o f boiler and turbine efficiencies 63

Figure 4.5 Effect o f excess air for coal combustion 64

Figure 4.6 Effect o f pressure drop in steam cycle 6 6

Figure 4.7 Effect o f pressure in the HP stage 6 8


Figure 4.8

Figure 4.9

Figure 4.10

Figure 4.11

Figure 4.12

Figure 4.13

Figure 4.14

Figure 4.15

Figure 4.16

Figure 5.1

Figure 5.2

Figure 5.3

Figure 5.4

Figure 5.5

Figure 5.6

Figure 5.7

Figure 5.8

Figure 5.9

Figure 5.10

Figure 5.11

Effect of pressure at the 1st IP stage

Effect of pressure at the 3rd IP stage

Effect of pressure at the last LP stage

Reference net efficiency of base subcritical PC

Parity plot of net efficiency between empirical correlation and

theoretical model

Scheme of subcritical PC at optimal operating conditions

Scheme of subcritical PC with MEA-based absorption unit operating

at optimal conditions

Effect of CO2 loading on reboiler heat duty

Effect of CO2 removal efficiency on net efficiency point drop

Results of sensitivity analysis by an approach of rank correlation

coefficient

Effects of moisture content in coal and temperature of preheated air

Effects of main steam and reheated steam temperatures

Effects of boiler and turbine efficiencies

Effect of excess air for coal combustion

Effect of pressure drop in steam cycle

Effect of pressure in the HP stage

Effect of pressure at the 2nd HP Stage

Effect of pressure at the 1St IP stage

Effect of pressure at the 3rd IP stage

Effect of pressure at the last LP stage

xi

70

70

72

73

77

79

82

85

86

89

91

92

93

94

96

97

97

98

98

100


Figure 4.8 Effect o f pressure at the 1st IP stage 70

Figure 4.9 Effect o f pressure at the 3rd IP stage 70

Figure 4.10 Effect o f pressure at the last LP stage 72

Figure 4.11 Reference net efficiency of base subcritical PC 73

Figure 4.12 Parity plot o f net efficiency between empirical correlation and

theoretical model 77

Figure 4.13 Scheme of subcritical PC at optimal operating conditions 79

Figure 4.14 Scheme of subcritical PC with MEA-based absorption unit operating

at optimal conditions 82

Figure 4.15 Effect o f CO2 loading on reboiler heat duty 85

Figure 4.16 Effect o f CO2 removal efficiency on net efficiency point drop 86

Figure 5.1 Results o f sensitivity analysis by an approach o f rank correlation

coefficient 89

Figure 5.2 Effects o f moisture content in coal and temperature o f preheated air 91

Figure 5.3 Effects o f main steam and reheated steam temperatures 92

Figure 5.4 Effects o f boiler and turbine efficiencies 93

Figure 5.5 Effect o f excess air for coal combustion 94

Figure 5.6 Effect o f pressure drop in steam cycle 96

Figure 5.7 Effect o f pressure in the HP stage 97

Figure 5.8 Effect o f pressure at the 2nd HP Stage 97

Figure 5.9 Effect o f pressure at the 1st IP stage 98

Figure 5.10 Effect o f pressure at the 3rd IP stage 98

Figure 5.11 Effect o f pressure at the last LP stage 100

xi


Figure 5.12 Reference net efficiency of base supercritical PC

Figure 5.13 Parity plot of net efficiency between empirical correlation and

theoretical model

Scheme of supercritical PC at optimal operating conditions

Scheme of supercritical PC with MEA-based absorption unit operating

at optimal conditions

Comparison of energy penalty between subcritical and supercritical

PCs

Magnitude of energy penalty per unit of CO2 removal efficiency

Levelized fixed charge rate for capital cost

Cost of electricity (COE) difference, (0/kWh, yearn - yearn_i)

Capital recovery period

Results of sensitivity analysis for cost of electricity

Algorithm to compute the temperature profile in furnace/boiler

Algorithm for Gauss-Seidel method

Algorithm for NO calculation

Parity plot of enthalpy between actual data and empirical correlation

Figure 5.14

Figure 5.15

Figure 5.16

Figure 5.17

Figure 6.1

Figure 6.2

Figure 6.3

Figure 6.4

Figure A.1

Figure A.2

Figure A.3

Figure A.4

xii

101

103

105

108

110

111

115

121

122

125

134

135

136

137


Figure 5.12 Reference net efficiency of base supercritical PC 1 0 1

Figure 5.13 Parity plot o f net efficiency between empirical correlation and

theoretical model 103

Figure 5.14 Scheme of supercritical PC at optimal operating conditions 105

Figure 5.15 Scheme o f supercritical PC with MEA-based absorption unit operating

at optimal conditions 108

Figure 5.16 Comparison o f energy penalty between subcritical and supercritical

PCs 1 1 0

Figure 5.17 Magnitude o f energy penalty per unit o f CO2 removal efficiency 1 1 1

Figure 6.1 Levelized fixed charge rate for capital cost 115

Figure 6.2 Cost o f electricity (COE) difference, (0/kWh, yearn - yearn-i) 1 2 1

Figure 6.3 Capital recovery period 1 2 2

Figure 6.4 Results o f sensitivity analysis for cost o f electricity 125

Figure A .l Algorithm to compute the temperature profile in furnace/boiler 134

Figure A.2 Algorithm for Gauss-Seidel method 135

Figure A.3 Algorithm for NO calculation 136

Figure A.4 Parity plot o f enthalpy between actual data and empirical correlation 137

xii


Acronym and Abbreviation

AFUDC allowance for funds used during construction

CCUJ Center for Coal Utilization, Japan

CEA Canadian Electricity Association

CFB circulating fluidized bed power plant

COE cost of electricity

DEA diethanolamine

DGA diglycolamine

DIPA diisopropanolamine

EIA Environmental Investigation Agency

FOR enhanced oil recovery

ESP electrostatic precipitator

FGD flue gas desulfurization

FWHs feedwater heaters

FBC fluidized bed combustor power plant

G generator

GHGs greenhouse gases

HHV high heating value

HP high pressure turbine

IEA International Energy Agency

IP intermediate pressure turbine

IGCC integrated gasification combined cycle power plant


Acronym and Abbreviation

AFUDC allowance for funds used during construction

CCUJ Center for Coal Utilization, Japan

CEA Canadian Electricity Association

CFB circulating fluidized bed power plant

COE cost o f electricity

DEA diethanolamine

DGA diglycolamine

DIPA diisopropanolamine

EIA Environmental Investigation Agency

EOR enhanced oil recovery

ESP electrostatic precipitator

FGD flue gas desulfurization

FWHs feedwater heaters

FBC fluidized bed combustor power plant

G generator

GHGs greenhouse gases

HHV high heating value

HP high pressure turbine

IEA International Energy Agency

IP intermediate pressure turbine

IGCC integrated gasification combined cycle power plant


LEBS advanced coal-fired low emission boiler system

LHV low heating value

LNB low NO burner

LP low pressure turbine

MDEA N-methyldiethanolamine

MEA monoethanolamine

MWh megawatt-hour

NEDO New Energy and Industrial Technology Development Organization

O&M operating and maintenance

PC pulverized coal-fired power plant

PFB pressurized fluidized bed power plant

PM particulate matter

RH reheater

SCR selective catalytic reduction

SH superheater

TEA triethanolamine

TWh terawatt-hour

U.S.DOE United States Department of Energy

xiv


LEBS advanced coal-fired low emission boiler system

LHV low heating value

LNB low NOx burner

LP low pressure turbine

MDEA A-methyldiethanolamine

MEA monoethanolamine

MWh megawatt-hour

NEDO New Energy and Industrial Technology Development Organization

O&M operating and maintenance

PC pulverized coal-fired power plant

PFB pressurized fluidized bed power plant

PM particulate matter

RH reheater

SCR selective catalytic reduction

SH superheater

TEA triethanolamine

TWh terawatt-hour

U.S.DOE United States Department o f Energy


Nomenclature

A percent ash content by weight, %

AFUDC allowance for funds used during construction, $/kW

C percent carbon content by weight, %

Cp,, specific heat capacity of combustion product i, kJ/kmol K

CC consumable cost, $/kWh

CF capacity factor, %

COE cost of electricity, 0/kWh or $/kWh

CRF capital recovery factor


es annual escalation rate, %

e error between actual and empirical correlation data

Ea percent excess air, %

Fm percent free moisture in coal, %

FC fuel cost, $/kWh

FCF fixed charge rate

h specific enthalpy, kJ/kg

hi specific enthalpy of stream i, kJ/s

Afii enthalpy change of combustion product i, kJ/s

H percent hydrogen content by weight, %

HHV high heating value, kJ/kg coal

i interest rate, %

xv


Nomenclature

A percent ash content by weight, %

AFUDC allowance for funds used during construction, $/kW

C percent carbon content by weight, %

Cpj specific heat capacity o f combustion product i, kJ/kmol K

CC consumable cost, $/kWh


COE cost o f electricity, 0/kWh or $/kWh

CRF capital recovery factor


es annual escalation rate, %

e error between actual and empirical correlation data

Ea percent excess air, %

Fm percent free moisture in coal, %

FC fuel cost, $/kWh

FCF fixed charge rate

h specific enthalpy, kJ/kg

ht specific enthalpy o f stream i, kJ/s

AH i enthalpy change of combustion product i, kJ/s

H percent hydrogen content by weight, %

HHV high heating value, kJ/kg coal

i interest rate, %

xv


Kp

1

L

til coal

N

NN2

N NO

NO2

N total

0

OC

OM

PN,

PNO

Po,

P

P drop

P,„

PV

present worth discount rate, %

reaction equilibrium

likeliest

latent heat of vaporization, kJ/kg vapor

rate of coal consumption, kg/s

mass flow rate of combustion product i, kg/s

percent nitrogen content by weight, %

the number of moles of nitrogen

the number of moles of nitric oxide

the number of moles of oxygen

the total number of moles

percent oxygen content by weight, %

other operating costs, $/kWh

operating and maintenance cost, $/kWh

partial pressure of nitrogen, kPa

partial pressure of nitric oxide, kPa

partial pressure of oxygen, kPa

pressure

percent pressure drop, %

power output, kW

present value, $/kW

xvi


j present worth discount rate, %

KP reaction equilibrium

I likeliest

L latent heat of vaporization, kJ/kg vapor

™ coal rate o f coal consumption, kg/s

mt mass flow rate o f combustion product i, kg/s

N percent nitrogen content by weight, %

n N2 the number of moles o f nitrogen

N n othe number o f moles o f nitric oxide

N o 2 the number of moles o f oxygen

N total the total number o f moles

0 percent oxygen content by weight, %

oc Other operating costs, $/kWh

OM operating and maintenance cost, $/kWh

P n 2 partial pressure of nitrogen, kPa

P NO partial pressure o f nitric oxide, kPa

Po2 partial pressure o f oxygen, kPa

P pressure

P drop percent pressure drop, %

Pw power output, kW

PV present value, $/kW


qh

ql

Qboiler

Qecon

Qevap

Qfurnace

Amain steam

Qpreheater

01211

QSH

R

R2

S

S

sr

T

Tair

Tm

Tr

TCR

HHV-based combustion heat, kJ/kg coal

LHV-based combustion heat, kJ/kg coal

heat input from boiler, kJ/s

heat transferred to economizer, kJ/s

heat transferred to evaporator, kJ/s

furnace heat, kJ/s

LHV-based combustion heat, kJ/s

heat for producing main steam, kJ/s

heat recovered from hot flue gas via air preheater, kJ/s

heat for producing reheated steam, kJ/s

heat for producing superheat steam, kJ/s

rank correlation coefficient

coefficient of multiple determination

specific entropy, kJ/kg K

percent sulfur content by weight, %

sum square of residual between actual and empirical correlation data

temperature

preheated air temperature, °C

main temperature, °C

reheating temperature, °C

total capital requirement, $/year

xvii


Qh HHV-based combustion heat, kJ/kg coal

<n LHV-based combustion heat, kJ/kg coal

Qboiler heat input from boiler, kJ/s

Qecon heat transferred to economizer, kJ/s

Qevap heat transferred to evaporator, kJ/s

Q furnace furnace heat, kJ/s

Q i LHV-based combustion heat, kJ/s

Qmain steam heat for producing main steam, kJ/s

Q preheater heat recovered from hot flue gas via air preheater, kJ/s

Qrh heat for producing reheated steam, kJ/s

Qsh heat for producing superheat steam, kJ/s

R rank correlation coefficient

R2 coefficient o f multiple determination

s specific entropy, kJ/kg K

S percent sulfur content by weight, %

S r sum square o f residual between actual and empirical correlation data

T temperature

T a ir preheated air temperature, °C

Tm main temperature, °C

Tr reheating temperature, °C

TCR total capital requirement, $/year


US uniform series value, $/kW

W mass of water vapor, kg vapor/kg coal

* 1-1P i power produced from section i of high pressure turbine, kJ/s

* IP i power produced from section i of intermediate pressure turbine, kJ/s

* LP ,i power produced from section i of low pressure turbine, kJ/s

*our power output from steam cycle, kJ/s

W out,net net power output of overall system, kJ/s

WP pumping power input, kJ/s

* 13' i power input for individual pumps, kJ/s

* P,isen isentropic pumping power, kJ/s

* P foto( total pumping power, kJ/s

F.VT turbine power, kJ/s

* T ,isen isentropic turbine power, kJ/s

* T ,total total power from turbines, kJ/s

Greek letter

a

fi

6 Q

es

alpha or negative skew

beta or positive skew

approximate relative error, %

specified error, %

xviii


US uniform series value, $/kW

w mass o f water vapor, kg vapor/kg coal

wHP,t power produced from section i o f high pressure turbine, kJ/s

K,< power produced from section i o f intermediate pressure turbine, kJ/s

K j power produced from section i o f low pressure turbine, kJ/s

wout power output from steam cycle, kJ/s

w" out,net net power output o f overall system, kJ/s

Wp pumping power input, kJ/s

Wp,t power input for individual pumps, kJ/s

wP.isen isentropic pumping power, kJ/s

^ P , to ta l total pumping power, kJ/s

WT turbine power, kJ/s

wrr T,isen isentropic turbine power, kJ/s

WT .total total power from turbines, kJ/s

Greek letter

a alpha or negative skew

P beta or positive skew

£a approximate relative error, %

specified error, %

xviii


0

p

-

A r/

furnace

boiler

r 1 drop

net

71 ref

T

1 th

minimum value

mean value

standard deviation

efficiency variation, %

efficiency of furnace, %

efficiency of boiler, %

net efficiency point drop, %

net efficiency, %

reference efficiency, %

efficiency of turbine, %

thermal efficiency of steam cycle, %

xix


d minimum value

M mean value

a standard deviation

A 77 efficiency variation, %

V furnace efficiency o f furnace, %

boiler efficiency o f boiler, %

V drop net efficiency point drop, %

V net net efficiency, %

V re f reference efficiency, %

I t efficiency o f turbine, %

7* thermal efficiency o f steam cycle, %


Chapter One

Introduction

1.1 Electricity Generation by Coal

Electricity generation by coal is one of the most important activities in fossil fuel

based economies across the globe. About 7000 TWh (Terawatt hours) of electricity were

produced by coal in 2004. It was considered the largest fuel share, accounting for 39.8%

of the world's total electricity production (IEA, 2006a). In Canada, in 2003, coal was the

second largest energy resource for electricity generation providing about 19% of

Canada's total electricity generation (CEA, 2006). As reported by Energy Information

Administration (EIA) in 2005, the use of coal for electricity generation will continue to

play a primary role in the global scale at least until the year 2025 (Figure 1.1). The global

demand for coal is expected to rise significantly, as the major developing countries such

as China and India are planning for additional capacity of coal-fired generation in the

next two decades (IEA, 2006b). The growing coal demand trend will result in a global

coal consumption of more than 6000 mtce (million tons of carbon equivalent) by the year

2030.

Today, there are several coal-based electricity generation technologies that have

been used worldwide for both commercial and demonstration purposes. Such

technologies include a pulverized coal-fired power plant (PC), a circulating fluidized bed

power plant (CFB), a pressurized fluidized bed power plant (PFB) and an integrated

gasification combined cycle power plant (IGCC). The PC is the conventional technology

1


Chapter One

Introduction

1.1 Electricity Generation by Coal

Electricity generation by coal is one o f the most important activities in fossil fuel

based economies across the globe. About 7000 TWh (Terawatt hours) o f electricity were

produced by coal in 2004. It was considered the largest fuel share, accounting for 39.8%

of the world’s total electricity production (IEA, 2006a). In Canada, in 2003, coal was the

second largest energy resource for electricity generation providing about 19% of

Canada’s total electricity generation (CEA, 2006). As reported by Energy Information

Administration (ELA) in 2005, the use o f coal for electricity generation will continue to

play a primary role in the global scale at least until the year 2025 (Figure 1.1). The global

demand for coal is expected to rise significantly, as the major developing countries such

as China and India are planning for additional capacity o f coal-fired generation in the

next two decades (IEA, 2006b). The growing coal demand trend will result in a global

coal consumption of more than 6000 mtce (million tons o f carbon equivalent) by the year

2030.

Today, there are several coal-based electricity generation technologies that have

been used worldwide for both commercial and demonstration purposes. Such

technologies include a pulverized coal-fired pow er plant (PC ), a circulating flu idized bed

power plant (CFB), a pressurized fluidized bed power plant (PFB) and an integrated

gasification combined cycle power plant (IGCC). The PC is the conventional technology

1


Percent of Total

100 —

80 —0 Natural Gas

60 — Nuclear

Eri] Renewables

0 Coal 40— Oil

20 --

0

V

2002 2010 2015 2020 2025

Figure 1.1 Projected fuel share of world's electricity generation from 2002 to 2025.

(Redrawn from ETA, 2005)

2


Percent of Total

100

80Natural Gas

NuclearRenewables

60

Coal4 0 - Oil

2 0 -

2002 2010 2015 2020 2025

Figure 1.1 Projected fuel share o f world’s electricity generation from 2002 to 2025.

(Redrawn from EIA, 2005)


that relies on simple combustion of pulverized coal in a furnace at about 1650-1900°C

(Woodruff et al., 2005). Energy from the coal combustion is utilized for generating high-

pressure steam that drives steam turbines. The CFB is operated by combusting coal in a

fluidized bed combustor in the presence of limestone to reduce sulfur dioxide (SO2)

content in an emitted flue gas. Solid particles of limestone, ashes and unburned coal

resulting from the combustion are continuously collected by cyclones and re-circulated

within the combustor (Woodruff et al., 2005). The PFB is almost similar to the CFB,

except that the combustor is operated at a higher pressure ranging from 1.0 to 1.5 MPa.

Both of the CFB and PFB generate electricity mainly through the steam cycle. For the

IGCC, the electricity is produced by the gas turbines and steam turbines. Coal is gasified

to produce a stream of syngas (or synthesis gas) that drives the gas turbines and the flue

gas from the gas turbine is used to produce a high-pressure steam that drives the steam

turbines. Among these four technologies, the PC is the most commonly used power plant

around the world as shown in Table 1.1. A typical schematic diagram of the PC is given

in Figure 1.2.

1.2 Coal-Fired Power Plants and the Environment

Despite its significance, the use of coal for electricity generation poses an adverse

impact on humans and the environment, especially excessive emissions of greenhouse

gases (GHGs) to the atmosphere as also listed in Table 1.1. In 2001, the combustion of

coal contributed 38% of the total carbon dioxide (CO2) emission from the industrialized

world (Smith and Rousaki, 2002). It is recognized that CO2 is one of the major GHGs

causing global warming.

3


that relies on simple combustion o f pulverized coal in a furnace at about 1650-1900°C

(Woodruff et al., 2005). Energy from the coal combustion is utilized for generating high-

pressure steam that drives steam turbines. The CFB is operated by combusting coal in a

fluidized bed combustor in the presence o f limestone to reduce sulfur dioxide (SO2)

content in an emitted flue gas. Solid particles o f limestone, ashes and unbumed coal

resulting from the combustion are continuously collected by cyclones and re-circulated

within the combustor (Woodruff et al., 2005). The PFB is almost similar to the CFB,

except that the combustor is operated at a higher pressure ranging from 1.0 to 1.5 MPa.

Both o f the CFB and PFB generate electricity mainly through the steam cycle. For the

IGCC, the electricity is produced by the gas turbines and steam turbines. Coal is gasified

to produce a stream of syngas (or synthesis gas) that drives the gas turbines and the flue

gas from the gas turbine is used to produce a high-pressure steam that drives the steam

turbines. Among these four technologies, the PC is the most commonly used power plant

around the world as shown in Table 1.1. A typical schematic diagram of the PC is given

in Figure 1.2.

1.2 Coal-Fired Power Plants and the Environment

Despite its significance, the use o f coal for electricity generation poses an adverse

impact on humans and the environment, especially excessive emissions o f greenhouse

gases (GHGs) to the atmosphere as also listed in Table 1.1. In 2001, the combustion o f

coal contributed 38% o f the total carbon dioxide (CO2) emission from the industrialized

world (Smith and Rousaki, 2002). It is recognized that CO2 is one o f the major GHGs

causing global warming.

3


Reproduced w

ith permission o

f the copyright owner.

Furth

er reproduction prohibited w

ithout perm

ission.

Table 1.1 Comparison of PC, CFB, PFB and IGCC.

Description Sub-/Supercritical PC

Reliability, availability and commercial Commercial plants readiness with flue gas

desulfurization (FGD) since 1980s.

Worldwide established GW —1000

%HHV 35.8 — 38.9 Net efficiency

Unit size MW 400-1000

Emission rate (with SO2, NOR, and particulate removals)

SO2 kg/MWh 0.34-0.79

4=,

NO,, kg/MWh 0.20-1.20

Particulate matter kg/MWh 0.04-0.12

CO2

Capital requirement

kg/MWh 760-874

$/kW 1129 — 1173

CFB & PFB IGCC Reference

Expected to be in commercial application in year 2015a.


U.S.DOE (1999)

(CFB), —1 (PFB)

—3 Lako (2004)

35.5 — 39.0 32.3 — 43.1b U.S.DOE (1999); Marion et al. (2004)

<460 <318 Lako (2004)

0.34-0.66 negligible b - 0.87 U.S.DOE (1999); Marion et al. (2004); Lako (2004)

0.20-0.80 negligible b - 0.40 U.S.DOE (1999); Marion et al. (2004); Lako (2004)

0.003 0.008 U.S.DOE (1999)

816-906 718 b -898 U.S.DOE (1999); Marion et al. (2004); Lako (2004)

1100 1193 13 —1409 U.S.DOE (1999); Marion et al. (2004)

a The year 2015 is predicted based on the U.S.DOE (1999). b The H-class of the gas turbine used in the IGCC is on an early commercial demonstration phase and it is considered as a future case.

Reproduced

with perm

ission of the

copyright ow

ner. Further

reproduction prohibited

without

permission.

Table 1.1 Comparison of PC, CFB, PFB and IGCC.

Description Sub-/SupercriticalPC

CFB & PFB IGCC Reference

Reliability, availability and commercial readiness

Commercial plants with flue gas desulfurization (FGD) since 1980s.



U.S.DOE (1999)

Worldwide established GW -1000 -3 (CFB), -1 (PFB)

-3 Lako (2004)

Net efficiency %HHV 35.8-38 .9 35 .5 -39 .0 32.3 - 4 3 .11’ U.S.DOE (1999); Marion et al. (2004)

Unit size MW 400-1000 <460 <318 Lako (2004)

Emission rate (with SO:2, NOx, and particulate removals)

so2 kg/MWh 0.34-0.79 0.34-0.66 negligibleb - 0.87 U.S.DOE (1999); Marion et al. (2004); Lako (2004)

NOx kg/MWh 0.20-1.20 0.20-0.80 negligibleb - 0.40 U.S.DOE (1999); Marion et al. (2004); Lako (2004)

Particulate matter kg/MWh 0.04-0.12 0.003 0.008 U.S.DOE (1999)

C02 kg/MWh 760-874 816-906 718 6 -898 U.S.DOE (1999); Marion et al. (2004); Lako (2004)

Capital requirement $/kW 1129-1173 1100 1193 b- 1409 U.S.DOE (1999); Marion et al. (2004)

a The year 2015 is predicted based on the U.S.DOE (1999).b The H-class of the gas turbine used in the IGCC is on an early commercial demonstration phase and it is considered as a future case.

Fu

rnac

eBo

iler

Boiler feed pump

Condenser

Condensate pump

ter train

SH Superheater RH Reheater HP High pressure turbine IP Intermediate pressure turbine LP Low pressure turbine FWH Feedwater heater G Generator

Figure 1.2 Scheme of pulverized coal-fired power plant.

(Modified from Singer, 1991; Drbal et al., 1996;

U.S.DOE, 1999 and Kakaras et al., 2002)

5


Fur

nace

/Boi

ler

LPEvaporator

Snray water

Condenser-Reheat

Condensate pump13)

Upper feeawater heater train,Coal

SH SuperheaterRH ReheaterHP High pressure turbineIP Intermediate pressure turbineLP Low pressure turbineFWH Feedwater heaterG Generator

Figure 1.2 Scheme o f pulverized coal-fired power plant.



\ / Air heatei Degerator

Boiler feed pump

5


Although no emission standard has been set for CO2, efforts to reduce CO2 emissions

from existing coal-fired power plants are driven by responsibility to the environment and

community as well as the international agreements including Kyoto Protocol that 169

countries and governmental entities have signed and ratified. Canada has committed to

reducing CO2 emissions to a target 6% below 1990 levels by the year 2012. With its

increasing rate of GHG emissions after 1990, Canada will be required to lower the

emission by about 20-25% from the projected GHG emissions of 703-748 Mt in the year

2010 (Neitzert et al., 1999).

1.3 GHG Mitigation Strategies for Coal-Fired Power Plants

Reduction of CO2 emissions from coal-fired power plants can be achieved by two

fundamental strategies: (i) an improvement in net efficiency of the power generation

cycle and (ii) an integration of a CO2 capture unit to remove CO2 from the combustion

flue gas before it is discharged to the atmosphere. The improved efficiency strategy can

be realized through either adjusting the power plant operating conditions or modifying

the plant's configuration to fully utilize energy resources within the system. Applying

these two approaches can lead to the maximum plant efficiency as well as the minimum

coal consumption, thus resulting in the reduced rate of CO2 emissions at a specific net

power output. To further reduce emissions to a much lower level, the integration of the

CO2 capture unit into the power plants becomes necessary. However, the capture strategy

is not straightforward, as it requires the integrated power plants to be larger in size and

capable of providing additional energy for CO2 capture activities. This means that

6


Although no emission standard has been set for CO2, efforts to reduce CO2 emissions

from existing coal-fired power plants are driven by responsibility to the environment and

community as well as the international agreements including Kyoto Protocol that 169

countries and governmental entities have signed and ratified. Canada has committed to

reducing CO2 emissions to a target 6 % below 1990 levels by the year 2012. With its

increasing rate o f GHG emissions after 1990, Canada will be required to lower the

emission by about 20-25% from the projected GHG emissions o f 703-748 Mt in the year

2010 (Neitzert et al., 1999).

1.3 GHG Mitigation Strategies for Coal-Fired Power Plants

Reduction o f CO2 emissions from coal-fired power plants can be achieved by two

fundamental strategies: (i) an improvement in net efficiency of the power generation

cycle and (ii) an integration o f a CO2 capture unit to remove CO2 from the combustion

flue gas before it is discharged to the atmosphere. The improved efficiency strategy can

be realized through either adjusting the power plant operating conditions or modifying

the plant’s configuration to fully utilize energy resources within the system. Applying

these two approaches can lead to the maximum plant efficiency as well as the minimum

coal consumption, thus resulting in the reduced rate o f CO2 emissions at a specific net

power output. To further reduce emissions to a much lower level, the integration o f the

CO2 capture unit into the power plants becomes necessary. However, the capture strategy

is not straightforward, as it requires the integrated power plants to be larger in size and

capable o f providing additional energy for CO2 capture activities. This means that

6


capturing CO2 from the coal-fired power plants will present an increase in the cost of

electricity.

1.3.1 Improvement in Net Efficiency

Table 1.2 summarizes a number of research studies presenting various methods

that can help improving the net efficiency of coal-fired power plants (Hobbs and Heller,

1923; Leung and Moore, 1966; Cicconardi et al., 1991; Miliaras and Broer, 1991;

Schilling, 1993; Kitto, 1996; Regan et al., 1996; Petermann and Fett, 1997; U.S.DOE,

1999; Beer, 2000; Chattopadhyay, 2000; Kiga et al., 2000; Kakaras et al., 2002; Kjaer,

2002; Toshiyuki et al., 2002; Termuehlen and Emsperger, 2003; Gwosdz et al., 2005).

From the table, methods of improvement include a reduction of the moisture content in

coal, a use of an air pre-heater for waste energy recovery, an introduction of feed water

heaters (FWHs), an adjustment of operating temperature and pressure as well as an

introduction of advanced material and a new design of a boiler, a furnace and a turbine.

It should be noted that most studies were aimed only at an individual effect of one or a

pair of such operating and design parameters on the improvement of the plant efficiency.

There is no research study on the optimization of the power plant efficiency that

simultaneously takes all parametric effects and the associated parametric interactions into

account. Such a study would allow the development of operational and design strategies

to achieve the maximum power generation efficiency.

7


capturing CO2 from the coal-fired power plants will present an increase in the cost of

electricity.

1.3.1 Improvement in Net Efficiency

Table 1.2 summarizes a number o f research studies presenting various methods

that can help improving the net efficiency of coal-fired power plants (Hobbs and Heller,

1923; Leung and Moore, 1966; Cicconardi et al., 1991; Miliaras and Broer, 1991;

Schilling, 1993; Kitto, 1996; Regan et al., 1996; Petermann and Fett, 1997; U.S.DOE,

1999; Beer, 2000; Chattopadhyay, 2000; Kiga et al., 2000; Kakaras et al., 2002; Kjaer,

2002; Toshiyuki et al., 2002; Termuehlen and Emsperger, 2003; Gwosdz et al., 2005).

From the table, methods o f improvement include a reduction of the moisture content in

coal, a use o f an air pre-heater for waste energy recovery, an introduction o f feed water

heaters (FWHs), an adjustment o f operating temperature and pressure as well as an

introduction o f advanced material and a new design o f a boiler, a furnace and a turbine.

It should be noted that most studies were aimed only at an individual effect o f one or a

pair o f such operating and design parameters on the improvement o f the plant efficiency.

There is no research study on the optimization o f the power plant efficiency that

simultaneously takes all parametric effects and the associated parametric interactions into

account. Such a study would allow the development o f operational and design strategies

to achieve the maximum power generation efficiency.


Reproduced w

ith permission o


Furth


ithout perm

ission.

Table 1.2 Research studies on improvement of power plant efficiency.

Reference Power Plant Research Objective Finding

Hobbs and Heller, PC

1923

Study the effects of a

boiler capacity on the

plant efficiency.

The high boiler capacity or power output results in a better combustion efficiency

and coal consumption.

Leung and Moore,

1966

Supercritical

PC

Analyze the proper

position for steam

extraction in the turbine

series.

Appropriately extracting the steam pressure from the turbine series can improve the

net heat rate by 5.7%.

Cicconardi et al.,

1991

FBC Conduct the parametric

study.

Increasing the excess air from 10 to 40% slightly reduces the net efficiency.

Increasing a combustion temperature from 800 to 1000°C causes an improvement of

the plant efficiency by 6.3%.

Increasing of a compression and an expansion efficiencies from 0.8 to 0.9 results in

an improvement of the efficiency by 2.8 and 3.9%, respectively.

Miliaras and Broer, PC

1991

Review the advantage of a

regenerative system, a

double reheat steam cycle

and an arrangement of

equipment.

The regenerative system and the appropriate arrangement results in a reduction of the

coal consumption by 6.5% and an increase of the net power output by 21.2%.

The double steam reheater gives a reduction of the coal consumption by 7.3%.

Schilling, 1993 PC Review the process

parameters affecting the

net efficiency.

Increasing the excess air causes a reduction in the plant efficiency.

Reducing a stack temperature results in an improvement of the plant efficiency.

Increasing the main temperature and pressure from 25 to 35 MPa and from 540 to

600°C improves the plant efficiency by about 1.5%.

Reproduced

with perm

ission of the

copyright ow

ner. Further


without

permission.

Table 1.2 Research studies on improvement of power plant efficiency.


Hobbs and Heller,

1923

PC Study the effects of a

boiler capacity on the

plant efficiency.

The high boiler capacity or power output results in a better combustion efficiency

and coal consumption.

Leung and Moore, Supercritical Analyze the proper Appropriately extracting the steam pressure from the turbine series can improve the

1966 PC position for steam

extraction in the turbine

series.

net heat rate by 5.7%.

Cicconardi et al.,

1991

FBC Conduct the parametric

study.

Increasing the excess air from 10 to 40% slightly reduces the net efficiency.

Increasing a combustion temperature from 800 to 1000°C causes an improvement of

the plant efficiency by 6.3%.

Increasing o f a compression and an expansion efficiencies from 0.8 to 0.9 results in

an improvement of the efficiency by 2.8 and 3.9%, respectively.

Miliaras and Broer,

1991

PC Review the advantage of a

regenerative system, a

double reheat steam cycle

and an arrangement of

equipment.

The regenerative system and the appropriate arrangement results in a reduction o f the

coal consumption by 6.5% and an increase o f the net power output by 21.2%.

The double steam reheater gives a reduction o f the coal consumption by 7.3%.

Schilling, 1993 PC Review the process

parameters affecting the

net efficiency.

Increasing the excess air causes a reduction in the plant efficiency.

Reducing a stack temperature results in an improvement of the plant efficiency.

Increasing the main temperature and pressure from 25 to 35 MPa and from 540 to

600°C improves the plant efficiency by about 1.5%.

Reproduced w

ith permission o


Furth


ithout perm

ission.

Table 1.2 Research studies on improvement of power plant efficiency. (continued)


Schilling, 1993

(continued)

Changing the plant process from the single to the double steam reheater gives an

improvement of the plant efficiency.

Reducing a backpressure offers an increase of the plant efficiency.

Kitto, 1996 PC Evaluate the effect of the

subcritical, supercritical

and ultrasupercritical

power plants on the net

efficiency and identify key

parameters for plant

designs and operations.

The net efficiencies of the subcritical, supercritical and ultrasupercritical power

plants are 37, 42 and 46%, respectively.

The key parameters are (i) an advanced combustion system, (ii) a variable and dual

pressure operations, (iii) a spiral and vertical furnace circuit, (iv) a thermal design,

(v) a boiler material, (vi) a heat recovery, and (vii) an advanced SO2 emission

control.

Regan et al., 1996 LEBS a Purpose ideas to improve

the net efficiency.

The net efficiency is associated with condenser pressure, plant capacity and types of

coal-fired power stations.

The high pressure steam of 50 MPa at 600°C triple reheat stages gives the thermal

efficiency improvement by 3%.

A key to operate the power plant at a high temperature and pressure is the

introduction of the advanced material.

Petermann and

Fett, 1997

FBC Study the effect of thermal Increasing the thermal load of a 150-MW FBC from 70 to 100% results in an

load on the power output. increase of power output greater than 50 MW.

a LEBS is the advanced coal-fired low emission boiler system.

Reproduced

with perm

ission of the

copyright ow

ner. Further


without

permission.

Table 1.2 Research studies on improvement of power plant efficiency, (continued)


Schilling, 1993

(continued)

Changing the plant process from the single to the double steam reheater gives an

improvement o f the plant efficiency.

Reducing a backpressure offers an increase o f the plant efficiency.

Kitto, 1996 PC Evaluate the effect o f the

subcritical, supercritical

and ultrasupercritical

power plants on the net

efficiency and identify key

parameters for plant

designs and operations.


plants are 37,42 and 46%, respectively.

The key parameters are (i) an advanced combustion system, (ii) a variable and dual

pressure operations, (iii) a spiral and vertical furnace circuit, (iv) a thermal design,

(v) a boiler material, (vi) a heat recovery, and (vii) an advanced S 02 emission

control.

Regan et al., 1996 LEBS a Purpose ideas to improve

the net efficiency.

The net efficiency is associated with condenser pressure, plant capacity and types of

coal-fired power stations.

The high pressure steam of 50 MPa at 600°C triple reheat stages gives the thermal

efficiency improvement by 3%.

A key to operate the power plant at a high temperature and pressure is the

introduction o f the advanced material.

Petermann and

Fett, 1997

FBC Study the effect of thermal

load on the power output.

Increasing the thermal load o f a 150-MW FBC from 70 to 100% results in an

increase of power output greater than 50 MW.

a LEBS is the advanced coal-fired low emission boiler system.

Reproduced w

ith permission o


Further reproduction prohibited w

ithout permission.



U.S.DOE, 1999 PC Demonstrate the net

efficiency, the coal

consumption and CO2

emissions from various

types of the power plants.


plants are 37.6, 39.9, and 41.4%, respectively.

The coal consumptions of the subcritical, supercritical and ultrasupercritical power

plants are 39.0, 37.3 and 36.0 kg/s, respectively.

CO2 emissions from the subcritical, supercritical and ultrasupercritical power plants

are 837, 789 and 761 kg/MWh, respectively.

Beer, 2000 PC Discuss the variation of

the net efficiency caused

by a change in types of

the power plants.

Changing the plant's configuration from the subcritical to the supercritical PC can

improve the net efficiency from 39.4 to 41.1% and can reduce the coal consumption

from 874 to 826 ktonne/year.

Kiga et al., 2000 PC Investigate the effect of

the preheated air

temperature and the 0 2

content on the combustion

efficiency.

Preheating the air temperature from 35 to 850°C enhances the combustion efficiency

from —90 to —92%.

Lowering the 0 2 content in the supplied air from 21 to 8% decreases the combustion

efficiency from —92 to —79%.

Chattopadhyay,

2000

PC Study the effect of the

process parameters on the

net efficiency.

The high excess air and the free moisture in coal give the low net efficiency.

The high pressure and the temperature as well as the high turbine and boiler

efficiency offer an increase of the net efficiency.

Reproduced

with perm

ission of the

copyright ow

ner. Further


without

permission.

Table 1.2 Research studies on improvement o f power plant efficiency, (continued)


U.S.DOE, 1999 PC Demonstrate the net

efficiency, the coal

consumption and C 02

emissions from various

types of the power plants.


plants are 37.6, 39.9, and 41.4%, respectively.

The coal consumptions o f the subcritical, supercritical and ultrasupercritical power

plants are 39.0, 37.3 and 36.0 kg/s, respectively.

C02 emissions from the subcritical, supercritical and ultrasupercritical power plants

are 837, 789 and 761 kg/MWh, respectively.

Beer, 2000 PC Discuss the variation of

the net efficiency caused

by a change in types o f

the power plants.

Changing the plant’s configuration from the subcritical to the supercritical PC can

improve the net efficiency from 39.4 to 41.1% and can reduce the coal consumption

from 874 to 826 ktonne/year.

Kiga et al., 2000 PC Investigate the effect of

the preheated air

temperature and the 0 2

content on the combustion

efficiency.

Preheating the air temperature from 35 to 850°C enhances the combustion efficiency

from ~90 to -92%.

Lowering the 0 2 content in the supplied air from 21 to 8% decreases the combustion

efficiency from -92 to -79%.

Chattopadhyay,

2000

PC Study the effect o f the

process parameters on the

net efficiency.

The high excess air and the free moisture in coal give the low net efficiency.

The high pressure and the temperature as well as the high turbine and boiler

efficiency offer an increase o f the net efficiency.

Reproduced w

ith permission o



ithout permission.



Kakaras et al.,

2002

PC Study a coal dryer to

reduce the moisture

content in coal.

Reducing the moisture from 50-60% to 15-22% results in an improvement of the net

efficiency up to 7.4%.

Kjaer, 2002 Ultrasuper - Study the advanced Using the advanced material results in an improvement of the net efficiency greater

critical PC material of boiler tubes. than 50%.

Toshiyuki et al.,

2002

PC Investigate the effect of

the air temperature.

Raising the temperature to 727°C results in a decrease of ignition delay, causing an

increase of the net efficiency.

Termuehlen and PC Study the key equipments The introduction of the feedwater heaters and the steam reheater as well as the

Emsperger, 2003 to improve the plant increase of the pressure and temperature in the steam cycle can improve the steam

efficiency. efficiency from 34 to 58% b.

Gwosdz et al., PC Study the advantage and Lowering the excess air results in an increase of the net efficiency, but causing a

2005 disadvantage of the excess corrosion problem due to a presence of the carbon monoxide (CO) content.

air on the net efficiency.

b iIt s noted that the steam power cycle efficiency is not the net efficiency. It is always higher than the net efficiency.

Reproduced

with perm

ission of the

copyright ow

ner. Further


without

permission.

Table 1.2 Research studies on improvement of power plant efficiency, (continued)


Kakaras et al.,

2002

PC Study a coal dryer to

reduce the moisture

content in coal.

Reducing the moisture from 50-60% to 15-22% results in an improvement o f the net

efficiency up to 7.4%.

Kjaer, 2002 Ultrasuper -

critical PC

Study the advanced

material of boiler tubes.

Using the advanced material results in an improvement o f the net efficiency greater

than 50%.

Toshiyuki et al.,

2002

PC Investigate the effect of

the air temperature.

Raising the temperature to 727°C results in a decrease o f ignition delay, causing an

increase of the net efficiency.

Termuehlen and

Emsperger, 2003

PC Study the key equipments

to improve the plant

efficiency.

The introduction of the feedwater heaters and the steam reheater as well as the

increase of the pressure and temperature in the steam cycle can improve the steam

efficiency from 34 to 58% b.

Gwosdz et al.,

2005

PC Study the advantage and

disadvantage o f the excess

air on the net efficiency.

Lowering the excess air results in an increase o f the net efficiency, but causing a

corrosion problem due to a presence o f the carbon monoxide (CO) content.

b It is noted that the steam power cycle efficiency is not the net efficiency. It is always higher than the net efficiency.

1.3.2 CO2 Capture Technologies

CO2 capture is one of the potential approaches to reduce GHG emissions and meet

Kyoto targets. The goal of the capture is to remove CO2 from industrial gas streams and

to inject the removed CO2 into underground reservoirs for storage and enhance oil

recovery (EOR). Capturing CO2 can be achieved by several techniques, including gas

absorption, adsorption, membrane separation and cryogenic distillation. Among these

techniques, the gas absorption by chemical solvents is the most economical solution for

capturing CO2 from high-volume gas streams (Metz et al., 2005). Figure 1.3 illustrates a

typical flow diagram of the CO2 absorption unit that includes an absorption section for

capturing CO2 and a solvent regeneration section for restoring an absorption capacity of a

solvent and producing a high-purity CO2 gaseous stream. Monoethanolamine (MEA) is

the most commonly used solvent in this process.

It is well-recognized that CO2 absorption is an energy-intensive process that

consumes a large amount of the heat for the solvent regeneration up to 4800 kJ/kg CO2

captured (Aroonwilas and Veawab, 2007). To put the absorption process into use, the

energy required must be extracted from the power-generation steam cycle that will cause

a reduction in the net efficiency of the power plants commonly referred to as an energy

penalty. By far, there are a number of studies that address the issue of the energy penalty

resulting from the integration of the CO2 capture unit into the power plants (Desideri and

Paolucci, 1999; David and Herzog, 2000; Nsakala et al., 2001; Rao and Rubin, 2002;

Fisher et al., 2005). However, those studies were done based on a fixed CO2 capture

target, without considering how the changes in such a target would affect the extent of the

energy penalty. One may expect a disproportion between the amount of CO2 removed

12


1.3.2 C 0 2 Capture Technologies

C 0 2 capture is one of the potential approaches to reduce GHG emissions and meet

Kyoto targets. The goal o f the capture is to remove C 0 2 from industrial gas streams and

to inject the removed C 0 2 into underground reservoirs for storage and enhance oil

recovery (EOR). Capturing C 0 2 can be achieved by several techniques, including gas

absorption, adsorption, membrane separation and cryogenic distillation. Among these

techniques, the gas absorption by chemical solvents is the most economical solution for

capturing C 0 2 from high-volume gas streams (Metz et al., 2005). Figure 1.3 illustrates a

typical flow diagram of the C 0 2 absorption unit that includes an absorption section for

capturing C 0 2 and a solvent regeneration section for restoring an absorption capacity o f a

solvent and producing a high-purity C 0 2 gaseous stream. Monoethanolamine (MEA) is

the most commonly used solvent in this process.

It is well-recognized that C 0 2 absorption is an energy-intensive process that

consumes a large amount of the heat for the solvent regeneration up to 4800 kJ/kg C 0 2

captured (Aroonwilas and Veawab, 2007). To put the absorption process into use, the

energy required must be extracted from the power-generation steam cycle that will cause

a reduction in the net efficiency o f the power plants commonly referred to as an energy

penalty. By far, there are a number o f studies that address the issue o f the energy penalty

resulting from the integration o f the C 0 2 capture unit into the power plants (Desideri and

Paolucci, 1999; David and Herzog, 2000; Nsakala et al., 2001; Rao and Rubin, 2002;

Fisher et al., 2005). However, those studies were done based on a fixed C 0 2 capture

target, without considering how the changes in such a target would affect the extent o f the

energy penalty. One may expect a disproportion between the amount o f C 0 2 removed

12


Treated gas Condenser

CO2 product

Reflux drum

Cooler Reboiler

Rich amine pump Lean amine pump

Figure 1.3 Flow diagram of MEA-based CO2 absorption unit.

(Modified from Kohl and Nielsen, 1997)

13


MEA/Wateimake up

Treated gas

Cooler

Heat exchangerBlower

Cooler

oo00a

00

Condenser

CO2 product

Reflux drum

Pump

Steam

v _ (yl t̂HReboiler

Rich amine pump Lean amine pump

Figure 1.3 Flow diagram of MEA-based CO2 absorption unit.

(Modified from Kohl and Nielsen, 1997)

13


and the corresponding energy penalty as, from the fundamental viewpoint, the energy

requirement for the CO2 capture does not correlate in a proportional manner with the

efficiency of the CO2 capture unit. It is therefore worth examining if there is an optimal

point providing the most environmental benefit with the least energy penalty.

1.4 Research Objectives

This study is aimed at investigating the effects of the various operating and design

parameters on the improvement in the net efficiency of the pulverized coal-fired power

plants as well as the reduction in the emissions of GHGs from electricity generation by

coal. The key parameters governing the efficiency improvement are identified and used

to determine the optimal design and operating conditions that offer the maximum power

plant efficiency. The investigation focuses on both subcritical and supercritical

pulverized coal-fired power plants. The present study also examines how the net

efficiency of the power plants responds to the changes in the performance of the

integrated CO2 capture unit, thus helping identify the optimal capture target that offers

the least energy penalty per unit of CO2 captured. This study is carried out by first

developing a process-based computer model of pulverized coal-fired power plants that is

built on the principles of coal combustion, combustion chemistry, heat transfer from

combustion zone, combined material and energy balances, and thermodynamics of a

steam power cycle. Simulation of the developed model is then performed for a sensitivity

analysis using the rank correlation coefficient and the Monte Carlo simulation approaches

in order to arrive at the optimal operating and design conditions. In addition, the

levelized cost of electricity, the cost of electricity difference and the capital equivalent

14


and the corresponding energy penalty as, from the fundamental viewpoint, the energy

requirement for the CO2 capture does not correlate in a proportional manner with the

efficiency o f the CO2 capture unit. It is therefore worth examining if there is an optimal

point providing the most environmental benefit with the least energy penalty.

1.4 Research Objectives

This study is aimed at investigating the effects o f the various operating and design

parameters on the improvement in the net efficiency o f the pulverized coal-fired power

plants as well as the reduction in the emissions o f GHGs from electricity generation by

coal. The key parameters governing the efficiency improvement are identified and used

to determine the optimal design and operating conditions that offer the maximum power

plant efficiency. The investigation focuses on both subcritical and supercritical

pulverized coal-fired power plants. The present study also examines how the net

efficiency o f the power plants responds to the changes in the performance o f the

integrated CO2 capture unit, thus helping identify the optimal capture target that offers

the least energy penalty per unit o f CO2 captured. This study is carried out by first

developing a process-based computer model o f pulverized coal-fired power plants that is

built on the principles o f coal combustion, combustion chemistry, heat transfer from

combustion zone, combined material and energy balances, and thermodynamics o f a

steam power cycle. Simulation o f the developed model is then performed for a sensitivity

analysis using the rank correlation coefficient and the Monte Carlo simulation approaches

in order to arrive at the optimal operating and design conditions. In addition, the

levelized cost of electricity, the cost o f electricity difference and the capital equivalent

14


method are simulated to reveal the cost comparison between the subcritical and

supercritical pulverized coal-fired power plants. The sensitivity analysis of the cost

model is performed to investigate the individual effect of cost inputs on the cost of

electricity.

This thesis is divided into seven chapters. Introduction and research objectives are

presented in this chapter. Chapter 2 provides the basic principles of coal combustion and

its chemistry as well as a literature review of the coal-fired power plants and the CO2

capture unit. Details of development and simulation of the pulverized coal-fired power

plant model are given in Chapter 3. Simulation and optimization results for the

subcritical pulverized coal-fired power plant are reported in Chapter 4, whereas the

results for the supercritical pulverized coal-fired power plant are presented in Chapter 5.

Chapter 6 provides an economic implication of the study. Finally, conclusions drawn

from the study and recommendations for future work are given in Chapter 7.

15


method are simulated to reveal the cost comparison between the subcritical and

supercritical pulverized coal-fired power plants. The sensitivity analysis o f the cost

model is performed to investigate the individual effect o f cost inputs on the cost of

electricity.

This thesis is divided into seven chapters. Introduction and research objectives are

presented in this chapter. Chapter 2 provides the basic principles o f coal combustion and

its chemistry as well as a literature review of the coal-fired power plants and the CO2

capture unit. Details o f development and simulation o f the pulverized coal-fired power

plant model are given in Chapter 3. Simulation and optimization results for the

subcritical pulverized coal-fired power plant are reported in Chapter 4, whereas the

results for the supercritical pulverized coal-fired power plant are presented in Chapter 5.

Chapter 6 provides an economic implication of the study. Finally, conclusions drawn

from the study and recommendations for future work are given in Chapter 7.

15


Chapter Two

Literature Review and Fundamental

This chapter provides background in combustion process, basic principles of coal

combustion and its chemistry, as well as thermodynamics associated with a steam or

vapor power cycle. A literature review of the pulverized coal-fired power plants and the

CO2 capture unit is also given here.

2.1 Development of Combustion Process

Development of combustion process started in 1697 with Stahl proposing a

hypothetical combustion theory (Singer, 1991). During the 1700's, Joseph and Lavoisier

discovered that oxygen (02) in the atmosphere was an important element supporting

combustion of substances, paving the way for modern combustion theory (Singer, 1991).

Also during the 1700's, Black discovered latent heat of fusion and vaporization being

released through the combustion process (Singer, 1991). With a specific amount of heat

released, it was found that different substances offered different magnitudes of

temperature change during the combustion. This finding led to a concept of heat capacity

commonly used today. In 1824, French engineer Sadi Carnot proposed a reversible

power cycle known as "Carnot" cycle that was capable of producing work energy from a

theoretical operation running between two thermal reservoirs, i.e. a high-temperature heat

source and a low-temperature heat sink (Smith et al., 1996). During the mid 1800's, Joule

demonstrated how the work was able to transform into heat energy through water-based

16


Chapter Two

Literature Review and Fundamental

This chapter provides background in combustion process, basic principles o f coal

combustion and its chemistry, as well as thermodynamics associated with a steam or

vapor power cycle. A literature review o f the pulverized coal-fired power plants and the

CO2 capture unit is also given here.

2.1 Development of Combustion Process

Development o f combustion process started in 1697 with Stahl proposing a

hypothetical combustion theory (Singer, 1991). During the 1700’s, Joseph and Lavoisier

discovered that oxygen (O2) in the atmosphere was an important element supporting

combustion o f substances, paving the way for modem combustion theory (Singer, 1991).

Also during the 1700’s, Black discovered latent heat o f fusion and vaporization being

released through the combustion process (Singer, 1991). With a specific amount o f heat

released, it was found that different substances offered different magnitudes o f

temperature change during the combustion. This finding led to a concept o f heat capacity

commonly used today. In 1824, French engineer Sadi Carnot proposed a reversible

power cycle known as “Camof ’ cycle that was capable o f producing work energy from a

theoretical operation running between two thermal reservoirs, i.e. a high-temperature heat

source and a low-temperature heat sink (Smith et al., 1996). During the mid 1800’s, Joule

demonstrated how the work was able to transform into heat energy through water-based

16


experiments (Smith et al., 1996). All these findings are considered the fundamental

concept to the design and construction of the current power generation processes.

2.2 Chemistry of Coal Combustion

The operational concept of coal-fired power generation is to generate heat by

combusting coal (usually pulverized) in a furnace, and then transferring such heat to the

vapor power cycle where water serving as a working fluid is heated and transformed into

superheated & high-pressure steam that drives a series of turbines for electricity

generation. The coal combustion begins with evaporation of moisture in coal and

undergoes the process called "devolatilization" where coal particles release volatile

organic compounds under high temperature. Then, the coal particles are combusted at a

higher temperature after the volatile compounds are driven off. From the chemistry

viewpoint, the combustion of coal is associated with chemical reactions of oxygen (02) in

air with carbon (C) and other elements in coal including hydrogen (H), nitrogen (N), and

sulfur (S). Gaseous products of the coal combustion mainly consist of carbon dioxide

(CO2), water vapor (H20), sulfur dioxide (SO2), and nitrogen oxides (N0x) as well as

nitrogen (N2) and excess oxygen (02) from the air.

combustion are (de Nevers, 2000):

C + 02 _, CO2

The main reactions in the coal

(2.1)

H + y4 o, — y2H2o (2.2)

S + 02 ...„ SO2 (2.3)

0 + N 2 NO + N (2.4) -=---=-'-

17


experiments (Smith et al., 1996). All these findings are considered the fundamental

concept to the design and construction o f the current power generation processes.

2.2 Chemistry of Coal Combustion

The operational concept o f coal-fired power generation is to generate heat by

combusting coal (usually pulverized) in a furnace, and then transferring such heat to the

vapor power cycle where water serving as a working fluid is heated and transformed into

superheated & high-pressure steam that drives a series o f turbines for electricity

generation. The coal combustion begins with evaporation o f moisture in coal and

undergoes the process called “devolatilization” where coal particles release volatile

organic compounds under high temperature. Then, the coal particles are combusted at a

higher temperature after the volatile compounds are driven off. From the chemistry

viewpoint, the combustion of coal is associated with chemical reactions o f oxygen (O2) in

air with carbon (C) and other elements in coal including hydrogen (H), nitrogen (N), and

sulfur (S). Gaseous products o f the coal combustion mainly consist o f carbon dioxide

(CO2), water vapor (H2O), sulfur dioxide (SO2), and nitrogen oxides (NOx) as well as

nitrogen (N2) and excess oxygen (O2) from the air. The main reactions in the coal

combustion are (de Nevers, 2000):

c + o 2 • c o 2 (2 .1)

h +/<o 2 — y2H2o (2 .2 )

s + o 2 — s o 2 (2.3)

o + n 2 NO + N (2.4)

17


N+02 NO+0 (2.5)

NO + 72 0 2 NO2 (2.6)

N2 + 0 2 2N0 (2.7)

Note that the water vapor in the produced flue gas is also derived from free moisture in

coal. With a known composition of coal as well as the moisture content, the

concentrations of all combustion products in the flue gas stream can be calculated. In

addition to the gaseous products, the coal combustion also generates by-products

producing ashes and particulate matters that cannot be volatilized.

2.3 Heat of Combustion

Heat of combustion (qh) is primarily an integration of exothermic heats released

from chemical reactions listed above (Reactions 2.1 through 2.7). The qh in kJ/kg of coal

can be evaluated by (Perry et al., 1997)

qh = 2.326[146.58C + 568.78H + 29.4S — 6.58A — 51.53(0 + (2.8)

where C, H, S, A, 0, and N are weight percentages (on a dry basis) of carbon, hydrogen,

sulfur, ash, oxygen, and nitrogen, respectively. This dry basis heat of combustion is

usually referred to as "High Heating Value", HHV (Singer, 1991; Smith et al., 1996) of

which a fraction will be consumed through evaporation of the free moisture in the

supplied coal during the actual combustion process. This leads to a reduction in heat

available for steam generation in the vapor power cycle. The reduced heat of combustion

is commonly known as "Low Heating Value" (LHV), q1 ,

ql = qh — L •W (2.9)

18


N + 0 2 ^ NO + O (2.5)

N 0 + / 0 2 — N 0 2 (2.6)

N 2 + 0 2 = 2M ? (2.7)

Note that the water vapor in the produced flue gas is also derived from free moisture in

coal. With a known composition o f coal as well as the moisture content, the

concentrations of all combustion products in the flue gas stream can be calculated. In

addition to the gaseous products, the coal combustion also generates by-products

producing ashes and particulate matters that cannot be volatilized.

2.3 Heat of Combustion

Heat o f combustion (qh) is primarily an integration o f exothermic heats released

from chemical reactions listed above (Reactions 2.1 through 2.7). The qh in kJ/kg of coal

can be evaluated by (Perry et al., 1997)

qh = 2.326[l46.58C + 568.78H + 29.4S - 6.58A - 51.53{0 + JV)] (2.8)

where C, H, S, A, O, and N are weight percentages (on a dry basis) o f carbon, hydrogen,

sulfur, ash, oxygen, and nitrogen, respectively. This dry basis heat o f combustion is

usually referred to as “High Heating Value”, H H V (Singer, 1991; Smith et al., 1996) of

which a fraction will be consumed through evaporation o f the free moisture in the

supplied coal during the actual combustion process. This leads to a reduction in heat

available for steam generation in the vapor power cycle. The reduced heat o f combustion

is commonly known as “Low Heating Value” (LHV), q, ,

q , = q k - L - W (2.9)

18


where W represents mass of water vapor in the produced flue gas per unit mass of coal

burned, and L denotes the latent heat of water vaporization.

2.4 Steam Power Cycle

Coal-based electricity generation is commonly achieved through the use of the

steam power cycle that receives heat from the coal combustion and converts the heat into

work output in form of electricity. The "Rankine" cycle is the simplest steam power

cycle that was first introduced by William Rankine, a Scottish engineering professor, in

1859 (Singer, 1991; Smith et al., 1996). This basic steam cycle is composed of four main

components: (i) a boiler where the combustion heat is utilized for generating high-

pressure superheated steam, (ii) a turbine system driven by generated steam to produce

electricity, (iii) a condenser where low-pressure and low-quality steam exiting the turbine

system is condensed into saturated liquid water (or condensate), and (iv) a high-pressure

feedwater pump used for circulating liquid water back to the boiler. The relatively low

efficiency of the Rankine cycle lead to a modified cycle known as "Reheat Rankine"

cycle where reduced-energy steam extracted from a front part of the turbine system is

routed to the boiler for reheating before sent back to a next part of the turbine for further

electricity generation. The reheating process helps maintain a high energy level of the

superheated steam driving the turbine, thus providing additional work output that results

in an increase in the thermal efficiency of the steam cycle. A single reheat cycle with a

double casing steam turbine was implemented in actual power plants in the mid 1920's

and became the standard equipment in the late 1940's after successful invention of a

high-pressure boiler. A double reheat with triple casing steam turbine was introduced in

19


where W represents mass o f water vapor in the produced flue gas per unit mass o f coal

burned, and L denotes the latent heat o f water vaporization.

2.4 Steam Power Cycle

Coal-based electricity generation is commonly achieved through the use o f the

steam power cycle that receives heat from the coal combustion and converts the heat into

work output in form of electricity. The “Rankine” cycle is the simplest steam power

cycle that was first introduced by William Rankine, a Scottish engineering professor, in

1859 (Singer, 1991; Smith et al., 1996). This basic steam cycle is composed o f four main

components: (i) a boiler where the combustion heat is utilized for generating high-

pressure superheated steam, (ii) a turbine system driven by generated steam to produce

electricity, (iii) a condenser where low-pressure and low-quality steam exiting the turbine

system is condensed into saturated liquid water (or condensate), and (iv) a high-pressure

feedwater pump used for circulating liquid water back to the boiler. The relatively low

efficiency of the Rankine cycle lead to a modified cycle known as “Reheat Rankine”

cycle where reduced-energy steam extracted from a front part o f the turbine system is

routed to the boiler for reheating before sent back to a next part o f the turbine for further

electricity generation. The reheating process helps maintain a high energy level o f the

superheated steam driving the turbine, thus providing additional work output that results

in an increase in the thermal efficiency o f the steam cycle. A single reheat cycle with a

double casing steam turbine was implemented in actual power plants in the mid 1920’s

and became the standard equipment in the late 1940’s after successful invention of a

high-pressure boiler. A double reheat with triple casing steam turbine was introduced in

19


the 1970's. Also, the efficiency of the Reheat Rankine cycle can be further improved by

integrating a series of the feedwater heaters (FWHs) into the system to help raise

temperature of feedwater before entered the boiler. Several portions of the superheated

steam extracted from the turbine system serves as heating media for either open type

feedwater heaters (deaerator) or closed type feedwater heaters. This integrated system,

referred to as "Reheat-regenerative Rankine" cycle, is the conceptual system used in the

coal-fired power stations today. A simplified flow diagram of the Reheat-regenerative

Rankine cycle is given in Figure 2.1. The thermal efficiency of the steam cycle (r/th) can

be determined from the heat input from the boiler ( .0boiler) and the power output from the

cycle ( Wout ) as follows.

* out th = r. V)

boiler

(2.10)

According to Figure 2.1, the power output is produced from HP (High-pressure), IP

(Intermediate-pressure), and LP (Low-pressure) turbines. Therefore, the total power

output from these turbines (*Total ) can be expressed as

W T,total = E * HP,i E * IP,i E * LP,i i=1 i=1 i=1

(2.11)

where if>. , and Pi/Lp,1 denote the power output produced from section i of the HP,

IP, and LP turbines, respectively. Total pumping power input ( P,total) is the sum of

power input for each individual pump (Wpi ).

P

W P,total =IT /r/ P,i i=1

20

(2.12)


the 1970’s. Also, the efficiency o f the Reheat Rankine cycle can be further improved by

integrating a series o f the feedwater heaters (FWHs) into the system to help raise

temperature o f feedwater before entered the boiler. Several portions o f the superheated

steam extracted from the turbine system serves as heating media for either open type

feedwater heaters (deaerator) or closed type feedwater heaters. This integrated system,

referred to as “Reheat-regenerative Rankine” cycle, is the conceptual system used in the

coal-fired power stations today. A simplified flow diagram o f the Reheat-regenerative

Rankine cycle is given in Figure 2.1. The thermal efficiency o f the steam cycle {rjth) can

be determined from the heat input from the boiler ( QboUer) and the power output from the

cycle ( Wout) as follows.

According to Figure 2.1, the power output is produced from HP (High-pressure), IP

(Intermediate-pressure), and LP (Low-pressure) turbines. Therefore, the total power

output from these turbines ( WT total) can be expressed as

where WH P, W[Pi, and WLPJ denote the power output produced from section i o f the HP,

IP, and LP turbines, respectively. Total pumping power input ( Wptotal) is the sum of

pow er input for each individual pum p ( W P j ) .

■boiler

(2 .10)

m n o(2 .11)

(2 .12)(=i

20


Pump

Turbine

Condenser

Pump Feedwater heater

HP High pressure turbine IP Intermediate pressure turbine LP Low pressure turbine

Figure 2.1 Simple scheme of Reheat-regenerative Rankine cycle.

21


HP Turbine

Boiler

Condenser

PumpPump Feedwater heater

HP High pressure turbine IP Intermediate pressure turbineLP Low pressure turbine

Figure 2.1 Simple scheme o f Reheat-regenerative Rankine cycle.

21


The power output from the steam cycle then can be written as

Wow = W T ,total W P,total (2.13)

The net heat input from the boiler is the sum of the heat for producing main steam

(Amain steam) and reheated steam (a ). The general equation can be written as

Qboiler = Amain steam + QRH (2.14)

From the practical viewpoint, it is rather common to identify the performance of the

power station in terms of the net efficiency (Net) that combines the efficiency of both

steam power cycle (77th) and combustor or furnace (furnace). The net efficiency is often

used as an index that directly correlates the rate of the coal consumption ( ?he. / ) to the

power of electricity generation ( s * out ,net)•

HHV-based efficiency;

LHV-based efficiency;

rinet

y i

VV out,net

coal q h

Tr/out net 1 net

m =

coal • q1

(2.15a)

(2.15b)

where Wout,net is the net power output after all unit operations (e.g. environmental

abatement units) are supplied by the power output from the steam cycle.

2.5 Design and Operation of Pulverized Coal-Fired Power Plants

Construction of large-scale pulverized coal-fired power plants began after the

successful development of conceptual design of Reheat-regenerative Rankine cycle. This

22


The power output from the steam cycle then can be written as

Wout=WT'total- W P,total (2.13)

The net heat input from the boiler is the sum of the heat for producing main steam

( Qmain steam) and reheated steam ( QRH). The general equation can be written as

Qboiler ~ Qmain steam Q r H (2 .14)

From the practical viewpoint, it is rather common to identify the performance o f the

power station in terms o f the net efficiency ( rjnet) that combines the efficiency o f both

steam power cycle and combustor or furnace ( rjfurnace). The net efficiency is often

used as an index that directly correlates the rate o f the coal consumption ( mcoal) to the

power o f electricity generation ( Woul net).

HHV-based efficiency;

WV net ~ —1-—■ (2.15a)

™ COal '< lh

LHV-based efficiency;

0 , , , = - ^ - (2-15b)m c o a l'< ll

where Woutnet is the net power output after all unit operations (e.g. environmental

abatement units) are supplied by the power output from the steam cycle.

2.5 D esign and O peration o f Pulverized C oal-F ired Pow er Plants

Construction of large-scale pulverized coal-fired power plants began after the

successful development o f conceptual design of Reheat-regenerative Rankine cycle. This

22


cycle consists of a once-through boiler, a single reheat-condensing turbine system, a

vacuum condenser, a condensate and a boiler feed pumps, and a set of open and closed

feedwater heaters (FWHs). The once-through boiler generates superheated steam by

receiving and utilizing heat from the coal combustion through a series of heat-transfer

modules, including superheaters (SHs), reheaters (RHs), an evaporator, and an

economizer. These heat-transfer modules are arranged along the flow path of a hot flue

gas stream to recover heat in sequential steps. The superheated steam from the boiler is

routed to a multi-stage turbine system that is designed to extract heat from steam to three

different pressure ranges: the high-pressure (HP), the intermediate-pressure (IP) and the

low-pressure (LP) ranges. The exhaust steam leaving the HP turbine is sent back to the

boiler and heated by the reheaters to superheated temperature before entering to the IP

turbine. The reheated steam now undergoes a pressure reduction through the IP turbine,

resulting in exhaust steam routed directly to the LP turbine. Low quality steam leaving

the LP turbine is then cooled and condensed in the vacuum condenser at a pressure of as

low as 6 kPa. At this time, the condensate is pumped through a series of the feedwater

heaters run by steam extracted from the turbine system at different pressures. The heated

condensate known as feedwater is now introduced back to the boiler to complete the

steam cycle operation. Note that the desired number of the feedwater heaters is based on

a general construction guideline for power capacity above 200 MW (Drbal et al., 1996).

The higher the plant capacity is, the greater the number of the feedwater heaters are

required.

In the late 1980s, the pulverized coal-fired power plants usually operated under

conditions below critical pressure of water, i.e., a temperature of 538°C and a pressure of

23


cycle consists of a once-through boiler, a single reheat-condensing turbine system, a

vacuum condenser, a condensate and a boiler feed pumps, and a set o f open and closed

feedwater heaters (FWHs). The once-through boiler generates superheated steam by

receiving and utilizing heat from the coal combustion through a series o f heat-transfer

modules, including superheaters (SHs), reheaters (RHs), an evaporator, and an

economizer. These heat-transfer modules are arranged along the flow path o f a hot flue

gas stream to recover heat in sequential steps. The superheated steam from the boiler is

routed to a multi-stage turbine system that is designed to extract heat from steam to three

different pressure ranges: the high-pressure (HP), the intermediate-pressure (IP) and the

low-pressure (LP) ranges. The exhaust steam leaving the HP turbine is sent back to the

boiler and heated by the reheaters to superheated temperature before entering to the IP

turbine. The reheated steam now undergoes a pressure reduction through the IP turbine,

resulting in exhaust steam routed directly to the LP turbine. Low quality steam leaving

the LP turbine is then cooled and condensed in the vacuum condenser at a pressure o f as

low as 6 kPa. At this time, the condensate is pumped through a series o f the feedwater

heaters run by steam extracted from the turbine system at different pressures. The heated

condensate known as feedwater is now introduced back to the boiler to complete the

steam cycle operation. Note that the desired number of the feedwater heaters is based on

a general constmction guideline for power capacity above 200 MW (Drbal et al., 1996).

The higher the plant capacity is, the greater the number o f the feedwater heaters are

required.

In the late 1980s, the pulverized coal-fired power plants usually operated under

conditions below critical pressure o f water, i.e., a temperature o f 538°C and a pressure of

23


16.54 MPa. Such "subcritical" pulverized coal-fired power plants have offered the HHV-

based net efficiency of 37.6% (U.S.DOE, 1999). With the growing electricity demand

and the increasing environmental concern about GHG emissions, there has been the need

to improve the efficiency of the power generation cycle. Recently, the development of the

advanced material has allowed the power plants to operate under supercritical and

ultrasupercritical conditions. The supercritical technology helps improve power plant

efficiency to as high as 39.9% (HHV) while the ultra-supercritical would offer the net

efficiency of 41.4% (HHV) (U.S.DOE, 1999).

This study focuses on the 425 MW (gross output) subcritical and supercritical

pulverized coal-fired power plants. Configurations of the power plants are based on the

existing technology as demonstrated in Figures 2.2 and 2.3. The typical operating

conditions of these power plants are 530-600°C main steam and reheating temperatures,

290-370 kg/s main steam capacity, 15-20% excess air for the coal combustion, and 3-6%

pressure drop across the feedwater heaters (Singer, 1991; Drbal et al., 1996; U.S.DOE,

1999, Perry et al., 1997; Kakaras et al., 2002; Woodruff, 2005).

In addition to the steam cycle described above, an air preheater is also considered

the other important component of the typical pulverized coal-fired power plants as it

helps recover heat from the coal combustion that is otherwise wasted through the

discharged flue gas. The preheater for the pulverized coal-fired power plants is

Ljungstrom type which is capable of raising temperature of the incoming air to 250-

350°C (Singer, 1991; Chattopadhyay, 2000; Woodruff, 2005).

24


16.54 MPa. Such “subcritical” pulverized coal-fired power plants have offered the HHV-

based net efficiency o f 37.6% (U.S.DOE, 1999). With the growing electricity demand

and the increasing environmental concern about GHG emissions, there has been the need

to improve the efficiency o f the power generation cycle. Recently, the development o f the

advanced material has allowed the power plants to operate under supercritical and

ultrasupercritical conditions. The supercritical technology helps improve power plant

efficiency to as high as 39.9% (HHV) while the ultra-supercritical would offer the net

efficiency o f 41.4% (HHV) (U.S.DOE, 1999).

This study focuses on the 425 MW (gross output) subcritical and supercritical

pulverized coal-fired power plants. Configurations o f the power plants are based on the

existing technology as demonstrated in Figures 2.2 and 2.3. The typical operating

conditions o f these power plants are 530-600°C main steam and reheating temperatures,

290-370 kg/s main steam capacity, 15-20% excess air for the coal combustion, and 3-6%

pressure drop across the feedwater heaters (Singer, 1991; Drbal et al., 1996; U.S.DOE,

1999, Perry et al., 1997; Kakaras et al., 2002; Woodruff, 2005).

In addition to the steam cycle described above, an air preheater is also considered

the other important component o f the typical pulverized coal-fired power plants as it

helps recover heat from the coal combustion that is otherwise wasted through the

discharged flue gas. The preheater for the pulverized coal-fired power plants is

Ljungstrom type which is capable o f raising temperature o f the incoming air to 250-

350°C (Singer, 1991; Chattopadhyay, 2000; Woodruff, 2005).

24


Fu

rnac

e/B

oil

er

Boller feed pump

Condensate pump —t


Figure 2.2 Scheme of "subcritical" pulverized coal-fired power plant.



25


Furn

ace/

Boi

ler ^

_ T SffiEvaporator

Spray water

Condenser-Reheat

^CHjoi^er

fu '

Upper feedwater heater train^ Lower feedwater heater trpin

s<8 >A ir heate Deaerator

Boiler feed pump

Condensate pumpr*^>

Superheater ReheaterHigh pressure turbine Intermediate pressure turbine Low pressure turbine

FWH Feedwater heater G Generator

Figure 2.2 Scheme o f “subcritical” pulverized coal-fired power plant.



25


Fur

nace

/Boi

ler

Coal

Evaporator

II ►•11111 I ni• I 1

Air

eu

Upper fe dwater h ater train Lower feedwater he

is Merator

Boiler feed pump

LP

Condenser

Condensate pump

ter train


Figure 2.3 Scheme of "supercritical" pulverized coal-fired power plant.



26


Fur

nace

/Boi

ler

Coal

^1 I ̂ 1 'V1 I —

„ " , SH 2 m 2 S H I Evaporator

Spray water ICondenserReheat

Eco'nomizer

Lower feedwuter heater trainUpper feedwater h ater train

Air heatei __Deaerator‘t§F- 1

Condensate pump

SH SuperheaterBoiler feed pump RH Reheater

HP High pressure turbineIP Intermediate pressure turbineLP Low pressure turbineFWH Feedwater heaterG Generator

Figure 2.3 Scheme of “supercritical” pulverized coal-fired power plant.



26


2.6 CO2 Capture from Coal-Fired Flue Gas

The current environmental abatement units that help remove air pollutants from

the pulverized coal-fired flue gas are composed of a low NO. burner, a selective catalytic

reduction (SCR) unit, a particulate removal unit, and a flue gas desulfurization (FGD)

unit. The NO„ emission is regulated by a combination of the low-NO„ burner with about

65% NO. removal and the SCR unit with about 63% NO. removal. The particulate

matters released to the surrounding are controlled by an electrostatic precipitator (ESP)

with about 99.99% particulate removal. The SO2 emission discharged to the atmosphere

is limited by the FGD unit with about 96% SO2 removal (U.S.DOE, 1999). The gas

absorption process is considered the upcoming abatement unit that would be installed at a

downstream of the FGD unit to capture CO2 before the flue gas is discharged through the

stack (see Figure 2.4).

As mentioned earlier, gas absorption into an aqueous alkanolamine solution is the

most suitable and practical technology for capturing CO2 from low-pressure flue gas

streams. This technology has been well-established for more than a half century to work

successfully in gas treating services as well as chemical industries. The typical process

flow diagram of the CO2 absorption unit was illustrated earlier in Figure 1.3.

Alkanolamines used for the CO2 capture can be classified into three types:

primary, secondary, and tertiary alkanolamines. The primary alkanolamines include

monoethanolamine (MEA) and diglycolamine (DGA). The secondary alkanolamines are

diethanolamine (DEA) and diisopropanolamine (DIPA) while the tertiary alkanolamines

are triethanolamine (TEA) and N-methyldiethanolamine (MDEA). Among these

alkanolamines, the MEA solvent is the most popular solvent due to its high reactivity

27


2.6 C 0 2 Capture from Coal-Fired Flue Gas

The current environmental abatement units that help remove air pollutants from

the pulverized coal-fired flue gas are composed of a low NOx burner, a selective catalytic

reduction (SCR) unit, a particulate removal unit, and a flue gas desulfurization (FGD)

unit. The NOx emission is regulated by a combination o f the low-NOx burner with about

65% NOx removal and the SCR unit with about 63% NOx removal. The particulate

matters released to the surrounding are controlled by an electrostatic precipitator (ESP)

with about 99.99% particulate removal. The S 0 2 emission discharged to the atmosphere

is limited by the FGD unit with about 96% SO2 removal (U.S.DOE, 1999). The gas

absorption process is considered the upcoming abatement unit that would be installed at a

downstream of the FGD unit to capture CO2 before the flue gas is discharged through the

stack (see Figure 2.4).

As mentioned earlier, gas absorption into an aqueous alkanolamine solution is the

most suitable and practical technology for capturing CO2 from low-pressure flue gas

streams. This technology has been well-established for more than a half century to work

successfully in gas treating services as well as chemical industries. The typical process

flow diagram of the CO2 absorption unit was illustrated earlier in Figure 1.3.

Alkanolamines used for the CO2 capture can be classified into three types:

primary, secondary, and tertiary alkanolamines. The primary alkanolamines include

monoethanolamine (MEA) and diglycolamine (DGA). The secondary alkanolamines are

diethanolamine (DEA) and diisopropanolamine (DIPA) while the tertiary alkanolamines

are triethanolamine (TEA) and A-methyldiethanolamine (MDEA). Among these

alkanolamines, the MEA solvent is the most popular solvent due to its high reactivity

27


Coa

Furnace

Air

Low NOx burner

SCR

Air prebeater

SCR Selective Catalytic Reduction ESP Electrostatic Precipitator FGD Flue Gas Desulfurization MEA Monoethanolamine

ESP FGD I

Treated gas gas

Stack

--....1 MEA-based plant

CO2 product

CO2 compression

Figure 2.4 Schematic diagram of integration of environmental abatement units.

28


Furnace Treated

Low NOx burner

Stack

w vMEA-based plantAir prebeater

CO2 productSCR Selective Catalytic Reduction ESP Electrostatic PrecipitatorFGD Flue Gas DesulfurizationMEA Monoethanolamine

CO2 compression

Figure 2.4 Schematic diagram of integration o f environmental abatement units.

28


with CO2. However, it is well-known that capturing CO2 using the MEA solvent is the

energy-intensive operation. Integrating the CO2 capture unit into the pulverized coal-

fired power plants would result in a significant reduction in the net power output and also

the net efficiency of the power plants since a portion of steam normally used for

electricity generation within the steam cycle must be utilized for the CO2 capture activity.

The energy requirement of the MEA-based absorption process could be as high as 4800

kJ/kg CO2 captured for a capture target of 90%. (Sakwattanapong, 2005; Aroonwilas and

Veawab, 2007). The high energy intensity can be compromised by reducing the CO2

capture efficiency.

29


with CO2. However, it is well-known that capturing CO2 using the MEA solvent is the

energy-intensive operation. Integrating the CO2 capture unit into the pulverized coal-

fired power plants would result in a significant reduction in the net power output and also

the net efficiency o f the power plants since a portion o f steam normally used for

electricity generation within the steam cycle must be utilized for the CO2 capture activity.

The energy requirement o f the MEA-based absorption process could be as high as 4800

kJ/kg CO2 captured for a capture target o f 90%. (Sakwattanapong, 2005; Aroonwilas and

Veawab, 2007). The high energy intensity can be compromised by reducing the CO2

capture efficiency.

29


Chapter Three

Development of Coal-Fired Power Plant Model

This study was carried out by simulating the operation and performance of the

pulverized coal-fired power plants over wide ranges of design and operating conditions.

A process-based computer model for the subcritical and supercritical pulverized coal-

fired power plants was developed on the basis of coal combustion, combustion chemistry,

heat transfer from the combustion zone, combined material and energy balances, and the

thermodynamics of a steam power cycle for electricity generation. The model was written

in a Microsoft® Excel spreadsheet using Crystal Ball® software add-in to perform a

sensitivity analysis. Simulation of this model gave essential information on the coal

consumption rate, the thermal efficiency, the net efficiency, the power output, and also

the CO2 emission rate from the coal combustion. The following sections provide details

of the model development & simulation, the model validation, and the sensitivity analysis

conducted in this study.

3.1 Model Development

The simulation model was built according to typical configurations of the

pulverized coal-fired power plants shown in Figures 2.2 and 2.3. A series of process

modules was formulated specifically for individual process components that were put

together to form the complete system of power generation. The principles used in such

modules are highlighted next.

30


Chapter Three

Development of Coal-Fired Power Plant Model

This study was carried out by simulating the operation and performance o f the

pulverized coal-fired power plants over wide ranges o f design and operating conditions.

A process-based computer model for the subcritical and supercritical pulverized coal-

fired power plants was developed on the basis o f coal combustion, combustion chemistry,

heat transfer from the combustion zone, combined material and energy balances, and the

thermodynamics o f a steam power cycle for electricity generation. The model was written

in a Microsoft® Excel spreadsheet using Crystal Ball® software add-in to perform a

sensitivity analysis. Simulation o f this model gave essential information on the coal

consumption rate, the thermal efficiency, the net efficiency, the power output, and also

the CO2 emission rate from the coal combustion. The following sections provide details

o f the model development & simulation, the model validation, and the sensitivity analysis

conducted in this study.

3.1 Model Development

The simulation model was built according to typical configurations o f the

pulverized coal-fired power plants shown in Figures 2.2 and 2.3. A series o f process

modules was formulated specifically for individual process components that were put

together to form the complete system of power generation. The principles used in such

modules are highlighted next.

30


3.1.1 Furnace

Energy released from coal combustion in the furnace in kJ/s is derived from two

main components: LHV-based combustion heat (Q1 = mcoai • ql ) and waste heat recovered

from a hot flue gas via the air preheater ( 0 preheater)• With a known composition of coal

and a moisture content, the 0 1 can be calculated using Equations (2.8) and (2.9). A

general equation for furnace heat ( ) can be written as

Qfurnace = a+ Qpreheater (3.1)

This furnace heat is translated into the change in enthalpy of the combustion flue gas,

which can be evaluated from the sum of enthalpy change for each combustion product

( AI:I1) as follows

m

Qfurnace = E All i=i

(3.2)

The AiIi is sensible heat that causes an increase in flue gas temperature (7) as given

below

= frhiCpidT (3.3)

Where and Cpj represent mass flow rate and heat capacity of the combustion product

i, respectively. The mass flow rates of the combustion products can be calculated by

performing the material balance based on Reactions (2.1) through (2.7) presented in the

previous chapter. By combining Equations (3.2) and (3.3), the temperature of the flue gas

leaving the furnace (the combustion zone) to the boiler (the heat transfer zone) can be

determined.

31


3.1.1 Furnace

Energy released from coal combustion in the furnace in kJ/s is derived from two

main components: LHV-based combustion heat ( Q, = mcoal • qt) and waste heat recovered

from a hot flue gas via the air preheater ( Qpreheater). With a known composition of coal

and a moisture content, the Q, can be calculated using Equations (2.8) and (2.9). A

general equation for furnace heat ( Qfurnace) can be written as

Qfurnace Q l Qpreheater (^'1)

This furnace heat is translated into the change in enthalpy o f the combustion flue gas,

which can be evaluated from the sum of enthalpy change for each combustion product

(AH t) as follows

m

(h„,„. - T a m , (3.2)!=1

The AH i is sensible heat that causes an increase in flue gas temperature (7) as given

below

AH; = \m {CpJdT (3.3)

where mi and C . represent mass flow rate and heat capacity o f the combustion product

i, respectively. The mass flow rates o f the combustion products can be calculated by

performing the material balance based on Reactions (2.1) through (2.7) presented in the

previous chapter. B y com bining Equations (3 .2) and (3 .3), the temperature o f the flue gas

leaving the furnace (the combustion zone) to the boiler (the heat transfer zone) can be

determined.

31


3.1.2 Once-through Boiler

While traveling through the boiler unit, the hot combustion flue gas from the

furnace gives away its energy for the production of high quality steam driving the turbine

system. Relationship between the furnace heat (Q furnace) and the heat absorbed by the

boiler ( Oboder ) can be expressed as

Oboiler = 71 boiler • 0 furnace (3.4)

where r holl„ is the efficiency of the once-through boiler. Based on a general boiler

design, the Oboiler is the combined heat absorbed through four heat-transfer components:

an economizer ( •Oecoo), an evaporator ( a mp ), a superheater (QS, ), and a reheater ( ).

A general heat equation can be written as

Qboiler = 0econ Qevap QSH + Q (3.5)

3.1.3 Turbines and Pumps

Actual power extracted from the turbine ( Pkr ) can be determined from turbine

efficiency (iir ) and isentropic power ( ,r/kT ,isen) as follows

WT 717' • WT,isen (3.6)

According to the process configurations in Figures 2.2 and 2.3, electricity is produced

from a series of the HP, IP, and LP turbines. Several portions of steam are also extracted

from these turbines and used in the feedwater heaters. This results in a variation in a

mass flow rate of steam that passes through each turbine section. As such, in this study

32


3.1.2 Once-through Boiler

While traveling through the boiler unit, the hot combustion flue gas from the

furnace gives away its energy for the production o f high quality steam driving the turbine

system. Relationship between the furnace heat ( Qfurnace) and the heat absorbed by the

boiler ( Qboiler) can be expressed as

Qboiler Vboiler Qfurnace (^"4)

where rjboiler is the efficiency o f the once-through boiler. Based on a general boiler

design, the Qboiler is the combined heat absorbed through four heat-transfer components:

an economizer ( Qecon), an evaporator ( Qevap), a superheater ( QSH), and a reheater ( QRH).

A general heat equation can be written as

Qboiler = Qecon + Qevap + Q s H + QrH (3.5)

3.1.3 Turbines and Pumps

Actual power extracted from the turbine (WT) can be determined from turbine

efficiency (rjr ) and isentropic power ( WTJsen) as follows

» r = 7 r -»V*. (3-6)

According to the process configurations in Figures 2.2 and 2.3, electricity is produced

from a series o f the HP, IP, and LP turbines. Several portions o f steam are also extracted

from these turbines and used in the feedwater heaters. This results in a variation in a

mass flow rate of steam that passes through each turbine section. As such, in this study

32


the power produced from each turbine is determined from the combined power from

individual sections. Total power output from turbines :otar) can be expressed as

W T,total E W IP,i E W LP,i i=1 i=1 i=1

(3.7)

where TITHpi , and ii/Lpj denote the power output produced from section i of the HP,

IP, and LP turbines, respectively.

Power input for the feedwater pump ( ) can be calculated from

W P isen VV

=

P(3.8)

rip

where lip and PiTp,is„ are pump efficiency and isentropic power of pump, respectively.

Total pumping power ( Vrippoi ) is the sum of the power input for individual pumps ( )

P

W P,total = ZW P,i i=1

Power output from the steam cycle then can be written as

W ont = W T,total —WP,total

(3.9)

(3.10)

3.1.4 Feedwater Heaters

Heat transfer of each feedwater heater can be determined by using the energy

balance principle demonstrating that total enthalpy of fluids entering the heater is equal to

total enthalpy leaving the heater. An energy equation of the feedwater heater can be

written as

33


the power produced from each turbine is determined from the combined power from

individual sections. Total power output from turbines ( WT total) can be expressed as

m n o

(3-7>1=1 1=1 1=1

where WHP i , W[Pi, and WLPi denote the power output produced from section i o f the HP,

IP, and LP turbines, respectively.

Power input for the feedwater pump (Wp ) can be calculated from

WWP = - ^ ~ (3.8)

V p

where rjp and WP isen are pump efficiency and isentropic power o f pump, respectively.

Total pumping power ( Wp total) is the sum of the power input for individual pumps ( WP i )

(3.9)1=1

Power output from the steam cycle then can be written as

Wout=WTitotal- W P,otal (3.10)

3.1.4 Feedwater Heaters

Heat transfer o f each feedwater heater can be determined by using the energy

balance principle demonstrating that total enthalpy of fluids entering the heater is equal to

total enthalpy leaving the heater. An energy equation o f the feedwater heater can be

written as

33


(3.11)

where and h. are mass flow rate and specific enthalpy of the stream i entering or

leaving the heater.

It should be noted that the working fluid in the steam-power cycle is water. Its

properties, especially enthalpy and entropy, depend on temperature and pressure within

the cycle. To calculate performance of the individual process components described

above, empirical correlations of steam properties are considerably significant. In this

study, the steam properties obtained from Perry et al. (1997) were regressed using

multiple linear and/or non-linear regressions by an approach of the Monte Carlo

simulation. An algorithm flowchart for data regression is given in Figure 3.1. The

enthalpy and entropy correlations of steam are

h= f(P,T,$).z1(a1P+b1P2 + ...+ di ln P)+ z2 (a2T + b2T2 +...+d2 1nT) (3.12a)

+ Z3 (a3s+b3s 2 +...+d3 lns)+e0

s= f(P,T,h )= zi(aiP + biP2 + ...+ di lnP)+ z2(a2T + b2T2 +...+d2 1nT) (3.12b)

+z3(a3h+b3h 2 +...+d3 lnh)+e0

where P, T, h ands denote pressure, temperature, specific enthalpy and specific entropy,

respectively. The coefficient z, , z2 and z3 are 0 or 1, and and ea are the

real number also listed in Appendix A.

Simulation of the developed model was done through computational steps as

illustrated in Figure 3.2. The calculations started with the input of the operating and

design parameters including the net power output of the power station, the coal

composition, the percentage of the excess air for the coal combustion, the temperature

34


m it

Y l{mi -hi )in (3 .H )!=1 1-1

where mi and ht are mass flow rate and specific enthalpy of the stream i entering or

leaving the heater.

It should be noted that the working fluid in the steam-power cycle is water. Its

properties, especially enthalpy and entropy, depend on temperature and pressure within

the cycle. To calculate performance o f the individual process components described

above, empirical correlations o f steam properties are considerably significant. In this

study, the steam properties obtained from Perry et al. (1997) were regressed using

multiple linear and/or non-linear regressions by an approach o f the Monte Carlo

simulation. An algorithm flowchart for data regression is given in Figure 3.1. The

enthalpy and entropy correlations o f steam are

h = f ( P , T , s ) = z I ( a IP + blP 2 +... + d 3 lnP ) + z 2(a 2T + b2T 2 +... + d 2 InT)(3.12a)

+ z 3(a 3s + b3s +... + d 3 lns) + e0

s = f ( P , T , h ) = z 1( a 1P + bIP 2 +... + d j l n P ) + z 2( a 2T + b2T 2 +... + d 2 InT)(3.12b)

+ z 3(a 3h + b3h 2 +... + d 3 lnh) + e0

where P, T, h and s denote pressure, temperature, specific enthalpy and specific entropy,

respectively. The coefficientz , , z 2 and z 3 are 0 or 1, and a, 3,b1 3 ,...,dl 3 and e0are the

real number also listed in Appendix A.

Simulation o f the developed model was done through computational steps as

illustrated in Figure 3.2. The calculations started with the input o f the operating and

design parameters including the net power output o f the power station, the coal

composition, the percentage o f the excess air for the coal combustion, the temperature

34


Multiple linear/non-linear equations

Guess a new set of coefficients

I 1

n n

e2 = v E(.. i,steam table — Y ixorrelationi=1 i=l

End

Data of steam properties from

steam table

Figure 3.1 Regression flowchart for correlating steam properties.

35


No

Yes

End

Guess a new set of coefficients

Data of steam properties from

steam table

Multiple linear/non-linear equations

s r = E e * = H ( y i,steam table V i,correlation )i=l i - l

Figure 3.1 Regression flowchart for correlating steam properties.

35


Start

Parameter Input: • Coal composition (C, H, N, S, 0, ash and moisture) • % excess air • Net power output • Temperatures (main steam, reheated steam, preheated air) • Pressures (boiler, condenser, FWHs) • Pressures of steam extracted from turbines • Pressure drops (boiler, FWHs) • Efficiency (boiler, turbines)

Calculations for Coal Combustion:

• Flue gas composition • Furnace heat • Flue gas temperature

Calculations for Steam Cycle: • Enthalpy of each steam • Mass fraction of each stream • Work from turbines • Work for pumps • Work output • Mass flow of steam

1

Calculations for Plant Performance: • Rate of coal consumption • Thermal efficiency of steam cycle • Net efficiency of power station

Calculations for Plant Emissions: • SO2 emission rate • NO„ emission rate • CO2 emission rate • PM emission rate

Figure 3.2 Computational algorithm of developed power plant model.

36


Parameter Input:• Coal composition (C, H, N, S, O, ash and moisture)• % excess air• Net power output• Temperatures (main steam, reheated steam, preheated air)• Pressures (boiler, condenser, FWHs)• Pressures of steam extracted from turbines• Pressure drops (boiler, FWHs)• Efficiency (boiler, turbines)

Start

Calculations for Plant Performance:• Rate of coal consumption• Thermal efficiency of steam cycle• Net efficiency of power station


• Flue gas composition• Furnace heat• Flue gas temperature

Calculations for Plant Emissions:• SO2 emission rate• NOx emission rate• C 02 emission rate• PM emission rate

Calculations for Steam Cycle:• Enthalpy of each steam• Mass fraction of each stream• Work from turbines• Work for pumps• Work output• Mass flow of steam

Figure 3.2 Computational algorithm of developed power plant model.

36


and pressure of process streams as well as the efficiency of process components (i.e. the

furnace, the boiler, the turbine and the pump). After the input step, the calculations were

done in parallel for the combustion of coal and the steam cycle. For the coal combustion,

flue gas composition was calculated on the basis of the material balance and presented as

percentages of N2, 02, CO2, H2O, SO2, and NOR. The furnace heat and the flue gas

temperature were then calculated. For the steam cycle, the calculations were started by

determining the enthalpy of each process stream based on the input operating conditions.

Mass fractions of individual process streams within the steam cycle were then calculated

by performing both energy and the material balances for all process components. At this

point, the calculated mass fractions and enthalpies were used for calculating works

associated with the turbines and pumps as well as the net work output per unit mass of

steam generated and rejected from the boiler and condenser, respectively. With the

specified power output in MW, the mass flow rates of steam at different process locations

were identified. Combining calculated results from both the coal combustion and steam

cycle provided information on the coal consumption rate, the net efficiency of power

stations and also the emission rates of the air pollutants, particularly NOR, particulate

matters (PM), SO2, and CO2. It is noted that the emission rate of NO was numerically

calculated by the relationship among molar flowrate of N2 and 02, reaction equilibrium

(Kr) and flame temperature in the furnace. The emission rate of PM was approximately

calculated by emission factors based on percentage by weight of ash in coal. These

calculations are demonstrated in Appendix A.

37


and pressure o f process streams as well as the efficiency o f process components (i.e. the

furnace, the boiler, the turbine and the pump). After the input step, the calculations were

done in parallel for the combustion o f coal and the steam cycle. For the coal combustion,

flue gas composition was calculated on the basis o f the material balance and presented as

percentages o f N2, 0 2, C 0 2, H20 , S 0 2, and NOx. The furnace heat and the flue gas

temperature were then calculated. For the steam cycle, the calculations were started by

determining the enthalpy o f each process stream based on the input operating conditions.

Mass fractions of individual process streams within the steam cycle were then calculated

by performing both energy and the material balances for all process components. At this

point, the calculated mass fractions and enthalpies were used for calculating works

associated with the turbines and pumps as well as the net work output per unit mass of

steam generated and rejected from the boiler and condenser, respectively. With the

specified power output in MW, the mass flow rates o f steam at different process locations

were identified. Combining calculated results from both the coal combustion and steam

cycle provided information on the coal consumption rate, the net efficiency of power

stations and also the emission rates o f the air pollutants, particularly NOx, particulate

matters (PM), S 0 2, and C 0 2. It is noted that the emission rate o f NOx was numerically

calculated by the relationship among molar flowrate o f N2 and 0 2, reaction equilibrium

(Kp) and flame temperature in the furnace. The emission rate o f PM was approximately

calculated by emission factors based on percentage by weight o f ash in coal. These

calculations are demonstrated in Appendix A.

37


3.2 Model Validation

The developed model was validated by comparing simulation results from this

study with data reported by the U.S.DOE (1999) and Kakaras et al. (2002). The

comparison was made under identical operating conditions as listed in Table 3.1. Note

that the previous studies provided no information on several important parameters,

including the temperature of the preheated air, the percentage of the excess air, as well as

the efficiency of the boiler and turbines. In this study, values of such parameters were

assigned in ranges in order to cover all possible operational scenarios. As a result, the

simulation outputs are also reported in ranges as shown in the table. It is clear that the

simulation results obtained from this study agree well with the literature data in the two

cases, thus validating the developed model.

3.3 Sensitivity Analysis and Performance Optimization

After the development of the power plant model, the sensitivity analysis by an

approach of the rank correlation coefficient was performed to reveal how individual

process parameters influence the performance of the pulverized coal-fired power plants,

particularly the net efficiency, the rate of coal consumption and CO2 emissions. In this

study, the analysis was carried out using a Monte Carlo simulation in which the general

concept was to randomly select values for all input parameters that were used to calculate

model outputs. This random-approach simulation was repeated for a number of trials

(30000 in this study), sufficient for establishing a correlation between input parameters

and output results and providing knowledge of the maximum and/or minimum output

values in order to reveal the optimal solution for the operation and design of the

38


3.2 Model Validation

The developed model was validated by comparing simulation results from this

study with data reported by the U.S.DOE (1999) and Kakaras et al. (2002). The

comparison was made under identical operating conditions as listed in Table 3.1. Note

that the previous studies provided no information on several important parameters,

including the temperature o f the preheated air, the percentage o f the excess air, as well as

the efficiency of the boiler and turbines. In this study, values o f such parameters were

assigned in ranges in order to cover all possible operational scenarios. As a result, the

simulation outputs are also reported in ranges as shown in the table. It is clear that the

simulation results obtained from this study agree well with the literature data in the two

cases, thus validating the developed model.

3.3 Sensitivity Analysis and Performance Optimization

After the development o f the power plant model, the sensitivity analysis by an

approach of the rank correlation coefficient was performed to reveal how individual

process parameters influence the performance o f the pulverized coal-fired power plants,

particularly the net efficiency, the rate o f coal consumption and CO2 emissions. In this

study, the analysis was carried out using a Monte Carlo simulation in which the general

concept was to randomly select values for all input parameters that were used to calculate

model outputs. This random-approach simulation was repeated for a number o f trials

(30000 in this study), sufficient for establishing a correlation between input parameters

and output results and providing knowledge o f the maximum and/or minimum output

values in order to reveal the optimal solution for the operation and design o f the

38


Table 3.1 Comparison between simulation results in this study and published data.

Description Case-1 (This study - U.S.DOE,

1999)

Case-2 (This study - Kakaras et al.,

2002) Coal type Illinois #6 Greek coal Net power output (MW) 397.0 336.0 Boiler temperature (°C) 538.0 536.0 Reheat temperature (°C) 538.0 540.0 HP turbine

1st stage-extract pressure (MPa) 4.16 3.54 IP turbine

l at stage-extract pressure (MPa) 1.92 2.00 r d stage-extract pressure (MPa) 1.21 1.05 ,-.rd .5 stage-extract pressure (MPa) - 0.518

LP turbine 1st stage-extract pressure (MPa) 0.46 0.223 r d stage-extract pressure (MPa) 0.165 0.074 3rd

stage-extract pressure (MPa) 0.088 0.031 4th stage-extract pressure (MPa) 0.0430 0.0060 5th stage-extract pressure (MPa) 0.0068 -

Discharge pressure of boiler feed pump (MPa)

20.00 24.65

Discharge pressure of condensate pump (MPa)

2.275 1.83

Preheated air temperature (°C)a (250.0-350.0) (250.0-350.0) % excess air a (15.0-20.0) (15.0-20.0) Pressure drop in FWHs (%) 3.0 3.7 Pressure drop in boiler (%) 9.0 22.0 Boiler efficiency (%)a (90.0-92.0) (90.0-92.0) Turbine efficiency (%)a (90.0-92.0) (90.0-92.0)

U.S.DOE, This study Kakaras et This study Performance 1999 al., 2002

Net efficiency (%) 37.6 35.4-38.5 37.1 34.6-38.1 Coal consumption (kg/sec) 39.0 37.9-40.4 162.3 157.2-169.5 CO2 emission (kg/MWh) 837 818-871 - 1207-1302 SO2 emission (kg/MWh) 1.42 1.39-1.48 - 2.19-2.36 NOx emission (kg/MWh) 1.86 2.17-2.05 - 0.53-0.64 PM emission (kg/MWh) 0.12 0.17-0.18 - 0.82-0.89

a Values were assigned in this study.

39


Table 3.1 Comparison between simulation results in this study and published data.

Description Case-1 (This study - U.S.DOE,

1999)

Case-2(This study - Kakaras et al.,

2002)Coal type Illinois #6 Greek coalNet power output (MW) 397.0 336.0Boiler temperature (°C) 538.0 536.0Reheat temperature (°C) 538.0 540.0HP turbine

1st stage-extract pressure (MPa) 4.16 3.54IP turbine

1st stage-extract pressure (MPa) 1.92 2.002nd stage-extract pressure (MPa) 1.21 1.053rd stage-extract pressure (MPa) - 0.518

LP turbine1st stage-extract pressure (MPa) 0.46 0.2232nd stage-extract pressure (MPa) 0.165 0.0743rd stage-extract pressure (MPa) 0.088 0.0314th stage-extract pressure (MPa) 0.0430 0.00605th stage-extract pressure (MPa) 0.0068 -

Discharge pressure of boiler feed 20.00 24.65pump (MPa)Discharge pressure of condensate 2.275 1.83pump (MPa)Preheated air temperature (°C)a (250.0-350.0) (250.0-350.0)% excess aira (15.0-20.0) (15.0-20.0)Pressure drop in FWHs (%) 3.0 3.7Pressure drop in boiler (%) 9.0 22.0Boiler efficiency (%)a (90.0-92.0) (90.0-92.0)Turbine efficiency (%)a (90.0-92.0) (90.0-92.0)

PerformanceU.S.DOE,

1999This study Kakaras et

al., 2002This study

Net efficiency (%) 37.6 35.4-38.5 37.1 34.6-38.1Coal consumption (kg/sec) 39.0 37.9-40.4 162.3 157.2-169.5C 02 emission (kg/MWh) 837 818-871 - 1207-1302S 02 emission (kg/MWh) 1.42 1.39-1.48 - 2.19-2.36NOx emission (kg/MWh) 1.86 2.17-2.05 - 0.53-0.64PM emission (kg/MWh) 0.12 0.17-0.18 - 0.82-0.89

a Values were assigned in this study.

39


pulverized coal-fired power plants. The following subsections are a brief description of

the Monte Carlo simulation and the rank correlation coefficient.

3.3.1 Monte Carlo Simulation

The Monte Carlo simulation is the stochastic method in which the concept is to

randomly select values of input parameters, and then perform the simulation in order to

observe a variation in the output values. This method is normally used for simulating a

real system by investigating different scenarios under uncertainty conditions. The

simulation result is on the basis of a probabilistic risk analysis. This work presents the

sensitivity analysis by applying the Monte Carlo simulation with various probabilistic

distributions as concluded in Table 3.2. The result of the sensitivity analysis clearly

identified which input process parameters contributed to changes in the output values. In

addition, the incorporation between the Monte Carlo simulation and the rank correlation

coefficient (see details in the next subsection) helps identify significance levels for

influential parameters in terms of the correlation coefficient lying between -1 and 1. If the

input has a significant effect on the output, the corresponding correlation coefficient will

be very high (nearly either -1 or 1). A positive coefficient represents that increasing the

input will increase the output whereas the negative coefficient represents that increasing

the input will decrease the output. The Monte Carlo simulation in this study was

performed using Crystal Ball® software as an add-in to Microsoft Excel®. The

relationship between the Monte Carlo simulation and the developed model is

demonstrated in Figure 3.3.

40


pulverized coal-fired power plants. The following subsections are a brief description of

the Monte Carlo simulation and the rank correlation coefficient.

3.3.1 Monte Carlo Simulation

The Monte Carlo simulation is the stochastic method in which the concept is to

randomly select values o f input parameters, and then perform the simulation in order to

observe a variation in the output values. This method is normally used for simulating a

real system by investigating different scenarios under uncertainty conditions. The

simulation result is on the basis o f a probabilistic risk analysis. This work presents the

sensitivity analysis by applying the Monte Carlo simulation with various probabilistic

distributions as concluded in Table 3.2. The result o f the sensitivity analysis clearly

identified which input process parameters contributed to changes in the output values. In

addition, the incorporation between the Monte Carlo simulation and the rank correlation

coefficient (see details in the next subsection) helps identify significance levels for

influential parameters in terms of the correlation coefficient lying between -1 and 1. If the

input has a significant effect on the output, the corresponding correlation coefficient will

be very high (nearly either -1 or 1). A positive coefficient represents that increasing the

input will increase the output whereas the negative coefficient represents that increasing

the input will decrease the output. The Monte Carlo simulation in this study was

performed using Crystal Ball® software as an add-in to Microsoft Excel®. The

relationship between the Monte Carlo simulation and the developed model is

demonstrated in Figure 3.3.

40


Table 3.2 Type of distribution curves used in this study.

Type of Distribution

Equation

Uniform distribution

1 f(x) (3.13) =

-

Where, 0, = minimum

02 = maximum

Normal distribution f(x) — 1 (x — p ) 21 (3.14) exp[

cr-571- 20-2—oo < x < -Foo Where,

• = mean

o- = standard deviation

Purpose

• It is used to represent the variability of randomness under valid ranges, i.e., the minimum and the maximum.

• All variability within the valid ranges are likely equal to occur.

• It is no valid range of the minimum and maximum.

• The variability of randomness is based on the nominal value and the standard deviation.

• Almost the variability of randomness is most likely to occur in the nominal value but the rest are symmetrically occurred across the nominal value.

• The standard deviation indicates how far the variability of randomness could occur.

Beta distribution

f(x) .__[ +16) i x"-, •(1—xr (3.15a) l(a)•F( /3)

Where,

/(x) = V' • e-jix (3.15b)

a = alpha = beta

• It is used to represent the variability of randomness under the valid ranges, i.e., the minimum and the maximum.

• It is used to represent the variability of randomness under either in percentage or in fractions.

• The percentage or the fraction of possible occurrence is specified as alpha or beta parameter.

• The negative skew implies that the alpha is greater than the beta, but positive skew implies vice versa.

Triangular distribution

f (x) =

h(x — 01 ) if 0, < x < 1

if 1 < x < 0,

(3.16a) 1 — 0,

h(02 — x)

0, —1

Where, 1 = Likeliest

h 2

(3.16b) = 0, — 0,

• It is used to represent the variability of randomness under the valid ranges, i.e., the minimum and the maximum.

• It is used to represent the variability of randomness falling mostly near the likeliest number under the triangular-shaped distribution.

(Source: Crystal Ball, 2004)

41


Table 3.2 Type of distribution curves used in this study.

Type of Equation PurposeDistribution___________________Uniform idistribution = q _q

9x < x < 02 Where,

0, = minimum02 = maximum

• It is no valid range of the(3.14) minimum and maximum.

• The variability of randomness is based on the nominal value and the standard deviation.

• Almost the variability of randomness is most likely to occur in the nominal value but the rest are symmetrically occurred across the nominal value.

• The standard deviation indicates how far the variability of randomness could occur.

Normaldistribution f(x) = -

1rexp

12c t

-0 0 < X < + 00

Where,H = mean a = standard deviation

( x - p f

• It is used to represent the variability of randomness under valid ranges, i.e., the minimum and the maximum.

• All variability within the valid ranges are likely equal to occur.

Betadistribution f ( x ) =

H a + P)

Where,

r ( x ) = ^ - ' - e %a = alpha P = beta

(3.15b)

It is used to represent thevariability of randomness under the valid ranges, i.e., the minimum and the maximum.It is used to represent thevariability of randomness under either in percentage or infractions.The percentage or the fraction of possible occurrence is specified as alpha or beta parameter.The negative skew implies that the alpha is greater than the beta, but positive skew implies vice versa.

Triangulardistribution

/(* ) =

Where,/

h(x - 0,)i - e l

h(92 - x )e1-i

Likeliest2

if 9X < x < I(3.16a)

o,-o,(3.16b)

It is used to represent thevariability of randomness under the valid ranges, i.e., the minimum and the maximum.It is used to represent thevariability of randomness falling mostly near the likeliest numberunder the triangular-shapeddistribution.

(Source: Crystal Ball, 2004)

41


Start

i

r Parameter Input: ".. • Coal composition (C, H, N, S, 0, ash and moisture) • % excess air • Net power output • Temperatures (main steam, reheated steam, preheated air) • Pressures (boiler, condenser, FWHs) • Pressures of steam extracted from turbines • Pressure drops (boiler, FWHs) • Efficiency (boiler, turbines)

s Calculations for Coal Combustion:

• Flue gas composition • Furnace heat • Flue gas temperature

$ Calculations for Steam Cycle:

• Enthalpy of each steam • Mass fraction of each stream • Work from turbines • Work for pumps • Work output • Mass flow of steam

-- — n 1 I I t I I 1 1 I 1 I 1 I 1 I I 1 1 t 1 1 1 I I I I i 1 I

Calculations for Plant Performance: • Rate of coal consumption • Thermal efficiency of steam cycle • Net efficiency of power station

1 Calculations for Plant Emissions:

• SO2 emission rate • NO„ emission rate • CO2 emission rate • PM emission rate

1

Monte Carlo Simulation and Rank Correlation Coefficient

Figure 3.3 Developed power plant model and Monte Carlo simulation.

42


Start

Parameter Input:Coal composition (C, H, N, S, O, ash and moisture)% excess air Net power outputTemperatures (main steam, reheated steam, preheated air) Pressures (boiler, condenser, FWHs)Pressures of steam extracted from turbines Pressure drops (boiler, FWHs)Efficiency (boiler, turbines)


• Flue gas composition• Furnace heat• Flue gas temperature

Calculations for Steam Cycle:• Enthalpy of each steam• Mass fraction of each stream• Work from turbines• Work for pumps• Work output• Mass flow of steam

Calculations for Plant Performance:• Rate of coal consumption• Thermal efficiency of steam cycle• Net efficiency of power station

Calculations for Plant Emissions:• S 02 emission rate• NOx emission rate• C 02 emission rate• PM emission rate

T

M onte Carlo Sim ulation and R ank C orrelation Coefficient

Figure 3.3 Developed power plant model and Monte Carlo simulation.

42


3.3.2 Rank Correlation Coefficient

The most recognized statistic methods for calculating the correlation coefficients

are (i) an ordinary correlation coefficient and (ii) a rank correlation coefficient. The rank

correlation technique was chosen in this study because it was able to handle the input and

output data that did not have a normal or a uniform distribution. The coefficient can be

calculated from the following equation.

n n

nExiyi — xi E yi

R=

11 n Xi2 —(n I

2

x i ) ni — (E

2

y i 3 /2Z

i=1 i=1 i=1 i=1

(3.17)

where xi and yi denote the data points of input and output, and n represents the number of

data points in a sample. A flowchart demonstrating ranking algorithms is given in Figure

3.4.

43


3.3.2 Rank Correlation Coefficient

The most recognized statistic methods for calculating the correlation coefficients

are (i) an ordinary correlation coefficient and (ii) a rank correlation coefficient. The rank

correlation technique was chosen in this study because it was able to handle the input and

output data that did not have a normal or a uniform distribution. The coefficient can be

calculated from the following equation.

R = 1=1 1=1 1=1

- > I > 2 - [ ! > , •v 1=1 y V i=i v i=i y

(3.17)

i=i

where x, and y t denote the data points o f input and output, and n represents the number o f

data points in a sample. A flowchart demonstrating ranking algorithms is given in Figure

3.4.

43


4D

0

Step la

10.75

10.96

17.97

10.63

16.74

14.68

11.35

11.33

10.94

15.05

11.68

13.90

11.91

10.44

11.63

11.21

13.47

11.97

13.25

12.59

Step 2b Step 3 Step 4'

10.44 (10.44,1) 3

10.63 (10.63,2) 5

1 10.75 2 10'

(10.75,3) 3 Ob.

20

10.94 (10.94,4) 2

10.96 (10.96,5) 19

11.21 (11.21,6) 17

11.33 (11.33,7) 8

11.35 (11.35,8) 7

11.63 (11.63,9) 4

11.68 (11.68,10) 18

11.91 (11.91,11) 10

11.97 (11.97,12) 16

12.59 (12.59,13) 11

13.25 (13.25,14) 1

13.47 (13.47,15) 9

13.90 (13.90,16) 6

14.68 (14.68,17) 15

15.05 (15.05,18) 12

16.74 (16.74,19) 14

17.97 (17.97,20) 13

a Raw data before ranked from the minimum to the maximum number. As shown in the figure, it is the example of a small set which contains only 20 data points. b New data after ranked from the minimum to the maximum. In this study, one set of data has 30000 numbers. Thus a quick sort algorithm is necessary in case developing own algorithm (Martin, 1971).

All values ranked will be substituted into parameter x of Equation (3.17). Another set of raw data will be ranked by using the same algorithm and put into parameter y of Equation (3.17).

Figure 3.4 Basic flowchart for ranking algorithm.

44


S tep l a S tep 2b S tep 3 S tep 4C

10.75 10.44 (10.44,1) 310.96 10.63 (10.63,2) 517.97 1 10.75 2 „ (10.75,3) 3 „ 2010.63

w10.94 (10.94,4) 2

16.74 10.96 (10.96,5) 1914.68 11.21 (11.21,6) 1711.35 11.33 (11.33,7) 811.33 11.35 (11.35,8) 710.94 11.63 (11.63,9) 415.05 11.68 (11.68,10) 1811.68 11.91 (11.91,11) 1013.90 11.97 (11.97,12) 1611.91 12.59 (12.59,13) 1110.44 13.25 (13.25,14) 111.63 13.47 (13.47,15) 911.21 13.90 (13.90,16) 613.47 14.68 (14.68,17) 1511.97 15.05 (15.05,18) 1213.25 16.74 (16.74,19) 1412.59 17.97 (17.97,20) 13

a Raw data before ranked from the minimum to the maximum number. As shown in the figure, it is the example of a small set which contains only 20 data points.b New data after ranked from the minimum to the maximum. In this study, one set of data has 30000 numbers. Thus a quick sort algorithm is necessary in case developing own algorithm (Martin, 1971). c All values ranked will be substituted into parameter x of Equation (3.17). Another set of raw data will be ranked by using the same algorithm and put into parameter y of Equation (3.17).

Figure 3.4 Basic flowchart for ranking algorithm.


3.3.3 Ranges of Input Parameters

Table 3.3 provides ranges of input parameters for the sensitivity analysis. (also

see Figures 3.5 and 3.6 for identified points of input) These values were based on typical

operating conditions and practical appearances of the subcritical and supercritical

pulverized coal-fired power plants. Note that type of data distributions for each

parameter was also provided, as it was required for input selection process during the

Monte Carlo simulation. The followings are the highlights of the primary assumptions for

the analysis.

• Inlet pressures of the HP, IP, and LP turbines as well as the backpressure were the

controllable operating conditions. They were defined as uniform distribution.

• Boiler temperature was ranged from 530 to 600°C. This parameter could not be

set at a specific value because it was changed with other factors such as the excess

air and the combustion temperature. The boiler temperature could be significantly

varied within a range of —10 to 5°C (Chattopadhyay, 2000). To handle the

asymmetric range of variation, the beta distribution was assigned for the Monte

Carlo simulation.

• The amount of air supplied to the furnace was assigned to be more than the

theoretical requirement, thus preventing incomplete combustion. The percentage

of the excess air fed into the system was ranged from 15 to 20% (Woodruff et al.,

2005), which was defined as the beta distribution.

• Pressure drop across the tube-side of the feedwater heaters ranged from 3 to 6%.

(Drbal et al., 1996) This parameter was defined as the normal distribution

45


3.3.3 Ranges of Input Parameters

Table 3.3 provides ranges o f input parameters for the sensitivity analysis, (also

see Figures 3.5 and 3.6 for identified points o f input) These values were based on typical

operating conditions and practical appearances o f the subcritical and supercritical

pulverized coal-fired power plants. Note that type of data distributions for each

parameter was also provided, as it was required for input selection process during the

Monte Carlo simulation. The followings are the highlights o f the primary assumptions for

the analysis.

• Inlet pressures o f the HP, IP, and LP turbines as well as the backpressure were the

controllable operating conditions. They were defined as uniform distribution.

• Boiler temperature was ranged from 530 to 600°C. This parameter could not be

set at a specific value because it was changed with other factors such as the excess

air and the combustion temperature. The boiler temperature could be significantly

varied within a range of -10 to 5°C (Chattopadhyay, 2000). To handle the

asymmetric range o f variation, the beta distribution was assigned for the Monte

Carlo simulation.

• The amount o f air supplied to the furnace was assigned to be more than the

theoretical requirement, thus preventing incomplete combustion. The percentage

of the excess air fed into the system was ranged from 15 to 20% (Woodruff et al.,

2005), which was defined as the beta distribution.

• Pressure drop across the tube-side o f the feedwater heaters ranged from 3 to 6 %.

(Drbal et al., 1996) This parameter was defined as the normal distribution

45


Reproduced w

ith permission o



ithout permission.

Fu

rnac

e/B

oil

er

Coal

Q

r

Evapo

/ \ /

‘\ /

\ / —A

Air

CS OD 44

G 20

D C Boiler feed pump

8

24

CO absorption process/ Reboiler

LP

-- 7

28

0 Condensate pump

---it 36

29 30 31 32 33 34 35

Figure 3.5 Identified points of input parameters for subcritical PC.

—1%)_ _1

Reproduced

with perm

ission of the

copyright ow

ner. Further


without

permission.

G 20

CO2 absorption I process/ Reboiler|I----

40HP LP

- -FSpray water -A

Condense!. Reheat

H 1 - - J __L - - M - - N

,<^>nomizer 1—0 C ondensate pump

36 "

-BCoal

A ir heater

Boiler feed pump

Air

Figure 3.5 Identified points o f input parameters for subcritical PC.

Reproduced w

ith permission o



ithout permission.

r

Furn

ace

/Boile

r

Coal I

Q l• /•

/ / / •

\ / —A r--

Evaporator 17; 1—R1 FH

Spay

Air

ater

RH1

40 1 17

H 20

E 13

Deaerator' 9

8

Boiler feed pump

24 F

L LP

--A 28

Condens

1 P Condensate pump

—B 3 2

30 31 32 33 34 35

Figure 3.6 Identified points of input parameters for supercritical PC.

Reproduced

with perm

ission of the

copyright ow

ner. Further


without

permission.

H 20

C O 2 absorption I process/ R eb o ilerf "1

LPs h ;

EvaporatorF G

Spray vyater - A

RH1 Reheat

- - M - - N -O- - 3 7 I J - - K

l - L p Condensate pump

- -B 3 6 --Coal

40 1Air heater Deaerator

Boiler feed pump

Air

Figure 3.6 Identified points o f input parameters for supercritical PC.

Reproduced w

ith permission o



ithout permission.

Table 3.3 Main input for subcritical and supercritical PCs.

Point Pressure (MPa) Temperature (°C) Distribution Source

Min Max Min Max For Subcritical PC shown in Figure 3.5 A 0.0060 0.0068 36.3 38.5 Uniform Distribution Singer (1991), U.S.DOE, (1999), Kakaras et al. (2002)

B 1.830 2.275 36.3 38.5 Uniform Distribution U.S.DOE, (1999), Kakaras et al. (2002)

C 1.05 1.27 181.9 190.5 Uniform Distribution U.S.DOE, (1999), Kakaras et al. (2002)

D 19.99 20.57 196.5 196.7 Uniform Distribution Singer (1991), U.S.DOE, (1999)

E 16.64 19.00 530.0 600.0 Uniform Distribution for pressure, and Beta Distribution for temperature (minimum, maximum, alpha, beta) = (530.0, 600.0, 2.0, 3.0)

Singer (1991), Perry et al. (1997), U.S.DOE, (1999), Kakaras et al. (2002), Sanders (2004)

F 3.54 4.50 310.3 345.0 Uniform Distribution Singer (1991), U.S.DOE (1999), Kakaras et al. (2002), Sanders (2004)

G 3.19 4.10 530.0 600.0 Beta Distribution (minimum, maximum, alpha, beta) = (530.0, 600.0, 2.0, 3.0)

Singer (1991), Perry et al. (1997), U.S.DOE (1999), Chattopadhyay (2000), Kakaras et al. (2002), Sanders (2004)

H 2.00 2.52 469.5 506.0 Uniform Distribution Singer (1991), Kakaras et al. (2002), Sanders (2004)

I 1.05 1.27 381.9 411.8 Uniform Distribution Singer (1991), Kakaras et al. (2002), Sanders (2004)

J, K 0.60 0.90 334.9 346.5 Uniform Distribution

L 0.223 0.480 204.3 299.3 Uniform Distribution Singer (1991), Kakaras et al. (2002)

M 0.074 0.180 103.2 198.7 Uniform Distribution Singer (1991), Kakaras et al. (2002)

N 0.031 0.040 69.2 101.9 Uniform Distribution Singer (1991), Kakaras et al. (2002)

0 0.0060 0.0068 36.3 38.5 Uniform Distribution Singer (1991), U.S.DOE (1999), Kakaras et al. (2002)

P 0.103 250.0 350.0 Beta Distribution (minimum, maximum, alpha, beta) = (250.0, 350.0, 3.0, 3.0)

Chattopadhyay (2000), Kakaras et al. (2002)

Q 0.103 25.0 25.0 Fixed

Reproduced

with perm

ission of the

copyright ow

ner. Further


without

permission.

Table 3.3 Main input for subcritical and supercritical PCs.

Point Pressure (MPa) Temperature (°C) Distribution SourceMin Max Min Max

For Subcritical PC shown in Figure 3.5A 0.0060 0.0068 36.3 38.5 Uniform Distribution Singer (1991), U.S.DOE, (1999), Kakaras etal. (2002)




E 16.64 19.00 530.0 600.0 Uniform Distribution for pressure, and Beta Distribution for temperature (minimum, maximum, alpha, beta)= (530.0, 600.0,2.0,3.0)



G 3.19 4.10 530.0 600.0 Beta Distribution(minimum, maximum, alpha, beta) = (530.0, 600.0, 2.0,3.0)


H 2.00 2.52 469.5 506.0 Uniform Distribution Singer (1991), Kakaras et al. (2002), Sanders (2004)


J, K 0.60 0.90 334.9 346.5 Uniform Distribution

L 0.223 0.480 204.3 299.3 Uniform Distribution Singer (1991), Kakaras et al. (2002)



0 0.0060 0.0068 36.3 38.5 Uniform Distribution Singer (1991), U.S.DOE (1999), Kakaras et al. (2002)

P 0.103 250.0 350.0 Beta Distribution(minimum, maximum, alpha, beta) = (250.0, 350.0, 3.0, 3.0)


Q 0.103 25.0 25.0 Fixed

Reproduced w

ith permission o



ithout permission.

Table 3.3 Main input for subcritical and supercritical PCs. (continued)

Point Pressure (MPa) Temperature (°C) Distribution Source

Min Max Min Max For Supercritical shown PC in Figure 3.6 A 0.0050 0.0068 33.1 38.5 Uniform Distribution Singer (1991), U.S.DOE, (1999), Kakaras et al. (2002),

Aroonwilas and Veawab (2007)




E 22.09 25.34 530.0 600.0 Uniform Distribution for pressure, and Beta Distribution for temperature (minimum, maximum, alpha, beta) = (530.0, 600.0, 2.0, 3.0)



G 3.54 4.50 310.1 344.7 Uniform Distribution Singer (1991), U.S.DOE (1999), Kakaras et al. (2002), Sanders (2004)

H 3.19 4.10 530.0 600.0 Beta Distribution (minimum, maximum, alpha, beta) = (530.0, 600.0, 2.0, 3.0)



J 1.05 1.27 381.9 411.8 Uniform Distribution Singer (1991), Kakaras et al. (2002), Sanders (2004)

K, L 0.60 0.90 334.9 346.5 Uniform Distribution



0 0.031 0.040 69.2 101.9 Uniform Distribution Singer (1991), Kakaras et al. (2002)

P 0.0050 0.0068 36.3 38.5 Uniform Distribution Singer (1991), U.S.DOE (1999), Kakaras et al. (2002)

Reproduced

with perm

ission of the

copyright ow

ner. Further


without

permission.


Point Pressure (MPa) Temperature (°C) Distribution SourceMin Max Min Max

For Supercritical shown PC in Figure 3.6A 0.0050 0.0068 33.1 38.5 Uniform Distribution Singer (1991), U.S.DOE, (1999), Kakaras etal. (2002),

Aroonwilas and Veawab (2007)




E 22.09 25.34 530.0 600.0 Uniform Distribution for pressure, and Beta Distribution for temperature (minimum, maximum, alpha, beta)= (530.0, 600.0,2.0,3.0)



G 3.54 4.50 310.1 344.7 Uniform Distribution Singer (1991), U.S.DOE (1999), Kakaras et al. (2002), Sanders (2004)

H 3.19 4.10 530.0 600.0 Beta Distribution(minimum, maximum, alpha, beta) = (530.0,600.0,2.0, 3.0)



J 1.05 1.27 381.9 411.8 Uniform Distribution Singer (1991), Kakaras et al. (2002), Sanders (2004)

K, L 0.60 0.90 334.9 346.5 Uniform Distribution



O 0.031 0.040 69.2 101.9 Uniform Distribution Singer (1991), Kakaras et al. (2002)

P 0.0050 0.0068 36.3 38.5 Uniform Distribution Singer (1991), U.S.DOE (1999), Kakaras et al. (2002)

Reproduced w

ith permission o


Furth


ithout perm

ission.


Point Pressure (MPa) Temperature (°C) Distribution Source Min Max Min Max 0.103

Q

250.0 350.0 Beta Distribution (minimum, maximum, alpha, beta) = (250.0, 350.0, 3.0, 3.0)


R 0.103 25.0 25.0 Fixed

Miscellaneous significant parameters

Description

%P

ress

ure

Dro

p

FWH 1

FWH 2

FWH 3

FWH 4

FWH 5

FWH 6

FWH 7 (for supercritical PC) Boiler

% Excess air

Boiler efficiency (%)

Turbine efficiency (%)

Free moisture in coal (%)

Min Max Distribution Source

-3.0% -6.0% Normal Distribution, -4.5 ± 1.5% Drbal et al. (1996)





-3.0% -6.0% Normal Distribution, -4.5 t 1.5% Drbal et al. (1996)


-9.0% -10.0% Normal Distribution, -9.5 ± 0.5% U.S.DOE (1999), Sanders (2004)

15.0% 20.0% Beta Distribution (minimum, maximum, alpha, beta) = (15.0, 20.0, 3.0, 3.0)

Woodruff et al. (2005)

90.0% 92.0% Uniform Distribution Termuehlen and Emsperger (2003)

90.0% 92.0% Uniform Distribution Termuehlen and Emsperger (2003)

11.12% 17.60% Beta Distribution (minimum, maximum, alpha, beta)

U.S.DOE (1999), Geers and O'Brien (2002)

= (11.12, 17.6, 3.0, 3.0)

Reproduced

with perm

ission of the

copyright ow

ner. Further


without

permission.


Point Pressure (MPa) Min Max

Temperature (°C) Min Max

Distribution Source

0.103Q

250.0 350.0 Beta Distribution(minimum, maximum, alpha, beta) = (250.0, 350.0, 3.0, 3.0)


r 0.103 25.0 25.0 Fixed -

Miscellaneous significant parameters

Description Min Max Distribution Source

FWH 1 -3.0% -6.0% Normal Distribution, -4.5 ± 1.5% Drbal etal. (1996)FWH 2 -3.0% -6.0% Normal Distribution, -4.5 ± 1.5% Drbal etal. (1996)

ft FWH 3 o -3.0% -6.0% Normal Distribution, -4.5 ± 1.5% Drbal etal. (1996)Q FWH 4<D


g FWH 5 -3.0% -6.0% Normal Distribution, -4.5 ± 1.5% Drbal etal. (1996)£ FWH 6 -3.0% -6.0% Normal Distribution, -4.5 ± 1.5% Drbal etal. (1996)

^ FWH 7 (for supercritical PC)

-3.0% -6.0% Normal Distribution, -4.5 ± 1.5% Drbal etal. (1996)

Boiler -9.0% -10.0% Normal Distribution, -9.5 ± 0.5% U.S.DOE (1999), Sanders (2004)

% Excess air 15.0% 20.0% Beta Distribution(minimum, maximum, alpha, beta)= (15.0, 20.0, 3.0, 3.0)

Woodruff et al. (2005)

Boiler efficiency (%) 90.0% 92.0% Uniform Distribution Termuehlen and Emsperger (2003)Turbine efficiency (%) 90.0% 92.0% Uniform Distribution Termuehlen and Emsperger (2003)Free moisture in coal (%)

%

11.12% 17.60% Beta Distribution(minimum, maximum, alpha, beta)= (11.12, 17.6,3.0,3.0)

U.S.DOE (1999), Geers and O'Brien (2002)

with the standard deviation of 0.75 percent point. The pressure drop across a

shell-side of feedwater heaters was considered insignificant.

• Pressure drop across the boiler unit was ranged from 9 to 10% under the normal

distribution with the standard deviation of 0.25 percent point (U.S.DOE, 1999;

Sanders, 2004).

• Free moisture content in coal was varied from 11.1 to 17.6 wt%. (U.S.DOE, 1999;

Geers and O'Brien, 2002). This parameter was defined as the beta distribution.

51


with the standard deviation o f 0.75 percent point. The pressure drop across a

shell-side o f feedwater heaters was considered insignificant.

• Pressure drop across the boiler unit was ranged from 9 to 10% under the normal

distribution with the standard deviation o f 0.25 percent point (U.S.DOE, 1999;

Sanders, 2004).

• Free moisture content in coal was varied from 11.1 to 17.6 wt%. (U.S.DOE, 1999;

Geers and O'Brien, 2002). This parameter was defined as the beta distribution.

51


Chapter Four

Results and Discussions: Subcritical Coal-Fired Power Plant

The main objective of this chapter is to provide a set of simulation results

obtained for the typical pulverized coal-fired power plant operated under the subcritical

conditions. The maximum-minimum ranges of the plant performance including the

thermal efficiency, the net efficiency and the pollutant emissions are reported in the first

part of the chapter. The sensitivity analysis by an approach of the rank correlation

coefficient is then presented in order to reveal the significant process parameters on the

plant efficiency and emissions. Individual parametric effects have been quantified and

are reported as a set of empirical correlations that can be readily utilized by power

industries and other researchers in the related field. In addition, this chapter also provides

the discussion regarding the application of the CO2 capture process for reducing GHG

emissions from the power plant as well as the potential impact on the energy penalty

caused by the CO2 capture activity.

4.1 Maximum-Minimum Ranges of Plant Performance

Table 4.1 summarizes the maximum-minimum ranges of the plant performance

including the thermal efficiency, the net efficiency, the rate of the coal consumption, the

combustion temperature, the emission rate of CO2 and other air pollutants. These

results were obtained through the Monte Carlo simulation in which the simulating

conditions (or values of the process parameters such as the steam pressure and

52


Chapter Four

Results and Discussions: Subcritical Coal-Fired Power Plant

The main objective o f this chapter is to provide a set o f simulation results

obtained for the typical pulverized coal-fired power plant operated under the subcritical

conditions. The maximum-minimum ranges o f the plant performance including the

thermal efficiency, the net efficiency and the pollutant emissions are reported in the first

part o f the chapter. The sensitivity analysis by an approach o f the rank correlation

coefficient is then presented in order to reveal the significant process parameters on the

plant efficiency and emissions. Individual parametric effects have been quantified and

are reported as a set o f empirical correlations that can be readily utilized by power

industries and other researchers in the related field. In addition, this chapter also provides

the discussion regarding the application o f the CO2 capture process for reducing GHG

emissions from the power plant as well as the potential impact on the energy penalty

caused by the CO2 capture activity.

4.1 Maximum-Minimum Ranges of Plant Performance

Table 4.1 summarizes the maximum-minimum ranges o f the plant performance

including the thermal efficiency, the net efficiency, the rate o f the coal consumption, the

com bustion temperature, the em ission rate o f C 0 2 and other air pollutants. T hese

results were obtained through the Monte Carlo simulation in which the simulating

conditions (or values o f the process parameters such as the steam pressure and

52


Table 4.1 Maximum-minimum performance of subcritical PC.

Feature Range aThermal efficiency

Steam cycle efficiency 42.63 - 50.40

Net efficiency %HHV 32.41 - 41.29

Net heat rate kJ/kWh HHV 872519 - 1111580

Coal consumption kg/s 31.41 - 50.11

Combustion zone temperature °C 1697.35 - 1940.73

CO2 emission rate b tonne/hr 260.35 - 402.04

CO2 emission rate b kg/MWh 759.48 - 992.70

SO2 emission rate b tonne/hr 0.35 - 0.55

SO2 emission avoided b tonne/hr 8.30 - 13.20

SO2 emission rate b kg/MWh 1.03 - 1.35

SO2 emission avoided b kg/MWh 24.76 - 32.36

NO emission rate tonne/hr 0.13 - 0.28

NO emission avoided tonne/hr 0.90 - 1.91

NO emission rate kg/MWh 0.39 - 0.70

NO emission avoided kg/MWh 2.63 - 4.70

PM emission rate b' c tonne/hr 0.0050 - 0.0080

PM emission avoided b' tonne/hr 4.96 - 7.89

PM emission rate b' c kg/MWh 0.015 - 0.019

PM emission avoided b' c kg/MWh 14.68 - 19.33

%Flue gas composition

02 mole% 2.63 - 3.36

CO2 mole% 14.25 - 14.84

H2O mole% 6.02 - 6.27

N2 mole% 75.73 - 75.86

SO2, NO and others mole% 0.51 - 0.53

a The simulated results are based on a range of the gross outputs between 350 and 450 MW. b The LNB and SCR units remove the NO emission up to 65% and 63% respectively. The FGD unit removes the SO2 emission up to 96%. The electrostatic precipitator (ESP) removes PM up to 99.9% (U.S.DOE, 1999).

The calculation of particulate is based on emission factors for bituminous coal consumption without control equipment (de Nevers, 2000).

53


Table 4.1 Maximum-minimum performance of subcritical PC.

Feature RangeaThermal efficiency

Steam cycle efficiency % 42.63 - 50.40






C02 emission rate b kg/MWh 759.48 - 992.70

S 0 2 emission rateb tonne/hr 0.35 - 0.55

S 02 emission avoided b tonne/hr 8.30 - 13.20


S 02 emission avoided b kg/MWh 24.76 - 32.36





PM emission rateb’c tonne/hr 0.0050 - 0.0080

PM emission avoided b’c tonne/hr 4.96 - 7.89

PM emission rate b’c kg/MWh 0.015 - 0.019

PM emission avoidedb’c kg/MWh 14.68 - 19.33


0 2 mole% 2.63 - 3.36

C 02 mole% 14.25 - 14.84

H20 mole% 6.02 - 6.27

n 2 mole% 75.73 - 75.86

S 02, NO and others mole% 0.51 - 0.53a The simulated results are based on a range of the gross outputs between 350 and 450 MW. b The LNB and SCR units remove the NO emission up to 65% and 63% respectively. The FGD unit removes the SO2 emission up to 96%. The electrostatic precipitator (ESP) removes PM up to 99.9% (U.S.DOE, 1999).c The calculation of particulate is based on emission factors for bituminous coal consumption without control equipment (de Nevers, 2000).

53


temperature, the moisture content in coal and the excess air for the coal combustion) were

randomly selected for each run of the repeated simulation. Note that the results presented

in the table were based on combustion of Illinois #6 bituminous coal of which the

characteristics were given in Table 4.2. It is obvious that the performance of the

subcritical pulverized coal-fired power plant, i.e., the net efficiency and CO2 emissions

can be varied in the wide ranges (32.41-41.29% net efficiency and 759-993 kg/MWh CO2

emission). Significant variation in the performance indicates the important role of

process conditions under which the power plant is operated.

4.2 Sensitivity Analysis

To arrive at the improved plant performance (i.e. the net efficiency, the CO2

emissions and the coal consumption), a sensitivity analysis by an approach of the rank

correlation coefficient was performed to reveal the effect of operating parameter on the

power plant performance and emissions. Figure 4.1 shows the results presented as the

correlation coefficients of individual operating parameters that indicate proportional

effects of such parameters on the net efficiency, the CO2 emissions, and the rate of the

coal consumption. The operating parameters of interest include the temperature of the

preheated air, the moisture content in coal, the temperature of main steam, the

temperature of reheated steam, the efficiency of the boiler and turbine units, the percent

excess air for combustion, the pressure drop across the feedwater heaters and boiler, and

the steam pressures at different locations throughout the turbine system (i.e. HP inlet, HP

outlet, IP 1St extract, IP 2nd extract, IP outlet, LP 1st extract, LP 2nd extract, LP 3rd extract,

and LP outlet). Note that the value of the correlation coefficient ranges from

54


temperature, the moisture content in coal and the excess air for the coal combustion) were

randomly selected for each run o f the repeated simulation. Note that the results presented

in the table were based on combustion o f Illinois #6 bituminous coal o f which the

characteristics were given in Table 4.2. It is obvious that the performance o f the

subcritical pulverized coal-fired power plant, i.e., the net efficiency and CO2 emissions

can be varied in the wide ranges (32.41-41.29% net efficiency and 759-993 kg/MWh CO2

emission). Significant variation in the performance indicates the important role of

process conditions under which the power plant is operated.

4.2 Sensitivity Analysis

To arrive at the improved plant performance (i.e. the net efficiency, the CO2

emissions and the coal consumption), a sensitivity analysis by an approach of the rank

correlation coefficient was performed to reveal the effect o f operating parameter on the

power plant performance and emissions. Figure 4.1 shows the results presented as the

correlation coefficients o f individual operating parameters that indicate proportional

effects o f such parameters on the net efficiency, the CO2 emissions, and the rate o f the

coal consumption. The operating parameters o f interest include the temperature o f the

preheated air, the moisture content in coal, the temperature o f main steam, the

temperature o f reheated steam, the efficiency o f the boiler and turbine units, the percent

excess air for combustion, the pressure drop across the feedwater heaters and boiler, and

the steam pressures at different locations throughout the turbine system (i.e. HP inlet, HP

outlet, IP 1st extract, IP 2nd extract, IP outlet, LP 1st extract, LP 2nd extract, LP 3rd extract,

and LP outlet). Note that the value o f the correlation coefficient ranges from

54


Table 4.2 Characteristics of Illinois#6 bituminous coal.

Proximate Analysis (percent by weight)

Moisture content 11.12-17.6 %

Volatile content 34.99-44.2 %

Fixed carbon 44.19-45.0 %

Ash 9.7-10.8 %

Ultimate Analysis (percent by weight)

Carbon 69.0 %

Hydrogen 4.9 %

Nitrogen 1.0 %

Sulfur 4.3 %

Ash 10.8 %

Oxygen 10.0 %

(Source: U.S.DOE, 1999; Geers and O'Brien, 2002)

55


Table 4.2 Characteristics o f Illinois#6 bituminous coal.

Proximate Analysis (percent by weight)

Moisture content 11.12-17.6 %

Volatile content 3 4 .9 9 .4 4 .2 %

Fixed carbon 44.19-45.0 %

Ash 9.7-10.8 %

Ultimate Analysis (percent by weight)

Carbon 69.0 %

Hydrogen 4.9 %

Nitrogen 1.0 %

Sulfur 4.3 %

Ash 10.8 %

Oxygen 10.0 %


55


6

Input

Preheated air temperature

Free moisture in coal

Main temperature

Reheat temperature

Boiler efficiency

Turbine efficiency

Excess air

Pressure drop of FWH & boiler

HP inlet

HP outlet

IP 1st extract

IP 2nd extract

IP 3rd extract

LP 1st extract

LP 2nd extract

LP 3rd extract

LP outlet

Boiler feed pressure

Condensate pressure

Deaerator inlet

-1.00 -0.75 -0.50 -0.25 0.00 0.25 0.50 0.75 1.00

Coefficient

0 Net efficiency (%) 12 CO2 (tonne/hour) ■ Coal consumption (kg/sec) Output

Figure 4.1 Results of sensitivity analysis by an approach of rank correlation coefficient.

56


Input



M ain temperature

Reheat temperature

Boiler efficiency

Turbine efficiency

Excess air

Pressure drop o fF W H & boiler

HP inlet

HP outlet

IP 1st extract

IP 2nd extract

IP 3rd extract

LP 1st extract

LP 2nd extract

LP 3rd extract

LP outlet


C ondensate pressure

Deaerator inlet

-1.00 -0.75 -0.50 -0.25 0.00 0.25 0.50 0.75 1.00

Coefficient

□ Net efficiency (%) E3 C 02 (tonne/hour) ■ Coal consumption (kg/sec) O utpu t

Figure 4.1 Results o f sensitivity analysis by an approach of rank correlation coefficient.

56


-1.00 to 1.00. In general, the positive coefficient indicates that an increase in value of

the selected parameter causes the plant performance or the output to rise whereas the

negative coefficient suggests otherwise. The magnitude of the coefficient is proportional

to the level of the effect on the plant performance. From the figure, major influential

parameters are the temperature of the preheated air, the efficiency of the boiler, the

moisture content in coal, the temperature of main steam, the temperature of reheated

steam, and the steam pressures at the outlet of the HP, IP, and LP turbines. Details of

individual parametric effects are given in the following sections.

4.3 Individual Effects of Process Parameters on Plant Performance

This section provides a comprehensive presentation of individual parametric

effects on the net efficiency of the subcritical pulverized coal-fired power plant. All

results presented here were obtained from the simulation of the power plant model

developed in this study. To reveal the true effect of a specific parameter, the simulation

was performed with fixed values of all process parameters, except for the parameter of

interest in which the value was varied within the predetermined range. Understanding

these parametric effects is essential for the development of empirical correlations in the

next section.

57


-1.00 to 1.00. In general, the positive coefficient indicates that an increase in value of

the selected parameter causes the plant performance or the output to rise whereas the

negative coefficient suggests otherwise. The magnitude of the coefficient is proportional

to the level o f the effect on the plant performance. From the figure, major influential

parameters are the temperature o f the preheated air, the efficiency o f the boiler, the

moisture content in coal, the temperature o f main steam, the temperature o f reheated

steam, and the steam pressures at the outlet o f the HP, IP, and LP turbines. Details of

individual parametric effects are given in the following sections.

4.3 Individual Effects of Process Parameters on Plant Performance

This section provides a comprehensive presentation of individual parametric

effects on the net efficiency o f the subcritical pulverized coal-fired power plant. All

results presented here were obtained from the simulation o f the power plant model

developed in this study. To reveal the true effect o f a specific parameter, the simulation

was performed with fixed values o f all process parameters, except for the parameter o f

interest in which the value was varied within the predetermined range. Understanding

these parametric effects is essential for the development o f empirical correlations in the

next section.

57


4.3.1 Effect of Moisture Content in Coal

Figure 4.2 demonstrates the direct effect of the free moisture content in coal on

the net efficiency of the subcritical pulverized coal-fired power plant. The higher the

moisture content, the lower the net efficiency. This is because, in the presence of free

moisture, a fraction of the heat released from the coal combustion is utilized through a

phase changing process that converts liquid water in supplied coal into water vapor

present in the combustion flue gas. Losing such energy during the phase changing

process leads to a reduction in the temperature of the combustion flue gas, reflecting a

lower amount of heat available for transfer into the steam cycle. From the figure, the

reduction in the net efficiency due to the presence of coal moisture is rather significant.

An increase in coal moisture by about 6% (i.e. 11.12-17.60%) causes the power plant net

efficiency to drop by 2.5 percent point (e.g. 35.0-32.5% net efficiency) regardless of the

temperature of the preheated air.

4.3.2 Effect of Preheated Air Temperature

The net efficiency of the pulverized coal-fired power plant can be improved by

preheating the air supplied for the coal combustion via the air preheater unit where waste

heat from the exhaust flue gas is recovered. The recovered waste heat provides extra heat

to the supplied air, resulting in an increase in the air temperature. Increasing the

temperature allows the combustion in the furnace to proceed at a higher temperature, thus

offering a higher quality of heat transferred to the steam cycle. Figure 4.2 shows that

preheating the supplied air to a higher temperature causes the net efficiency to increase in

a linear manner. Regardless of the moisture content in coal, a one percent point increase

58


4.3.1 Effect of Moisture Content in Coal

Figure 4.2 demonstrates the direct effect o f the free moisture content in coal on

the net efficiency of the subcritical pulverized coal-fired power plant. The higher the

moisture content, the lower the net efficiency. This is because, in the presence o f free

moisture, a fraction o f the heat released from the coal combustion is utilized through a

phase changing process that converts liquid water in supplied coal into water vapor

present in the combustion flue gas. Losing such energy during the phase changing

process leads to a reduction in the temperature o f the combustion flue gas, reflecting a

lower amount of heat available for transfer into the steam cycle. From the figure, the

reduction in the net efficiency due to the presence o f coal moisture is rather significant.

An increase in coal moisture by about 6% (i.e. 11.12-17.60%) causes the power plant net

efficiency to drop by 2.5 percent point (e.g. 35.0-32.5% net efficiency) regardless o f the

temperature o f the preheated air.

4.3.2 Effect of Preheated Air Temperature

The net efficiency o f the pulverized coal-fired power plant can be improved by

preheating the air supplied for the coal combustion via the air preheater unit where waste

heat from the exhaust flue gas is recovered. The recovered waste heat provides extra heat

to the supplied air, resulting in an increase in the air temperature. Increasing the

temperature allows the combustion in the furnace to proceed at a higher temperature, thus

offering a higher quality o f heat transferred to the steam cycle. Figure 4.2 shows that

preheating the supplied air to a higher temperature causes the net efficiency to increase in

a linear manner. Regardless o f the moisture content in coal, a one percent point increase

58


Net

Eff

icie

ncy

(%)

36.0

35.0 -

34.0 -

33.0 -

32.0 -

31.0 -

30.0

250

00)

3>

* °C.C111PC4 * *

.0. 00 40:16*.PC°4

aiSairtri at1311133EP Cri 11:3:13:1

0

Ci

szna 0,3 Ana A

arl dta SK X X < X

A

•I‘'

70#45001 .0461.°( X A

X AO( 3°°°41C /00 4E21/11111111114.'

ora30011/114•15Free Moisture in Coal (%)

o 11.12 0 12.74 a 14.36 x 15.98 x 17.60

275 300 325

Preheated Air Temperature (°C)

350

Figure 4.2 Effects of moisture content in coal and temperature of preheated air.

59


S®0 sw

1a

36.0 -1

35.0 - o<x> «■

□ ID0034.0 -

A *

33.0 - X *X

as*32.0 -

31.0 -

30.0 -

— '” D nJJ^ JdCttInCIIJ3tP A A

^ a * * * * * * m M * * *

F ree M o is tu re in C oal (%o 11.12 □ 12.74 A 14.36 x 15.98 x 17.60

250 275 300 325

Preheated Air Temperature (°Q

350

Figure 4.2 Effects o f moisture content in coal and temperature o f preheated air.

59


in the net efficiency can be achieved by raising the preheated air temperature by 80°C.

Note that the temperature of the preheated air should be limited up to 350°C due to a

metallurgical limitation of common air preheaters (Singer, 1991; Chattopadhyay, 2000;

Woodruff et al., 2005).

4.3.3 Effects of Main Steam Temperature and Reheating Temperature

Increasing the temperature of the superheated steam driving the turbines leads to a

higher enthalpy producing additional work from the steam cycle. This simply results in

an increase in the net efficiency of the power plant. Figure 4.3 illustrates a proportional

relationship between the net efficiency and the temperature of main steam generated from

the boiler unit. Reheating the temperature is also included in the figure as a parameter.

In general, increasing the temperature of either main steam or reheated steam by 50°C

results in an increase in the net efficiency by one half percent point. It should be noted

that, despite the positive effects of the steam temperatures on the plant efficiency, an

increase in such temperatures must be done within the metallurgical limitation of the

steam boiler, i.e. main steam pipe fabricated by a terrific material with 2.25Cr 1Mo can

tolerate the temperature up to about 545°C according to New Energy and Industrial

Technology Development Organization (NEDO) and Center for Coal Utilization Japan

(CCUJ) (2004).

60


in the net efficiency can be achieved by raising the preheated air temperature by 80°C.

Note that the temperature o f the preheated air should be limited up to 350°C due to a

metallurgical limitation o f common air preheaters (Singer, 1991; Chattopadhyay, 2000;

Woodruff et al., 2005).

4.3.3 Effects of Main Steam Temperature and Reheating Temperature

Increasing the temperature o f the superheated steam driving the turbines leads to a

higher enthalpy producing additional work from the steam cycle. This simply results in

an increase in the net efficiency o f the power plant. Figure 4.3 illustrates a proportional

relationship between the net efficiency and the temperature o f main steam generated from

the boiler unit. Reheating the temperature is also included in the figure as a parameter.

In general, increasing the temperature o f either main steam or reheated steam by 50°C

results in an increase in the net efficiency by one half percent point. It should be noted

that, despite the positive effects o f the steam temperatures on the plant efficiency, an

increase in such temperatures must be done within the metallurgical limitation o f the

steam boiler, i.e. main steam pipe fabricated by a ferritic material with 2.25Cr IMo can

tolerate the temperature up to about 545°C according to New Energy and Industrial

Technology Development Organization (NEDO) and Center for Coal Utilization Japan

(CCUJ) (2004).

60


36.0

Net

Eff

icie

ncy

(%)

35.5 -

35.0

34.5 -

34.0 -

33.5 -

33.0

530.0

w X

xxxx4X

)00011141° ..AinmAA a ow vosiartifirOso< aitetato c.---00 co

))0 *INA -.% itaabge At' Agrosionrsols°,,,,ci , 00 o ,604 coign ,00 ot0N.- -

walla 4:4000P o EP 40.10044000

<0 o Reheat Temperature (°C)

o 530.0 o 547.5 A 565.0 x 582.5 X 600.0

547.5 565.0 582.5 600.0

Temperature of Main Steam (°C)

Figure 4.3 Effects of main steam and reheated steam temperatures.

61


36.0

35.5

^ 35.0U

1 34.5€w$ 34.0 S5

33.5

33.0530.0 547.5 565.0 582.5 600.0

Temperature of Main Steam (°Q

Figure 4.3 Effects o f main steam and reheated steam temperatures.

Reheat Temperature (°Qo 530.0 a 547.5 A 565.0 x 582.5 x 600.0


4.3.4 Effects of Boiler and Turbine Efficiencies

Figure 4.4 shows the effects of the turbine and boiler efficiency on the net

efficiency of the power plant. An increase in the turbine efficiency from 90 to 92% leads

to a slight improvement in the net efficiency (i.e. 0.1 percent point) whereas an increase

in the boiler efficiency by the same magnitude (2%) results in about 0.75 percent point

increase in the efficiency. This indicates that the boiler efficiency plays an important role

in improving the efficiency of the power plant.

4.3.5 Effect of Excess Air Supply

The amount of the excess air supplied to the furnace is necessary, from the

practical viewpoint, to achieve the complete combustion. However, introducing the

excess air to the furnace leads to an increasing amount of gas-phase traveling through the

combustion zone and boiler unit, causing a reduction in the net efficiency of the power

plant. However, the reduction in the efficiency is rather small as demonstrated in Figure

4.5. About 3 percent increase in the excess air (i.e. from 16 to 19%) causes a slight

efficiency drop of 0.03 percent point. Therefore, the effect of the excess air may be

considered negligible.

62


4.3.4 Effects of Boiler and Turbine Efficiencies

Figure 4.4 shows the effects o f the turbine and boiler efficiency on the net

efficiency o f the power plant. An increase in the turbine efficiency from 90 to 92% leads

to a slight improvement in the net efficiency (i.e. 0 .1 percent point) whereas an increase

in the boiler efficiency by the same magnitude (2%) results in about 0.75 percent point

increase in the efficiency. This indicates that the boiler efficiency plays an important role

in improving the efficiency o f the power plant.

4.3.5 Effect of Excess Air Supply

The amount o f the excess air supplied to the furnace is necessary, from the

practical viewpoint, to achieve the complete combustion. However, introducing the

excess air to the furnace leads to an increasing amount o f gas-phase traveling through the

combustion zone and boiler unit, causing a reduction in the net efficiency o f the power

plant. However, the reduction in the efficiency is rather small as demonstrated in Figure


efficiency drop of 0.03 percent point. Therefore, the effect o f the excess air may be

considered negligible.

62


35.7

35.6 AZ& A A, MANZa(tDM AON aftAA 46.a6LsfitOAAAA namemitad

35.4 -

Net

Eff

icie

ncy

(%)

35.2 cILAufiCI CanraarlD IINEE:Prai3Erp3 Ea 0 =Xi MacCIDallaci

35.0 -

34.8 "poem pp 4110(00.200:00> 0 010 0 03:CO CID CO

34.6 - Boiler Efficiency (%)

34.4 - *90.0

34.2 - 0 91.0

A 92.0 34.0

90.0 90.5 91.0 91.5 92.0

Turbine Efficiency (%)

Figure 4.4 Effects of boiler and turbine efficiencies.

63


35.7 r --------------------------------------------- — .........3 5 . 6 - ^ AAA^ m m ^ a n u i n m A i A <m h w m ,

35.4 -g 35.2 m D m racnrno.aw :

§ 35-° 'H 34.8 *3xx«x> ooctxxaco «x»<*»a>o<»<*> o<x*> o < k » « < »

~ 34.6 Boiler Efficiency (%)

* 34 .4 - ♦ 90-°□ 91.0

34.2 -A 92.0

34.0----------------- -1-1---------------1--------------- 1---------------

90.0 90.5 91.0 91.5 92.0


Figure 4.4 Effects o f boiler and turbine efficiencies.

a * a a ^ a * a a a

________ mnmnniiiriniiiUiJifipmin muLLimJi gmmMiixPaxn ™

»J>CX£S> <X>ctxxaoo «xxx>€»axx»co oooeo o <*sfx><» <®

Boiler Efficiency (%)<> 90.0

□ 91.0 A 92.0


Net

Eff

icie

ncy

(%)

16.0 17.0 18.0 19.0

Excess Air (%)

Figure 4.5 Effect of excess air for coal combustion.

64

20.0


34.8

&sE

34.715.0 16.0 17.0 18.0 19.0 20.0

Excess Air (%)

Figure 4.5 Effect o f excess air for coal combustion.

64


4.3.6 Effect of Pressure Drop across the Steam Cycle

Based on the thermodynamic principles, the enthalpy of steam not only depends

on temperature but also pressure of the system. If the steam cycle is subjected to a high

pressure drop, a large amount of steam heat can be lost causing the net efficiency to

reduce. Figure 4.6 shows the effect of the pressure drop in the boiler unit and the FWH

train. It is clear that the pressure drop in the boiler unit has an impact on the net

efficiency of the power plant whereas the effect of the pressure drop in the FWH train is

considered negligible. Yet, the effect of the boiler pressure drop is rather insignificant.

An increase in the pressure drop by 2% contributes to a slight reduction in the net

efficiency (about 0.2 percent point).

4.3.7 Effects of Pressure and Pressure Distribution in the Turbine Series

In general, operating the steam cycle with a large difference between inlet

pressure and outlet pressure of turbine series (i.e. boiler pressure and condenser pressure)

tends to offer a high thermal efficiency of the power plant. In addition to these two

pressure boundaries, the steam pressures at different turbine stages also play important

roles in defining the efficiency of the power plant. The followings are the highlights of

such pressure effects that focus on the outlet pressure of the HP turbine, the 1st stage and

the outlet pressures of the IP turbine, as well as the 4th stage pressure of the LP turbine.

65


4.3.6 Effect of Pressure Drop across the Steam Cycle

Based on the thermodynamic principles, the enthalpy o f steam not only depends

on temperature but also pressure o f the system. If the steam cycle is subjected to a high

pressure drop, a large amount o f steam heat can be lost causing the net efficiency to

reduce. Figure 4.6 shows the effect o f the pressure drop in the boiler unit and the FWH

train. It is clear that the pressure drop in the boiler unit has an impact on the net

efficiency o f the power plant whereas the effect o f the pressure drop in the FWH train is

considered negligible. Yet, the effect o f the boiler pressure drop is rather insignificant.

An increase in the pressure drop by 2% contributes to a slight reduction in the net

efficiency (about 0 .2 percent point).

4.3.7 Effects of Pressure and Pressure Distribution in the Turbine Series

In general, operating the steam cycle with a large difference between inlet

pressure and outlet pressure o f turbine series (i.e. boiler pressure and condenser pressure)

tends to offer a high thermal efficiency of the power plant. In addition to these two

pressure boundaries, the steam pressures at different turbine stages also play important

roles in defining the efficiency o f the power plant. The followings are the highlights of

such pressure effects that focus on the outlet pressure o f the HP turbine, the 1st stage and

ththe outlet pressures o f the IP turbine, as well as the 4 stage pressure o f the LP turbine.

65


34.9

34.8

, 0 34.7

s•—• Q, 34.6

0a 34.5

-

--

- ig 34.4 -w ti 34.3 - 4

34.2 -

34.1

34.0

8.0 9.0 10.0

Pressure Drop in Boiler Units (%)

Figure 4.6 Effect of pressure drop in steam cycle.

66

11.0


N®0sW'£.3Ew"8z

34.9

34.8 H

34.7

34.6

34.5

34.4

34.3

34.2

34.1 H

34.0 -

8

Pressure Drop in FWHs (% )

o 3.0

a 4.0

a 5.0

x 6 .0

0 9.0 10.0

Pressure Drop in Boiler Units (%

Figure 4.6 Effect o f pressure drop in steam cycle.

66

11.0


(a) Pressure of HP turbine

Figure 4.7 illustrates the effect of the HP turbine pressure ratio on the net

efficiency of the power plant. Increasing the pressure ratio from 4.5 to 5.8 generally

helps improve the plant efficiency. Note that an increase in the pressure ratio can be

achieved by either increasing the inlet pressure of the HP turbine or reducing the outlet

pressure of the HP turbine. Between these two approaches, reducing the outlet pressure is

the primary cause of the improved efficiency. This can be seen clearly from the figure.

By keeping the outlet pressure constant (e.g. 4.12 MPa), raising the inlet pressure or the

pressure ratio of the turbine does not contribute to any improvement in the plant

efficiency but causing a slight reduction in the efficiency due to a higher work load in the

boiler feed pump. It should be noted that this subsection considers only the HP turbine

pressure and the net efficiency with fixed values of all process parameters. However,

unless the rest of parameter inputs are fixed, increasing HP inlet pressure improves the

net efficiency. On the contrary, lowering the outlet pressure from 4.5 to 3.7 MPa can

enhance the efficiency by one half percent points.

Despite its positive impact, reducing the outlet pressure beyond a specific point

(3.7 MPa in the figure) can cause a reduction in the plant efficiency. Based on a typical

process scheme of the subcritical PC (Figure 3.5), a fraction of exhaust steam from the

HP turbine is used to heat the feedwater heater. Lowering the pressure of the exhaust

steam below the optimal level leads to a reduced temperature of the heater, thus causing

the net efficiency of the power plant to drop.

67


(a) Pressure of HP turbine

Figure 4.7 illustrates the effect o f the HP turbine pressure ratio on the net

efficiency of the power plant. Increasing the pressure ratio from 4.5 to 5.8 generally

helps improve the plant efficiency. Note that an increase in the pressure ratio can be

achieved by either increasing the inlet pressure o f the HP turbine or reducing the outlet

pressure o f the HP turbine. Between these two approaches, reducing the outlet pressure is

the primary cause o f the improved efficiency. This can be seen clearly from the figure.

By keeping the outlet pressure constant (e.g. 4.12 MPa), raising the inlet pressure or the

pressure ratio of the turbine does not contribute to any improvement in the plant

efficiency but causing a slight reduction in the efficiency due to a higher work load in the

boiler feed pump. It should be noted that this subsection considers only the HP turbine

pressure and the net efficiency with fixed values o f all process parameters. However,

unless the rest of parameter inputs are fixed, increasing HP inlet pressure improves the

net efficiency. On the contrary, lowering the outlet pressure from 4.5 to 3.7 MPa can

enhance the efficiency by one half percent points.

Despite its positive impact, reducing the outlet pressure beyond a specific point

(3.7 MPa in the figure) can cause a reduction in the plant efficiency. Based on a typical

process scheme o f the subcritical PC (Figure 3.5), a fraction o f exhaust steam from the

HP turbine is used to heat the feedwater heater. Lowering the pressure o f the exhaust

steam below the optimal level leads to a reduced temperature o f the heater, thus causing

the net efficiency o f the power plant to drop.

67


35.0

,..; 34.8 - ,... t' z i 34.6 -a 44 t Z 34.4 -

34.2

4.4

wag

Crumb ittlts21, <3211041

HP Outlet (MPa)

o 3.54 O 3.74 A 3.93 x 4.12

* 4.31 O 4.50

4.8 5.2 5.6

Pressure Ratio, HP Inlet/Outlet

Figure 4.7 Effect of pressure in the HP stage.

68

6.0


35.0

34.80s

1 34.6S3w"8* 34.4

34.24.4 4.8 5.2 5.6 6.0

P re ssu re R a tio , H P In le t/O u tle t

H P O u tle t (M P a)

o 3.54o 3.74A 3.93 x 4.12 x 4.31 o 4.50

F ig u re 4.7 Effect o f pressure in the HP stage.

68


(b) Pressure of IP turbine

Figures 4.8 and 4.9 show the effect of the steam pressure ratio in the IP turbine

extracted at the 1st and the 3rd stages. Both figures indicate that increasing the pressure

ratio (e.g. from 1.3 to 2.0 in Figure 4.8 and from 3.6 to 6.7 in Figure 4.9) leads to a

reduction in the plant efficiency which is opposite to the results given in the previous

subsection (the pressure ratio of the HP turbine). Based on earlier discussion, there are

two approaches to increase the pressure ratio, i.e., increasing the inlet pressure and

reducing the outlet pressure. This means that reducing the pressure ratio can be achieved

by either reducing the inlet pressure or increasing the outlet pressure. Reducing the

pressure ratio by decreasing inlet pressure of the turbine with the constant outlet pressure

offers the improvement of the net efficiency. In Figures 4.8, for example, at 2.0 MPa

outlet pressure, reducing the pressure ratio from 2.0 to 1.7 results in an increase in the net

efficiency. From Figure 3.5, exhaust steam from the HP turbine is extracted to drive the

IP turbine. A high inlet pressure presented in the IP turbine implies a low pressure ratio in

the HP turbine which leads to a reduction of the net efficiency as previously concluded in

Figure 4.7. Even though decreasing the inlet pressure results in the positive impact on

the net efficiency, decreasing the pressure beyond a certain level could cause a slight

reduction in efficiency. In Figure 4.8, for instant at 2.0 MPa, reducing the pressure ratio

from 1.7 to 1.6 causes a reduction of the net efficiency.

Increasing the pressure ratio by decreasing the outlet pressure causes a reduction

of the net efficiency. Figure 4.8 shows that decreasing the outlet pressure from 2.5 to 2.0

MPa causes a reduction of 0.2 percent point. Similarly, Figure 4.9 shows that reducing

the outlet pressure from 0.9 to 0.6 MPa causes a reduction of the net efficiency by about

69


(b) Pressure of IP turbine

Figures 4.8 and 4.9 show the effect o f the steam pressure ratio in the IP turbine

extracted at the 1st and the 3rd stages. Both figures indicate that increasing the pressure

ratio (e.g. from 1.3 to 2.0 in Figure 4.8 and from 3.6 to 6.7 in Figure 4.9) leads to a

reduction in the plant efficiency which is opposite to the results given in the previous

subsection (the pressure ratio o f the HP turbine). Based on earlier discussion, there are

two approaches to increase the pressure ratio, i.e., increasing the inlet pressure and

reducing the outlet pressure. This means that reducing the pressure ratio can be achieved

by either reducing the inlet pressure or increasing the outlet pressure. Reducing the

pressure ratio by decreasing inlet pressure o f the turbine with the constant outlet pressure

offers the improvement o f the net efficiency. In Figures 4.8, for example, at 2.0 MPa

outlet pressure, reducing the pressure ratio from 2.0 to 1.7 results in an increase in the net

efficiency. From Figure 3.5, exhaust steam from the HP turbine is extracted to drive the

IP turbine. A high inlet pressure presented in the IP turbine implies a low pressure ratio in

the HP turbine which leads to a reduction o f the net efficiency as previously concluded in

Figure 4.7. Even though decreasing the inlet pressure results in the positive impact on

the net efficiency, decreasing the pressure beyond a certain level could cause a slight

reduction in efficiency. In Figure 4.8, for instant at 2.0 MPa, reducing the pressure ratio

from 1.7 to 1.6 causes a reduction o f the net efficiency.

Increasing the pressure ratio by decreasing the outlet pressure causes a reduction

o f the net efficiency. Figure 4.8 shows that decreasing the outlet pressure from 2.5 to 2.0

MPa causes a reduction o f 0.2 percent point. Similarly, Figure 4.9 shows that reducing

the outlet pressure from 0.9 to 0.6 MPa causes a reduction o f the net efficiency by about

69


Net

Eff

icie

ncy

(%)

Net

Eff

icie

ncy

(%)

Pressure Ratio, IP Inlet/Outlet at 1st Stage

Figure 4.8 Effect of pressure at the 1st IP stage.

37.0

36.5 -

36.0 -

35.5 -

35.0 -

34.5 -

34.0

IP Outlet at 3 rd Stage (MPa)

o 0.60

0 0.70

A 0.80

X 0.90

3.5 4.0 4.5 5.0 5.5 6.0 6.5 7.0 7.5

Pressure Ratio, IP Inlet/Outlet at 3 rd Stage

Figure 4.9 Effect of pressure at the 3rd IP stage.

70


35.2

35.1 - Qc^

8'

.1it-

£

34.9

34.7

34.5

34.3

IP Outlet at 1St Stage(MPa)

o 2 .0 0

□ 2 .1 0

a 2 .2 0

x 2.30 x 2.40 ° 2.50

1.2 1.5 1.8 2.1 2.4


Figure 4.8 Effect o f pressure at the 1st IP stage.

37.0 -

36.5 -

^ 36.0 -

s*5 35.5 -aa% 35.0 -

34.5 -

34.0 -3.5 4.0 4.5 5.0 5.5 6.0 6.5 7.0 7.5

Pressure Ratio, IP Inlet/Outlet at 3rd Stage

IP Outlet at 3 Stage

o 0.60

□ 0.70A 0.80

x 0.90

Figure 4.9 Effect o f pressure at the 3rd IP stage.

70


1.0 percent point. This indicates that reducing the pressure of the exhaust steam leads to

a reduction of temperature of the feedwater heaters, causing the net efficiency to drop.

(c) Pressure of LP turbine

Decreasing the pressure of the exhaust steam from the LP turbine causes

additional work required by the condensate pump. Nevertheless, it offers a much higher

work output from the turbine system, thus helping improve the net efficiency of the

power plant. Figure 4.10 shows the effect of the steam pressure in the LP turbine

extracted at the 4th stage. The higher the pressure ratio between the inlet and the outlet,

the greater the net efficiency becomes. Even though the reduction of the exhaust pressure

provides a higher net efficiency, it could form excessive moisture in the turbine causing

damage on the turbine blade. The acceptable level of the moisture content was limited to

10% in this study.

4.4 Efficiency Correlations for Subcritical Pulverized Coal-fired Power Plant

This section demonstrates empirical equations of the net efficiency for the

subcritical pulverized coal-fired power plant that were created according to the

parametric effects on the net efficiency as previously reported in section 4.3. In general,

most parametric effects were presented in the linear manner, except for the effect of the

pressure in turbine series. An additional analysis for pressure is given here.

Figure 4.11 shows the reference net efficiency (rfref) of a base power plant that

was set to operate under reference conditions (i.e. 19.0 MPa HP inlet pressure, 2.6 MPa

IP outlet pressure at the 1st stage and 6.0 kPa backpressure). Apparently, the reference

71


1.0 percent point. This indicates that reducing the pressure o f the exhaust steam leads to

a reduction o f temperature of the feedwater heaters, causing the net efficiency to drop.

(c) Pressure of LP turbine

Decreasing the pressure o f the exhaust steam from the LP turbine causes

additional work required by the condensate pump. Nevertheless, it offers a much higher

work output from the turbine system, thus helping improve the net efficiency o f the

power plant. Figure 4.10 shows the effect o f the steam pressure in the LP turbine

extracted at the 4th stage. The higher the pressure ratio between the inlet and the outlet,

the greater the net efficiency becomes. Even though the reduction o f the exhaust pressure

provides a higher net efficiency, it could form excessive moisture in the turbine causing

damage on the turbine blade. The acceptable level o f the moisture content was limited to

1 0 % in this study.

4.4 Efficiency Correlations for Subcritical Pulverized Coal-fired Power Plant

This section demonstrates empirical equations o f the net efficiency for the

subcritical pulverized coal-fired power plant that were created according to the

parametric effects on the net efficiency as previously reported in section 4.3. In general,

most parametric effects were presented in the linear manner, except for the effect o f the

pressure in turbine series. An additional analysis for pressure is given here.

Figure 4.11 shows the reference net efficiency (tjref) o f a base power plant that

was set to operate under reference conditions (i.e. 19.0 MPa HP inlet pressure, 2.6 MPa

IP outlet pressure at the 1st stage and 6.0 kPa backpressure). Apparently, the reference

71


37.0

36.0

35.0 -

34.0

80.0

LP Outlet at 4th Stage (kPa) o 6.00

6.40 A 6.80

97.5 115.0 132.5 150.0

Pressure Ratio, LP Inlet/Outlet at 4th Stage

Figure 4.10 Effect of pressure at the last LP stage.

72


37.0

N~^ 36.0 - >>

* 35.0 -

34.0 J80.0 97.5 115.0 132.5 150.0


A□

<P

iffip LP Outlet at 4 Stage(kPa)o 6 .0 0

□ 6.40 A 6.80


72


3.4 3.6 3.8 4.0 4.2 4.4

HP Outlet at 1St Stage (MPa)

4.6

Figure 4.11 Reference net efficiency of base subcritical PC.

(Base condition: 19.0 MPa HP inlet pressure, 2.6 MPa 1P outlet pressure at the 1st stage

and 6.0 kPa backpressure)

73


35.0

IP, Outlet jat 3 S(age (M[Pa)

0.9034.0

0.?3Ur

a 33.00.7^

.2 0.68S3"8fc 32.0

31.03.8 4.0 4.2 4.4 4.63.4 3.63.2

HP Outlet a t 1st Stage (MPa)

Figure 4.11 Reference net efficiency of base subcritical PC.

(Base condition: 19.0 MPa HP inlet pressure, 2.6 MPa IP outlet pressure at the 1st stage

and 6.0 kPa backpressure)

73


efficiency (Piref) varies with both HP outlet pressure and IP outlet pressure. With the well-

defined outlet pressure of the HP and IP turbines, the i'ref can be obtained directly from

the plot. However, it should be noted that changing the steam pressure extracted from the

1st stage of the IP turbine also causes the variation in the value of the gref• The change in

the reference net efficiency due to the 1st stage IP pressure was regressed and can be

presented as

A r hipijiwp3 = (a • Pmi+b • PIA C • P11,3) • (2.6-Plli ) (4.1)

where a, b and c are the regression constants with the values of —0.00124, 0.00794 and

—0.00743, respectively. PHI,/ PIP, and P11,3 denote the 1st stage HP turbine pressure, and the

1st and 3rd IP stage turbine pressures, respectively. By combining the calculated

efficiency variation and the reference efficiency from Figure 4.11, the net efficiency of

the power plant can be defined as

'/net 7.7. r ref — / (4.2)

Based on the effects of other parameters presented earlier in section 4.3, the efficiency

Equation (4.2) was modified to include these effects. After regression, the efficiency

equation can be presented as

net =(1 ref — 411 HP] JP] ,IP3 ) + 0.016 • ( 20.0— E a,r )+ 0.39 • ( 17.6 — F.)+ 0.012•(Ta,r — 250.0)

+ 0.011 • (T. — 530.0 )+ 0.010. (Tr —530.0)+0.38• (n boiler 90.0 ) + 0.05 5 • (th —90.0) (4.3)

—0.1 • (Pd„, —6.0)

where Eair, Tair, Tm, Tr, 1 In and Pdrop represent the excess air (%), the free

moisture in coal (%), the preheated air temperature (°C), the main temperature (°C), the

reheating temperature (°C), the boiler efficiency (%), the turbine efficiency (%) and the

74


efficiency (r\rej) varies with both HP outlet pressure and IP outlet pressure. With the well-

defined outlet pressure o f the HP and IP turbines, the rjref can be obtained directly from

the plot. However, it should be noted that changing the steam pressure extracted from the

1st stage o f the IP turbine also causes the variation in the value o f the r/ref- The change in

the reference net efficiency due to the 1st stage IP pressure was regressed and can be

presented as

^ 0 ' = (a ' Php, ’ Pip, + c ' /̂/>3) ' ) (4.1)

where a, b and c are the regression constants with the values o f -0.00124, 0.00794 and

-0.00743, respectively. PHP/, PIPi and PIPj denote the 1st stage HP turbine pressure, and the

1st and 3rd IP stage turbine pressures, respectively. By combining the calculated

efficiency variation and the reference efficiency from Figure 4.11, the net efficiency o f

the power plant can be defined as

Vnet = V re f ~ ^0'HP\,IP\,IP, (4-2)

Based on the effects o f other parameters presented earlier in section 4.3, the efficiency

Equation (4.2) was modified to include these effects. After regression, the efficiency

equation can be presented as

nm ~ O lr e f - ^ HPl IPl IP3) + 0 .016-(20.0-E air) + 0 3 9 -(1 7 .6 -F m) + 0.012-(Tair-250 .0)

+ 0.01 l-(Tm - 530.0) + 0.010-(Tr - 530.0) + 0.38- ( r j ^ - 9 0 .0 ) + 0.055-(rjr -9 0 .0 ) (4.3)

-0 .1 (Pirop -6 .0 )

where Eair, Fm, Tain Tm, Tr, rjboiier, 0t and Pdrop represent the excess air (%), the free



74


pressure drop (%) across the boiler and FWHs, respectively. Note that Equation (4.3)

was developed for Illinois#6 bituminous coal.

To develop a more general equation that can be used for other types of coal,

Equation (4.3) was further modified to accommodate the variation in the high heating

value (HHV, kJ/kg coal) and hydrogen content (H, percent by weight) for individual coals

(see Table 4.3). The final equation then can be written as

rinet ( riref 4 11-1P1 ± 0.016 .( 20.0 — Ea) +[0.39 HHV

17.6 F,,)+ 2.05 H 4.9 •( ).( — •( — 28,818

)]

+0.012 • (Ta„. — 250.0) + 0.011 • (T„, — 530.0) + 0.010 • — 530.0 )+ 0.38' , ( Fn (4.4) boiler — 90.0)

+0.055 • T — 90.0 ) — 0.1. (Pdrop —6.0)

It is noted that Equation (4.4) is valid for a range of operating conditions as previously

given in Table 3.3 with the types of coals as given in Table 4.3. A parity plot between

the efficiency calculated from the empirical equation and that obtained from the power

plant theoretical model is given in Figure 4.12. The multiple determination coefficient

(R2) of 0.99 from the plot indicates a good agreement.

75


pressure drop (%) across the boiler and FWHs, respectively. Note that Equation (4.3)

was developed for Illinois# 6 bituminous coal.

To develop a more general equation that can be used for other types o f coal,

Equation (4.3) was further modified to accommodate the variation in the high heating

value (HHV, kJ/kg coal) and hydrogen content (H, percent by weight) for individual coals

(see Table 4.3). The final equation then can be written as

Tl n e t ~ ( t l r e f ^ H P , ,IP , J P 3 ) + 0.016 '(20 .0 Ea) + 0 - 3 9 - ( ^ - } ( 1 7 . 6 - F m) + 2 .0 5 - ( H - 4 .9 )J o , o l o

+ 0.012 ■ (Tair - 250.0) + 0.01l-(T m- 530.0) + 0.010 -(Tr - 530.0) + 0.38 ■ (rjboiler - 9 0 .0 ) (4 -4 )

+ 0.055 • (rjT - 9 0 .0 ) - 0 .1 • (Pirop - 6 .0 )

It is noted that Equation (4.4) is valid for a range of operating conditions as previously

given in Table 3.3 with the types o f coals as given in Table 4.3. A parity plot between

the efficiency calculated from the empirical equation and that obtained from the power

plant theoretical model is given in Figure 4.12. The multiple determination coefficient

(R2) o f 0.99 from the plot indicates a good agreement.

75


Table 4.3 Characteristics of coal used for simulation.

Content (percent by

Bituminous coal Subbituminous coal Lignite

weight) Pittsburg

#8 Illinois

#6

Upper Freeport

MV

Spring Creek

Decker North

Dakota Hallaville

Moisture 5.2 11.2-17.6 2.2 24.1 23.4 33.3 37.7

Ultimate

C 74.0 69.0 74.9 70.3 72.0 63.3 66.3

H 5.1 4.9 4.7 5.0 5.0 4.5 4.9

0 7.9 10.0 4.97 17.69 16.41 19.0 16.2

N 1.6 1.0 1.27 0.96 0.95 1.0 1.0

S 2.3 4.3 0.76 0.35 0.44 1.1 1.2

A (ash) 9.1 10.8 13.4 5.7 5.2 11.1 10.4

HHV a(kJ/kg coal)

30856 28818 30854 28285 29033 25043 26949

a The HHV is equal to 2.326[146.58C+ 568.78H+ 29.4S- 6.58A - 51.53(0+N)] (Perry et al., 1997).


76


Table 4.3 Characteristics o f coal used for simulation.

Content (percent by weight)

Bituminous coal Subbituminous coal Lignite

Pittsburg#8

Illinois#6

UpperFreeport

MV

SpringCreek Decker North

Dakota Hallaville

Moisture 5.2 11.2-17.6 2.2 24.1 23.4 33.3 37.7Ultimate

C 74.0 69.0 74.9 70.3 72.0 63.3 66.3H 5.1 4.9 4.7 5.0 5.0 4.5 4.9

0 7.9 10.0 4.97 17.69 16.41 19.0 16.2

N 1.6 1.0 1.27 0.96 0.95 1.0 1.0S 2.3 4.3 0.76 0.35 0.44 1.1 1.2A (ash) 9.1 10.8 13.4 5.7 5.2 11.1 10.4

HHVa 30856 28818 30854 28285 29033 25043 26949(kJ/kg coal)

a The HHV is equal to 2.326[146.58C + 568.78// + 29 .45- 6.58,4 - 51.53(0+/V)] (Perry et al., 1997).


76


R2 = 0.99

42.0

,—, 37.8 -

r 9 33.5 -

E W cu W s 29.3 -

25.0

25.0 29.3 33.5 37.8 42.0

o Bitumino4

• Subbituniinous

& Lignite

Net Efficiency (%) — Power Plant Theoretical Model

Figure 4.12 Parity plot of net efficiency between empirical correlation

and theoretical model.

(Original in color)

77


25.0 29.3 33.5 37.8 42.0


Figure 4.12 Parity plot o f net efficiency between empirical correlation


(Original in color)

77


4.5 Optimum Operating Conditions

This section presents the optimal operating conditions that would provide the

highest net efficiency possible for the subcritical pulverized coal-fired power plant. The

appropriate net efficiency was obtained by adjusting plant operations according to the

sensitivity analysis and by considering individual effects of process parameters.

Constraint for each parameter was also taken into account.

The first constraint is the moisture content of steam leaving the LP turbine. The

moisture content of LP steam should not be higher than 10% to prevent droplet erosion

problem on turbine blades (Termuehlen and Emsperger, 2003). Temperature of high-

pressure steam is another important constraint. High operating temperature can cause a

severe impact on the pipe (e.g., corrosion). Even though the advanced material

technology allows material to withstand the temperature beyond 600°C (Kjaer, 2002;

NEDO and CCUJ, 2004), the cost of pipe and associated maintenance cost will become

high. In practical, the main steam temperature and reheat temperature should be defined

in a range of 530-545°C for subcritical pulverized coal-fired power stations (Singer,

1991; U.S.DOE, 1999; Kakaras et al., 2002; Sanders, 2004). Regarding the individual

effects of process parameters and the constraints of process variables, the optimal

operating conditions are given in Figure 4.13 and Table 4.4. Note that the results

presented in the figure and table were based on the 425 MW (gross output) subcritical

pulverized coal-fired power plant with the combustion of Illinois #6 bituminous coal.

78



This section presents the optimal operating conditions that would provide the

highest net efficiency possible for the subcritical pulverized coal-fired power plant. The

appropriate net efficiency was obtained by adjusting plant operations according to the

sensitivity analysis and by considering individual effects o f process parameters.

Constraint for each parameter was also taken into account.

The first constraint is the moisture content o f steam leaving the LP turbine. The

moisture content o f LP steam should not be higher than 10% to prevent droplet erosion

problem on turbine blades (Termuehlen and Emsperger, 2003). Temperature o f high-

pressure steam is another important constraint. High operating temperature can cause a

severe impact on the pipe (e.g., corrosion). Even though the advanced material

technology allows material to withstand the temperature beyond 600°C (Kjaer, 2002;

NEDO and CCUJ, 2004), the cost o f pipe and associated maintenance cost will become

high. In practical, the main steam temperature and reheat temperature should be defined

in a range o f 530-545°C for subcritical pulverized coal-fired power stations (Singer,

1991; U.S.DOE, 1999; Kakaras et al., 2002; Sanders, 2004). Regarding the individual

effects o f process parameters and the constraints o f process variables, the optimal

operating conditions are given in Figure 4.13 and Table 4.4. Note that the results

presented in the figure and table were based on the 425 MW (gross output) subcritical

pulverized coal-fired power plant with the combustion o f Illinois # 6 bituminous coal.

78


Reproduced w

ith permission o



ithout permission.

Fu

rnac

eBo

iler

r

Evaporator

0.10312047.67

r40.731477.80

i

Coal 0.103 283.52 350 453.07

0.103 287 (HHV)25 35.42N

/ \ /

\ / \ /

/ ....

H

C/ 3/4 2902.91 12 u 285.211

0.90 3279.8

3.40 3588.4 545.0 287.85

19.00 3401.0 545.0 298.79 403.4 245.76

1

Reheat

Air heater

0.103 473 46.7 453.07

0.1031-251453.07

Air

20.571794.10 187.9 2.64

3.74 2902.9 306.4113.58

19.95 957.8 223.0 298.79

er FWH train

3.74 978.7

co) 19.53 1044.7

0400

O

241.3298.79

T=155.22°C

.58

HP LP

1.05 817.1

2.52 817.1 192.4 31.11

for 0.90

0.90 13279.8 403.4121.31

0.074 2682.4 104.9 10.08

0.22 2868 206 10.74

Lower FWH train 1.67 517.15 1.72 74.95 1.78 268.8 123.0 267.07 89.3 67.07 64.2 267

5.6 127.4 21.31

20.57 794.10 0 187.9 301.43 Boiler feed pump

.223

1.05 772.0 1.62 736.08 181.9 301.43 173.9 267.07

0.03112661.487.6 10.71

0.0062374.736.3 214.24

Condenser

0.006 156.19 36.3 267.

Condensate pump

0.001171.836.3 52.83

1.831158.08 36.31267.07

0.031 71.8 40.8 52.83

535.6 0.074 394.5 0.031 289.7 21.31 32.04

0.223 394.5 0.07 93.7

289.7 32.04 68.7

Figure 4.13 Scheme of subcritical PC at optimal operating conditions.

(For Illinois#6 bituminous coal)

42.12

°C I kg/s

Reproduced

with perm

ission of the

copyright ow

ner. Further


without

permission.

VO

3.40 3588.4545.01287.85

19.00 3401.0 3279.8545.0 298.79 245.76

rVil K 4 rVit=TT sm Rm sin

Evaporator

2902.93 0 6 4 298.79

0.006 2374.7.031 2661.487.6 10.71 214.24

Condenserg j Rh I^I Reheat2902.

3289.2 0.90 3279.83483.6508.7 17.52 403.4 2131

conomize 0.006 156.190.074 2682436.3

Condensate pump267.07104.9 10.08

0.223128683187.910.74

2902.90.103 2047.67 3 0 6 4 1338

940.73 477. 0.006171.8314.52 3 6 3 52.83223.0 298.79Lower FWH tram

1 3 3 158.517.15 374.95 3 6 3 267.07tram 123.0 267.07 267.07 267.0*r0.103 283.52

350 453.07 1.05 817.10.103128734 (HHV)

2s| 35.42 \

\

31.11

2.52 817.1 0.0311713192.4131.11 127421.31 40.8 52.83Air heater

794.100.103 4 7 3 ed pump772.0 1.62

46.71453.07 187.9 30143 21.31 32.04 42.121044.7 736.08298.79 0.223 394.5 0.074 289.7181.9 301.43 173.9 267.07

32.04 68.70.103 -

251453.07

Air155.22°C

MPa kj/kg°C kg/s

Figure 4.13 Scheme o f subcritical PC at optimal operating conditions.

(For fllinois# 6 bituminous coal)

Table 4.4 Optimal process operations for subcritical PC.

Description Optimal Operation

Boiler temperature (°C) 545.0

Reheat temperature (°C) 545.0

HP turbine

1st stage-extract pressure (MPa) 3.74

IP turbine

1s` stage-extract pressure (MPa)

2" stage-extract pressure (MPa)

3rd stage-extract pressure (MPa)

2.52

1.27

0.90

LP turbine


2" stage-extract pressure (MPa) 0.074

3rd stage-extract pressure (MPa) 0.031

4th stage-extract pressure (MPa) 0.0060

Discharge pressure of boiler feed 20.57 pump (MPa) Discharge pressure of condensate 1.83 pump (MPa) Preheated air temperature (°C) 350.0

Excess air (%) 15.0

Pressure drop in FWHs (%) <3.0

Pressure drop in boiler (%) <9.0

Boiler efficiency (%) >92.0

Turbine efficiency (%) >92.0

80


Table 4.4 Optimal process operations for subcritical PC.


Boiler temperature (°C) 545.0Reheat temperature (°C) 545.0HP turbine

1st stage-extract pressure (MPa) 3.74IP turbine

1st stage-extract pressure (MPa) 2.522nd stage-extract pressure (MPa) 1.273rd stage-extract pressure (MPa) 0.90

LP turbine1st stage-extract pressure (MPa) 0.2232nd stage-extract pressure (MPa) 0.0743rd stage-extract pressure (MPa) 0.0314th stage-extract pressure (MPa) 0.0060

Discharge pressure of boiler feed 20.57pump (MPa)Discharge pressure of condensate 1.83pump (MPa)Preheated air temperature (°C) 350.0Excess air (%) 15.0Pressure drop in FWHs (%) <3.0Pressure drop in boiler (%) <9.0Boiler efficiency (%) >92.0Turbine efficiency (%) >92.0

80


4.6 Efficiency Drop due to CO2 Capture

This section reveals the efficiency drop of the subcritical PC after integrating with

the CO2 capture unit. The reference plant obtained from the optimal conditions was

combined with the MEA-based CO2 absorption unit with 90% CO2 removal efficiency.

The investigation of the efficiency drop due to the changes in the CO2 removal efficiency

was conducted.

4.6.1 Application of CO2 Capture Process

It is well recognized that the MEA-based CO2 absorption is the energy-intensive

process. The majority of energy is supplied to the reboiler while other parts of the

process require low energy. In this study, a low pressure steam between the IP and LP

turbines was extracted to the reboiler according to the model conducted by Alie (2006).

The configuration of the subsidiary equipment and units (i.e., pressure control valve,

desuperheater, sump and pump) to control the process steam before entering the reboiler

was adapted from the work done by Fisher et al. (2005). The heat requirement to operate

the reboiler was chosen according to the work experimentally performed by

Sakwattanapong (2005). Energy for solvent regeneration of 4800 kJ/kg CO2 captured was

reported for 90% CO2 removal efficiency. Figure 4.14 conceptually demonstrates the

scheme of the subcritical pulverized coal-fired power plant integrated with the MEA-

based CO2 absorption unit.

81



This section reveals the efficiency drop o f the subcritical PC after integrating with

the CO2 capture unit. The reference plant obtained from the optimal conditions was

combined with the MEA-based CO2 absorption unit with 90% CO2 removal efficiency.

The investigation o f the efficiency drop due to the changes in the CO2 removal efficiency

was conducted.

4.6.1 Application of CO 2 C apture Process

It is well recognized that the MEA-based CO2 absorption is the energy-intensive

process. The majority o f energy is supplied to the reboiler while other parts o f the

process require low energy. In this study, a low pressure steam between the IP and LP

turbines was extracted to the reboiler according to the model conducted by Alie (2006).

The configuration o f the subsidiary equipment and units (i.e., pressure control valve,

desuperheater, sump and pump) to control the process steam before entering the reboiler

was adapted from the work done by Fisher et al. (2005). The heat requirement to operate

the reboiler was chosen according to the work experimentally performed by

Sakwattanapong (2005). Energy for solvent regeneration of 4800 kJ/kg CO2 captured was

reported for 90% CO2 removal efficiency. Figure 4.14 conceptually demonstrates the

scheme o f the subcritical pulverized coal-fired power plant integrated with the MEA-

based CO2 absorption unit.

81


Reproduced w

ith permission o



ithout permission.

Evapo ator

Fur

nace

/Boi

ler

00 0103 047.6

1940.73 477.80

Coal

0. 03 287 25 35.42

1:1

4141 Etr. aff 41

3 40 3588.4 545.0 287.85

H

3.74

H1

19.00 3401.0 545.0 298.79

3.74 12902.9 306.4 298.79

2902.9 28521 RH Reheat

HP

m

04

0.103 314.52 395. 477.80 ;11CI)

0.103 283.52 350 453.07

/

Air heater

0.103 4 46.7 453.07

0.103 25 453.07

Air

)

Up

3.74 2902.9 306.4 13.58

19. 957.8 223. 298.79

2.52 13483.6 508.7 17.52

20.571794.10 187.9 2.64

er FWH train

3.74 978.7 227 13.58

19.53 1044.7 co, 241.3 298.79 9400 44

T=155.22iC

20.57 794.10 187.9 301.43 Boi

1.05 817.1 31.

0.90 3279.8 403. 132.63

0.90 3279.8 403 245.76 0.45

Desuper heater

0.45 104.8 25. 544.4 -to 0.10

25.0

CO2 absorption process/Reboile

0.45 726. 5 3279.8 145.0 677.03

400.

1.2713289.2 0.90 3279.8 414.313.26 403. 2131

232 817.1 -192.4 31.11

Dea rator

0

0.22 .33412868 206. 14.14

132.63

0.074126824104.9 10.30

LP

Lower FWH train .67 517.15 1.72 7495 1.78 68.8

123. 134.44 89.3 34.44 642134

0.90 5.6 127.4 21.31

0.4271153.58123. 132.63

O

0.0312661.4 0.006 2374.7 87.6 9.72 36.3 78.98

Condenser

0.006 156.19 36.3 134.44

Condensate pump

wJJ0.000171.836.3 55.46

1.831158.08 36.31134.44

0.031 171. 40.8 55.46

er feed pump 1.05 772.0 1.62 736.08 181.9 301.43 173. 134.44

0.223 535.6 21.31

0.223 93.7

0.074 394.5 35.44

0.0311289.7

394.5 0.074 289.7 35.44 68.7 45.74

.74

1KFLalc.J/ °C kg/s

e

104.7544.4

41-

[4;

Figure 4.14 Scheme of subcritical PC with MEA-based absorption unit operating at optimal conditions.


Reproduced

with perm

ission of the

copyright ow

ner. Further


without

permission.

C O 2 absorption process/Reboiier

Desuperheater

13588.4 0.90 13279.8545.0| 287.85

3279.1 726.750.45 3279.1

LPHP;h i

Evaporator

3.74 12902.9306.4! 298.79

0.00612374.70.03112661.487.6 19.72 3 63 178.98

CondenserV 3.74 2902.91 m r imi. Rn Reheat

1.27 1 3289.2

0.0061156.193 6 3 1134.44

C ondensate pump

0.0061171.8

187.9|2.643.74 12902.9306.4) 1338^

19.951957.8940.73)477.80

0.103| 31432 3 6 3 |55.46298.79395.94) 477.80Lower FW H train

1.7812681.67 1517.15 363j 134.44Upper FW H trainCoal 0.103128332 3501453.07~ 1.05 1817.1

0.103128734 (HHV) 25] 35.42%

p u t

0.03140.8 55.46A ir heater 3.74 978.7 Deaerator

0.074 0.031 289.7535.62131

0.103|473i87.9)3br43 Boiier U ed pum p

1.05 772.0 1.62181.9)301.43 173.9

45.7446.7)453.07 1044.7 736.(298.79 289.70.223

93.73943 0.074 35.44 68.7

134.44

0.1031- MPal kJ/kg °C | kg/s

25| 453.07

Air

Figure 4.14 Scheme o f subcritical PC with MEA-based absorption unit operating at optimal conditions.


Table 4.5 summarizes the calculated power plant performance before and after

integrated with the MEA-based CO2 absorption unit. The integration of the CO2 capture

unit causes the net efficiency to drop from 39.2% to 27.6%. The ratio of CO2 emitted to

the net power output is decreased from 805.95 to 113.58 kg/MWh (323.38 to 32.34

tonne/hr). However the ratios of other pollutant emissions to the net power output are

slightly increased.

4.6.2 Effect of CO2 Removal Efficiency

The effect of the CO2 removal efficiency of the CO2 capture unit on the net

efficiency of the power plant was also investigated here. Figure 4.15 gives the

relationship between heat duty and lean CO2 loading (mole CO2/ mole MEA) reported in

the literature. According to the figure, the leaner the absorption solvent (low CO2

loading) supplied into the absorber inlet, the higher the energy required for solvent

regeneration (heat duty). The leaner solvent is capable of absorbing more CO2 from the

flue gas. This basically means that the reboiler heat duty per unit CO2 increases with the

increasing CO2 capture efficiency. This trend is used to analyze the effect of the CO2

removal efficiency on the power plant net efficiency point drop as illustrated in Figure

4.16a.

This figure reveals that a higher removal efficiency provides a greater reduction in

the net efficiency. However, when the results were analyzed as a ratio of the net

efficiency point drop to the CO2 removal efficiency, the optimal point for CO2 removal

was identified as shown in Figure 4.16b. The optimal CO2 removal efficiency was found

at 72% CO2 removal efficiency.

83


Table 4.5 summarizes the calculated power plant performance before and after

integrated with the MEA-based CO2 absorption unit. The integration o f the CO2 capture

unit causes the net efficiency to drop from 39.2% to 27.6%. The ratio o f CO2 emitted to

the net power output is decreased from 805.95 to 113.58 kg/MWh (323.38 to 32.34

tonne/hr). However the ratios o f other pollutant emissions to the net power output are

slightly increased.

4.6.2 Effect of CO2 Removal Efficiency

The effect o f the CO2 removal efficiency of the CO2 capture unit on the net

efficiency o f the power plant was also investigated here. Figure 4.15 gives the

relationship between heat duty and lean CO2 loading (mole CO2/ mole MEA) reported in

the literature. According to the figure, the leaner the absorption solvent (low CO2

loading) supplied into the absorber inlet, the higher the energy required for solvent

regeneration (heat duty). The leaner solvent is capable o f absorbing more CO2 from the

flue gas. This basically means that the reboiler heat duty per unit CO2 increases with the

increasing CO2 capture efficiency. This trend is used to analyze the effect o f the CO2

removal efficiency on the power plant net efficiency point drop as illustrated in Figure

4.16a.

This figure reveals that a higher removal efficiency provides a greater reduction in

the net efficiency. However, when the results were analyzed as a ratio o f the net

efficiency point drop to the CO2 removal efficiency, the optimal point for CO2 removal

was identified as shown in Figure 4.16b. The optimal CO2 removal efficiency was found

at 72% CO2 removal efficiency.

83


Table 4.5 Comparison of subcritical PC with and without MEA-based CO2 absorption

unit.

Description PC without MEA-

based CO2 capture

PC with MEA-based CO2

capture

Gross power output MW 424.74 424.74

Energy consumption without MEA-based CO2absorption unit

MW 24.74 24.74

Energy consumption due to MEA-based CO2 absorption unit

MW 116.23

Net power output MW 400.00 283.77

Net efficiency %HHV 39.18 27.62

Coal consumption kg/s 35.42 35.42

CO2 emitted tonne/hr 322.38 32.23

CO2 emitted kg/MWh 805.95 113.58

SO2 emitted tonne/hr 0.44 0.44

SO2 emitted kg/MWh 1.09 1.55

NO emitted tonne/hr 0.24 0.24

NO emitted kg/MWh 0.60 0.84

PM emitted tonne/hr 0.006 0.006

PM emitted kg/MWh 0.016 0.022

84


Table 4.5 Comparison of subcritical PC with and without MEA-based CO2 absorption

unit.

DescriptionPC without MEA-

based co2 capture

PC with MEA- based co2

captureGross power output MW 424.74 424.74Energy consumption without MEA-based C02 absorption unit MW 24.74 24.74

Energy consumption due to MEA-based C02 absorption unit MW - 116.23




C02 emitted tonne/hr 322.38 32.23

C02 emitted kg/MWh 805.95 113.58

S 02 emitted tonne/hr 0.44 0.44

S 02 emitted kg/MWh 1.09 1.55





84


Reb

oil

er H

eat D

uty

(M

J/ k

g C

O2)

8.0

7.0 -

6.0 -

5.0 -

4.0 -

3.0 -

2.0 -

1.0 -

0.0

0.15 0.20 0.25 0.30 0.35 0.40 0.45

Lean CO2 Loading (mole CO2 / mole MEA)

Figure 4.15 Effect of CO2 loading on reboiler heat duty.

(Source: Sakwattanapong, 2005)

85


8.06u 7.0 oc* 6.0

£ 5.0

I* 4-°

i 3 , =$ 2.0

1 1.0 04

0.00.15 0.20 0.25 0.30 0.35 0.40 0.45

Lean CO2 Loading (mole CO2 / mole MEA)

Figure 4.15 Effect o f CO2 loading on reboiler heat duty.

(Source: Sakwattanapong, 2005)

85


Net

Eff

icie

ncy

Po

int D

rop

, 'd

rop

, (%

) nd

rop

/ %

CO

2 R

emov

al

15.75

14.0 -

10.5 -

7.0 -

3.5 -

0.0

0

0.17 0.16 -

0.14 -

0.12 -

0.10 -

0.08 -

0.06 -

0.04 -

0.02 -

0.00

0

25 50 75

CO2 Removal Efficiency (%)

(a)

25 50 75

100

100


(b)

Figure 4.16 Effect of CO2 removal efficiency on net efficiency point drop.

86


15.75

£. 14.0OimT3srr>Q*

g 10.5

7.0

S3w

0.01000 25 50 75

CO2 Removal Efficiency (% )

(a)

0.170.16

° '14£ 0.12| 0.106 0.08 ug 0.06

| 0.04

P 0.02

0.0010050 75250

CO 2 R em oval Efficiency (% )

(b)

Figure 4.16 Effect of CO2 removal efficiency on net efficiency point drop.


Chapter Five

Results and Discussions: Supercritical Coal-Fired Power Plant

This chapter provides the simulation results obtained for the supercritical

pulverized coal-fired power plant. The results presented here can be considered the

extension of results in Chapter Four to cover supercritical operating conditions. Table 5.1

presents maximum-minimum ranges of plant performance. In general, the information

reported in this table are similar to those reported in Table 4.1, except for the range of

their outputs. Under the supercritical condition, the net efficiency can reach as high as

43.2% whereas the maximum net efficiency of the subcritical pulverized coal-fired power

plant is 41.3% (Table 4.1).

Figure 5.1 outlines the sensitivity analysis based on the correlation coefficient of

individual operating parameters. The parametric effects are similar to those in Chapter

Four. It should be noted that for the supercritical pulverized coal-fired power plant, the

pressure of steam extracted from the middle of the HP turbine (the 1st extract) was

included as the additional parameter. It was found that this new parameter had a

significant impact on the net efficiency of the plant.

87


Chapter Five

Results and Discussions: Supercritical Coal-Fired Power Plant

This chapter provides the simulation results obtained for the supercritical

pulverized coal-fired power plant. The results presented here can be considered the

extension of results in Chapter Four to cover supercritical operating conditions. Table 5.1

presents maximum-minimum ranges o f plant performance. In general, the information

reported in this table are similar to those reported in Table 4.1, except for the range of

their outputs. Under the supercritical condition, the net efficiency can reach as high as

43.2% whereas the maximum net efficiency o f the subcritical pulverized coal-fired power

plant is 41.3% (Table 4.1).

Figure 5.1 outlines the sensitivity analysis based on the correlation coefficient o f

individual operating parameters. The parametric effects are similar to those in Chapter

Four. It should be noted that for the supercritical pulverized coal-fired power plant, the

pressure o f steam extracted from the middle o f the HP turbine (the 1st extract) was

included as the additional parameter. It was found that this new parameter had a

significant impact on the net efficiency o f the plant.

87


Table 5.1 Maximum-minimum performance of supercritical PC.

Feature Range a

Thermal efficiency

Steam cycle efficiency 43.57 - 52.13






CO2 emission rate b kg/MWh 747.1 - 975.1

SO2 emission rate b tonne/hr 0.34 - 0.54

SO2 emission avoided b tonne/hr 8.17 - 12.97


SO2 emission avoided b kg/MWh 24.36 - 31.79

NO emission rate tonne/hr 0.13 -- 0.27




PM emission rate b' C tonne/hr 0.0050 - 0.0070

PM emission avoided b' c tonne/hr 4.80 - 7.40

PM emission rate b' c kg/MWh 0.013 - 0.018

PM emission avoided b' c kg/MWh 13.28 - 18.13


02 mole% 2.63 - 3.36

CO2 mole% 14.25 - 14.84

H2O mole% 6.02 - 6.27

N2 mole% 75.73 - 75.86

SO2, NO and others mole% 0.51 - 0.53

a The simulated results are based on a range of the gross outputs between 350 and 450 MW. b The LNB and SCR units remove the NO emission up to 65% and 63% respectively. The FGD unit removes the SO2 emission up to 96%. The electrostatic precipitator (ESP) removes PM up to 99.9% (U.S.DOE, 1999).

The calculation of particulate is based on emission factors for bituminous coal consumption without control equipment (de Nevers, 2000).

88


Table 5.1 Maximum-minimum performance of supercritical PC.

Feature RangeaThermal efficiency

Steam cycle efficiency % 43.57 - 52.13





C 02 emission rate b tonne/hr 256.1 - 394.9

C02 emission rate b kg/MWh 747.1 - 975.1

S 02 emission rateb tonne/hr 0.34 - 0.54

S 02 emission avoided b tonne/hr 8.17 - 12.97

S 02 emission rate b kg/MWh 1.01 - 1.32

S 02 emission avoided b kg/MWh 24.36 - 31.79





PM emission rateb’c tonne/hr 0.0050 - 0.0070

PM emission avoided b’c tonne/hr 4.80 - 7.40

PM emission rate b'c kg/MWh 0.013 - 0.018

PM emission avoided b’c kg/MWh 13.28 - 18.13


o 2 mole% 2.63 - 3.36

O O N> mole% 14.25 - 14.84

h2o mole% 6.02 - 6.27

n 2 mole% 75.73 - 75.86

S 02, NO and others mole% 0.51 - 0.53a The simulated results are based on a range of the gross outputs between 350 and 450 MW. b The LNB and SCR units remove the NO emission up to 65% and 63% respectively. The FGD unit removes the S 02 emission up to 96%. The electrostatic precipitator (ESP) removes PM up to 99.9% (U.S.DOE, 1999).c The calculation of particulate is based on emission factors for bituminous coal consumption without control equipment (de Nevers, 2000).

88


WI

6

Input



Main temperature

Reheat temperature

Boiler efficiency

Turbine efficiency

Excess air

Pressure drop of FWH & boiler

HP inlet

HP 1st extract

HP 2nd extract

IP 1st extract

IP 2nd extract

IP 3rd extract

LP 1st extract

LP 2nd extract

LP 3rd extract

IP outlet


Condensate pressure

Deaerator inlet

-1.00 -0.75 -0.50 -0.25 0.00 0.25 0.50 0.75 1.00

Coefficient

❑ Net efficiency (%) Ea CO2 (tonne/hour) ■ Coal consumption (kg/sec) Output

Figure 5.1 Results of sensitivity analysis by an approach of rank correlation coefficient.

89


InputPreheated air temperature


Main temperature

Reheat temperature

Boiler efficiency

Turbine efficiency

Excess air

Pressure drop o f FWH & boiler

HP inlet

HP 1st extract

HP 2nd extract

IP 1st extract

IP 2nd extract

IP 3rd extract

LP 1st extract

LP 2nd extract

LP 3rd extract

LP outlet


Condensate pressure

Deaerator inlet

-1.00 -0.75 -0.50 -0.25 0.00 0.25 0.50 0.75 1.00

Coefficient

□ Net efficiency (%) H C 02 (tonne/hour) ■ Coal consumption (kg/sec) Output

' 1 11 p

i1

I p

-__11

...... c6□......

i;□......1

gjg 1

1m

■......1

Figure 5.1 Results o f sensitivity analysis by an approach o f rank correlation coefficient.

89


5.1 Individual Parametric Effects

Figure 5.2 illustrates the effects of the free moisture content in coal and the

temperature of the preheated air on the net efficiency of the supercritical pulverized coal-

fired power plant. The effects presented in the figure are identical to those for the

subcritical conditions, i.e., increasing the moisture content by 6% leads to a reduction in

the net efficiency by 2.5 percent point and increasing the preheated air temperature by

80°C results in an increase in the net efficiency by 1.0 percent point.

Figure 5.3 illustrates a proportional relationship between the net efficiency and

the temperature of main and reheated steam generated from the boiler unit. According to

the figure, increasing the temperature of main steam by 28Pc regardless of the

temperature of reheated steam results in an increase in the net efficiency by one half a

percent point. At a given temperature of main steam, the same percent of the net

efficiency point can be achieved by increasing the temperature of reheated steam by

45°C.

Figure 5.4 shows the effects of the turbine and boiler efficiencies on the net

efficiency of the power plant. An increase in the turbine efficiency from 90 to 92% gives

a slight improvement in the net efficiency (i.e. 0.1 percent point) while an increase in the

boiler efficiency by the same magnitude (2%) results in the improvement in the net

efficiency by 0.8 percent point.

The effect of the excess air may be considered unimportant as illustrated in Figure


efficiency drop of 0.03 percent point.

90


5.1 Individual Parametric Effects

Figure 5.2 illustrates the effects o f the free moisture content in coal and the

temperature o f the preheated air on the net efficiency of the supercritical pulverized coal-

fired power plant. The effects presented in the figure are identical to those for the

subcritical conditions, i.e., increasing the moisture content by 6% leads to a reduction in

the net efficiency by 2.5 percent point and increasing the preheated air temperature by

80°C results in an increase in the net efficiency by 1.0 percent point.

Figure 5.3 illustrates a proportional relationship between the net efficiency and

the temperature o f main and reheated steam generated from the boiler unit. According to

the figure, increasing the temperature of main steam by 28°C regardless o f the

temperature o f reheated steam results in an increase in the net efficiency by one half a

percent point. At a given temperature o f main steam, the same percent o f the net

efficiency point can be achieved by increasing the temperature o f reheated steam by

45°C.

Figure 5.4 shows the effects o f the turbine and boiler efficiencies on the net

efficiency o f the power plant. An increase in the turbine efficiency from 90 to 92% gives

a slight improvement in the net efficiency (i.e. 0.1 percent point) while an increase in the

boiler efficiency by the same magnitude (2%) results in the improvement in the net

efficiency by 0.8 percent point.

The effect o f the excess air may be considered unimportant as illustrated in Figure


efficiency drop of 0.03 percent point.

90


36.5 36.0 -

34.5 -u

a 33.0 - W

31.5 -

30.0

250

Free Moisture in Coal (%) o 11.12 a 12.74 A 14.36 x 15.98 x 17.60

275 300 325

Preheated Air Temperature (°C)

350

Figure 5.2 Effects of moisture content in coal and temperature of preheated air.

91


31.5

figure 5.2 Bffects

o <XXXX> <X>CCWC<**eO9B30K»<><3t&<l̂ <>KK>

0 3 0m rjm m rm r m im i* nnrudiiULBm DO COO D

a /wmM mwataeM CJm, ^a a m etxm a ^m

x x xxx&mc

c °a l(% )0 U.12 ° 12.74

4 14.36 x 15.98

* 17.60

Free Moisture in

275

C h e a te d Air T.enipe nature (°q

° f moisture content in coal and ,em peratoeo fp reheateda.r

91

Permission of the „c°Pyright ow ner F u rth ,

36.5

36.0 -

‘g ‘' 35.5 -

35.0 -

W 34.5 -

34.0 -

33.5 -

33.0

530.0

Reheat Temperature (°C)

o 530.0 o 547.5 A 565.0 x 582.5 * 600.0

547.5 565.0 582.5 600.0


Figure 5.3 Effects of main steam and reheated steam temperatures.

92


36.5

36.0 -

aiBw"8£

35.0 \

34.5

34.0

33.5 H

33.0

■rfK. ** •mK A A

S S ifc - '

Reheat Temperature (°Qo 530.0 □ 547.5 A 565.0 x 582.5 x 600.0

530.0 547.5 565.0 582.5 600.0


Figure 5.3 Effects o f main steam and reheated steam temperatures.

92


36.0

Amalla A &AA &A% IAA AthAA LOACIAMIA AM ea&

Net

Eff

icie

ncy

(%) 35.5 -

a UP a Dam a ammo mm 033 oa as ma ED ED 0:1

35.0 -

34.5 -

34.0

90.0

COW) 000 0 0 QM 0 C. 0 0 0 *CO 0 CO 00 CM

Boiler Efficiency (%)

o 90.0

o 91.0

A 92.0

90.5 91.0 91.5


Figure 5.4 Effects of boiler and turbine efficiencies.

93

92.0


36.0

1 35.0S3WtS* 34.5

34.0

AAAA /MS& A A /MftAA rfWV\AAAA A a ft ^

^ 35,5 i odd □□>□ □ ninDDmm cmno □□ mo to no cP

o ^ o o o o O <x» « « > « OOXXDO o «x> oo coo

Boiler Efficiency (% )

o 90.0 □ 91.0 A 92.0

90.0 90.5 91.0 91.5

Turbine Efficiency (% )

92.0

Figure 5.4 Effects o f boiler and turbine efficiencies.

93


Net

Eff

icie

ncy

(%)

16.0 17.0 18.0 19.0 20.0

Excess Air (%)

Figure 5.5 Effect of excess air for coal combustion.

94


35.0

&I&W

34.920.017.0 18.0 19.015.0 16.0

Excess A ir(% )

Figure 5.5 Effect o f excess air for coal combustion.

94


Figure 5.6 shows the effect of the pressure drop in the boiler unit and the FWH

train. It is noticed that the pressure drop in the boiler unit and the FWH trains shows a

small negative impact on the net efficiency of the power plant. An increase in the

pressure drop of the boiler unit by 2% contributes to a slight reduction in the net

efficiency (about 0.2 percent point) while an increase in the pressure drop of the FWH

trains by 2% causes a reduction in the net efficiency by 0.02 percent point.

Figure 5.7 through 5.11 shows the effect of the pressure distribution in the turbine

series. Figure 5.7 demonstrates the effect of the steam pressure extracted at the 1st stage

of the HP turbine on the net efficiency of the power plant. Lowering the 1st stage outlet

pressure from 7.1 to 5.5 MPa can enhance the efficiency by about 1.3 percent points.

Increasing the inlet pressure slightly improves the net efficiency. From the figure, by

keeping the outlet pressure constant at 5.5 MPa, raising the inlet pressure from 22.1 to

25.3 MPa by increasing the pressure ratio from 4.0 to 4.6 enhances the net efficiency by

only 0.13 percent point.

Figure 5.8 shows the effect of the steam pressure leaving the HP turbine.

Apparently, decreasing the outlet pressure below the optimal level (i.e. 4.1-4.3 MPa)

leads to a reduction of the plant efficiency.

Figures 5.9 and 5.10 demonstrate the effect of the steam pressure extracted from

the IP turbine. A reduction in the steam pressure at either the 1st or the 3rd stage of the IP

turbine causes the efficiency drop. Figure 5.9 shows that decreasing the 1St IP outlet

pressure from 2.5 to 2.0 MPa leads to 0.2 percent point reduction. Figure 5.10 shows that

reducing the 3rd IP outlet pressure from 0.9 to 0.6 MPa affects the net efficiency about 1.0

percent point drop.

95


Figure 5.6 shows the effect o f the pressure drop in the boiler unit and the FWH

train. It is noticed that the pressure drop in the boiler unit and the FWH trains shows a

small negative impact on the net efficiency o f the power plant. An increase in the

pressure drop o f the boiler unit by 2% contributes to a slight reduction in the net

efficiency (about 0.2 percent point) while an increase in the pressure drop o f the FWH

trains by 2% causes a reduction in the net efficiency by 0.02 percent point.

Figure 5.7 through 5.11 shows the effect o f the pressure distribution in the turbine

series. Figure 5.7 demonstrates the effect o f the steam pressure extracted at the 1st stage

o f the HP turbine on the net efficiency o f the power plant. Lowering the 1st stage outlet

pressure from 7.1 to 5.5 MPa can enhance the efficiency by about 1.3 percent points.

Increasing the inlet pressure slightly improves the net efficiency. From the figure, by

keeping the outlet pressure constant at 5.5 MPa, raising the inlet pressure from 22.1 to

25.3 MPa by increasing the pressure ratio from 4.0 to 4.6 enhances the net efficiency by

only 0.13 percent point.

Figure 5.8 shows the effect o f the steam pressure leaving the HP turbine.

Apparently, decreasing the outlet pressure below the optimal level (i.e. 4.1-4.3 MPa)

leads to a reduction o f the plant efficiency.

Figures 5.9 and 5.10 demonstrate the effect of the steam pressure extracted from

the IP turbine. A reduction in the steam pressure at either the 1st or the 3rd stage o f the IP

turbine causes the efficiency drop. Figure 5.9 shows that decreasing the 1st IP outlet

pressure from 2.5 to 2.0 MPa leads to 0.2 percent point reduction. Figure 5.10 shows that

reducing the 3rd IP outlet pressure from 0.9 to 0.6 MPa affects the net efficiency about 1.0

percent point drop.

95


35.2

35.1 -

0"

34.9 -7.09

34.7 -

34.5

8.0

Xx op A

Pressure Drop in FWHs (%)

o 3.0 4.0

a 5.0 x 6.0

9.0 10.0

Pressure Drop in Boiler Units (%)

Figure 5.6 Effect of pressure drop in steam cycle.

96

11.0


35.2

35.1 -

C=0s W'

a 34.9 -I &W13I 34 .7-

34.5 -8.0 9.0 10.0 11.0

Pressure Drop in Boiler Units (% )

xxo<> A

Pressure Drop inFWHs (% )

o 3.0□ 4.0 A 5.0 x 6.0

Figure 5.6 Effect o f pressure drop in steam cycle.

96


35.2

7 34.9

•e4.-1 34.5

Z 34.2

Net

Eff

icie

ncy

(%)

33.8

.0400gez'

HP Outle at 1st Stage (MPa) o 5.50

:13 665.

..481231

x 6.74 o 7.05

3.0 3.4 3.8 4.2 4.6

Pressure Ratio, BP Inlet/Outlet at 1st Stage

Figure 5.7 Effect of pressure in the HP stage.

35.9

35.6 -

35.3 -

35.0

4.5 5.5

HP Outlet at 2 nd Stage (MPa) * 3.54 o 3.74 A 3.93 x 4.12 x 4.31 o 4.50

6.5

Pressure Ratio, HP Inlet/Outlet at 2nd Stage

Figure 5.8 Effect of pressure at the 2 nd HP Stage.

97

7.5


35.2

C= 34.9oN

fc*§*8 34.5 S3W

S? 34.2

33.8

a * * * * * * * * 0*

H P O u tle t a t 1st S tage(M P a)o 5.50 a 5.81 a 6 .1 2

x 6.43 x 6.74 o 7.05

3.0 3.4 3.8 4.2 4.6

P re ssu re R a tio , H P In le t/O u tle t a t 1st S tage

F ig u re 5.7 Effect o f pressure in the HP stage.

35.9

35.6 -0ss-/

.1£w

35.3

35.04.5

H P O u tle t a t 2nd S tage (M P a)♦ 3.54□ 3.74a 3.93x 4.12x 4.31

, o 4.50

5.5 6.5 7.5

P re ssu re R a tio , H P In le t/O u tle t a t 2nd S tage

F ig u re 5.8 Effect o f pressure at the 2nd HP Stage

97


Net

Eff

icie

ncy

(%)


Figure 5.9 Effect of pressure at the 1st IP stage.

36.8

36.5 -

e 36.2 - C.> 1:1

.41.4 35.9 -

W ta 35.6 -z

35.3 -

35.0

3.5 4.0 4.5 5.0 5.5 6.0 6.5 7.0 7.5

IP Outlet at 3 rd Stage (MPa)

o 0.60 O 0.70 & 0.80 x 0.90

Pressure Ratio, IP Inlet/Outlet at 3 rd Stage

Figure 5.10 Effect of pressure at the 3rd IP stage.

98


35.9

35.6'■S 0s

bI&W-g 35, fc

3 -

35.0

i / w Outlet a t 1st Stage(MPa)o 2.00 o 2.10 a 2.20 x 2.30 x 2.40 o 2.50

1.2 1.5 1.8 2.1 2.4


Figure 5.9 Effect o f pressure at the 1st IP stage.

IP Outlet a t 3 Stage (MPa)o 0.60 □ 0.70 A 0.80 x 0.90

36.5 -

36.2 -

tS 35.6 £

35.03.5 4.0 4.5 5.0 5.5 6.0 6.5 7.0 7.5

Pressure Ratio, IP Inlet/Outlet a t 3rd Stage

Figure 5.10 Effect o f pressure at the 3rd IP stage.

98


Figure 5.11 indicates that lowering the steam pressure leaving the LP turbine

significantly improves the net efficiency. The finding is similar to the results presented

previously in Chapter Four.

5.2 Efficiency Correlations for Supercritical Pulverized Coal-fired Power Plant

Based on the parametric effects presented in the previous section, empirical

correlations for predicting the net efficiency of the supercritical pulverized coal-fired

power plant were developed by means of regression.

Figure 5.12 shows the reference net efficiency (riref) for a base supercritical power

plant operating under reference conditions (i.e., 25.34 MPa inlet pressure, 5.5 MPa HP

outlet pressure at the 1st stage, 2.6 MPa IP outlet pressure at the la stage and 5.0 kPa

backpressure).

Similar to the case of the subcritical pulverized coal-fired power plant (Chapter

Four), changing the pressure of steam extracted from the middle of either the HP or IP

turbine will change the magnitude of the power plant efficiency. In this case, the

deviation of the net efficiency due to the change in such pressures was obtained through

the regression and can be reported as

A7ip,,Hp2 (a • PHI,/ b• PHp2 +c • Plpi +d • Pm )'(PHpi -5•5 ) (5.1)

+(e•PHPI +J • PHp2 +g • Pipi +h • Pip, )•( 2.6-Pip, )

where a, b, c, d, e, f, g and h are the regression constants with the values of -0.00042,

-0.0008, 0.00414, 0.00438, 0.00295, -0.00174, -0.002 and -0.001, respectively. The

terms of PHp and P. represent the corresponding pressure of steam in the HP or IP

99


Figure 5.11 indicates that lowering the steam pressure leaving the LP turbine

significantly improves the net efficiency. The finding is similar to the results presented

previously in Chapter Four.

5.2 Efficiency Correlations for Supercritical Pulverized Coal-fired Power Plant

Based on the parametric effects presented in the previous section, empirical

correlations for predicting the net efficiency o f the supercritical pulverized coal-fired

power plant were developed by means o f regression.

Figure 5.12 shows the reference net efficiency (r}rej) for a base supercritical power

plant operating under reference conditions (i.e., 25.34 MPa inlet pressure, 5.5 MPa HP

outlet pressure at the 1st stage, 2.6 MPa IP outlet pressure at the 1st stage and 5.0 kPa

backpressure).

Similar to the case o f the subcritical pulverized coal-fired power plant (Chapter

Four), changing the pressure o f steam extracted from the middle o f either the HP or IP

turbine will change the magnitude o f the power plant efficiency. In this case, the

deviation o f the net efficiency due to the change in such pressures was obtained through

the regression and can be reported as

HPi ,HP2 .IP] .IPs ~ ( a ' PH P; + ̂ ‘ P h P2 + C ' ^ IP j ' ̂ I P 3 ) ' ( ^ H P , ~ 5 ' $ )

+ ( e - P h p j f ' P h p 2 ^ 8 ‘ f * iP i ' P 1 P 3 ) ' ( 2 - 6 - P [ p t )

where a, b, c, d, e, f g and h are the regression constants with the values o f -0.00042,

-0.0008, 0.00414, 0.00438, 0.00295, -0.00174, -0.002 and -0.001, respectively. The

terms of PHP. and P,p represent the corresponding pressure o f steam in the HP or IP

99


Net

Eff

icie

ncy

(%)

38.0

37.5 -

37.0 -

36.5 -

36.0 -

35.5 -

35.0 -

34.5

80.0

LP Outlet at 4th Stage (kPa) o 5.00 a 5.50 a 6.00 x 6.40 x 6.80

105.0 130.0 155.0 180.0



100


38.0

37.5 -

? 37.0 -

a 36.5 -.aS 36.0 - wu£ 35.5 -

35.0 -

34.5 -80.0 105.0 130.0 155.0 180.0


Figure 5.11 Effect o f pressure at the last LP stage.

LP Outlet at 4 (kPa)o 5.00 □ 5.50A 6.00x 6.40 x 6.80

th Stage


36.5 IP Outlet at 3 rd Stage (MPa)

3.2 3.4 3.6 3.8 4.0 4.2 4.4

HP Outlet at 2nd Stage (MPa)

4.6

Figure 5.12 Reference net efficiency of base supercritical PC.

(Base condition: 25.34 MPa HP inlet pressure, 5.5 MPa HP outlet pressure at 1st stage,

2.6 MPa IP outlet pressure at 1st stage and 5.0 kPa backpressure)

101


36.5IP Outlet at 3 “ Stage (MPa)

36.00.83N®0s

i-P"£.S,a

35.5 0.750.68

35.00.60

34.5

4) 34.0

33.5

33.03.2 3.4 3.6 3.8 4.0 4.2 4.4 4.6

HP Outlet at 2nd Stage (MPa)

Figure 5.12 Reference net efficiency of base supercritical PC.

(Base condition: 25.34 MPa HP inlet pressure, 5.5 MPa HP outlet pressure at 1st stage,

2.6 MPa IP outlet pressure at 1st stage and 5.0 kPa backpressure)

101


turbine extracted at ith-stage. The net efficiency of the supercritical pulverized coal-fired

power plant can be defined as

r1 net net = r ref — A 7 1HPI ,HP2 ,IPI ,IP3 (5.2)

The // ref value can be obtained from Figure 5.12 while the efficiency variation can be

calculated from Equation (5.1). To include the effects of other process parameters,

Equation (5.2) was modified and is presented in the following form

7 net = Olref Ar ?HP' ,HP2 JP] JP3 ) + 0.016 •( 20.0 — Ea) +[0..39•( 11

)( 17.6 — F.) + 2.05•( H — 4.9 )] 28

117

81 8

+ 0.012•(Tair — 250.0 )+ 0.018 • (T — 530.0 )+ 0.011• (Tr — 530.0 )+ 0.40•(th.der — 90.0 ) (5.3)

+ 0.057 • — 90.0 )— 0.11. (Pdrop —6.0)

where Eair, Fm, Tair, Tm, Tr, ?Moiler, and Pdrop represent the excess air (%), the free



pressure drop (%), respectively. The HHV and H represent the high heating value (kJ/kg

coal) and hydrogen content of coal used (percent by weight).

It should be noted that Equation (5.3) is valid for the process parameters and types

of coals as given in Tables 3.3 and 4.3, respectively. A parity plot between the efficiency

calculated from the empirical correlation and that from the power plant model is

illustrated in Figure 5.13. The R2 of 0.99 indicates an excellent prediction from the

empirical correlation.

102


turbine extracted at ith-stage. The net efficiency o f the supercritical pulverized coal-fired

power plant can be defined as

^1 net = T l r e f ~ ^ HP{ ,HP2 ,/P, ,/P3 ( 5 -2)

The rjref value can be obtained from Figure 5.12 while the efficiency variation can be

calculated from Equation (5.1). To include the effects o f other process parameters,

Equation (5.2) was modified and is presented in the following form

0 3 9 ' (^ 8 } 0 ? ' 6 " F J + 2-05 ' ( H ~ 4'9)Vnet ~ (tfref .IP] ,IP3 ) + 6 •( 20.0 Ea) +

+ 0.012 ■ (Tair - 250.0) + 0.018 -(Tm- 530.0) + 0.01 l-(Tr - 530.0) + 0.40■ (rjMkr - 9 0 .0 ) (5 ‘3 )

+ 0.057 ■ (nT - 90.0) - 0 .1 1 • (Pdrop - 6 .0)

where Eair, Fm, Tair, Tm, Tr, rjboiier, r\T and Pdrop represent the excess air (%), the free



pressure drop (%), respectively. The HHV and H represent the high heating value (kJ/kg

coal) and hydrogen content o f coal used (percent by weight).

It should be noted that Equation (5.3) is valid for the process parameters and types

o f coals as given in Tables 3.3 and 4.3, respectively. A parity plot between the efficiency

calculated from the empirical correlation and that from the power plant model is

illustrated in Figure 5.13. The R2 o f 0.99 indicates an excellent prediction from the

empirical correlation.

102


-54

44.0

39.3

0..4 CJ 1:1

.2.4 C.)

lig34.5

Ei 29.8

25.0

-

* Bituminou

a Subbiturnitiois

Lignite

25.0 29.8 34.5 39.3

2 = 0 99

44.0


Figure 5.13 Parity plot of net efficiency between empirical correlation


(Original in color)

103


a"o'w "g

fc IA r9 .2 UA

■8 - H *E g *©.55 S W

44.0

39.3

34.5

29.8

o Bituminous » Subbitumino

Lignite

ubbitummous

Bituminous

25.025.0 29.8 34.5 39.3 44.0

Net Efficiency (%) ~ Power Plant Theoretical Model

Figure 5.13 Parity plot o f net efficiency between empirical correlation


(Original in color)

103



The optimal operation of the supercritical pulverized coal-fired power plant can

be identified by changing the operating conditions and considering the individual effects

of process parameters as previously mentioned. However, a few parameters must be

carefully considered to allow the power plant to practically operate. In this study, the

moisture content of steam leaving any turbines is limited to 10% to prevent the

operational problem (Termuehlen and Emsperger, 2003). There is no limitation for main

and reheat temperatures in the steam power cycle since the material used for the boiler

tube was assumed to be ferritic and austenitic that could withstand the temperature up to

600°C (NEDO and CCUJ, 2004). Based on such constraints, the optimal operating

conditions are given in Figure 5.14 and Table 5.2. It should be noted that the results

presented in the figure and table were based on the 425 MW (gross output) supercritical

pulverized coal-fired power plant with the combustion of Illinois #6 bituminous coal.

104



The optimal operation o f the supercritical pulverized coal-fired power plant can

be identified by changing the operating conditions and considering the individual effects

o f process parameters as previously mentioned. However, a few parameters must be

carefully considered to allow the power plant to practically operate. In this study, the

moisture content o f steam leaving any turbines is limited to 10% to prevent the

operational problem (Termuehlen and Emsperger, 2003). There is no limitation for main

and reheat temperatures in the steam power cycle since the material used for the boiler

tube was assumed to be ferritic and austenitic that could withstand the temperature up to

600°C (NEDO and CCUJ, 2004). Based on such constraints, the optimal operating

conditions are given in Figure 5.14 and Table 5.2. It should be noted that the results

presented in the figure and table were based on the 425 MW (gross output) supercritical

pulverized coal-fired power plant with the combustion o f Illinois #6 bituminous coal.

104


Reproduced w

ith permission o



ithout permission.

r --

Evaporator

0.103 11940.7

Coal

3.29 37133 600 262.43

RH1

C0110MIZ r

Reheat

4.31 2968.7 337.9 1958

2047.6 0.103 314.52 b 29.92 1099.8 30.85 957.8 451.71 395.94 451.71 el) 2$2.7 285.78 223.0 285.78

Upper FWD ain

.103 28734 33.59

0.103 350

283.52 429.91

0.103 4

.02 1175 68.1 285.78

Air heater

46.7 29.91

8000

0.103 25 429.91

Air

.31 122.9 11.18

232

530 1122.9 334 978.7 257.1 11.18 2273 30.75

25.34 3485.7 600 285.78

1 41

5.50 3048.0 380.9 11.18

2.52 13507 519.1 14.42

31.80806.8190.81 7.41

2.52 830.2 195.3

978.7 31.8 30.75 190.8

45.17

1.05 830.2 5.17

488

IP

1.27 13310.0 423.9 9.07

Deaerator 806.8 293.19

11.05 772.0 181.9 293.19

Boiler feed pump

0.9

0.9 3300.9 413.2 220.03

0.9

LP

3300.9 413.2 18.92

0.07412695.4111.518.98

0.22312886.8214.4 9.57

0.00512357.133.1 190.70

Condense

0.031126 3.8 94.0 10.79 0.005 142. 2

33.1 23815

Condensate pump

1.67 517.15 1.72 374.95 1.78 268.80 123.0 238.95 89.3 238.95 64.2 238.95

0.223 535.6

535.6

18.92

0.223

ower F train

- 28.49

394.5 0.074

0.031

1.831144.3633.1 238.95

0.031 158.3 37.6 48.25

289.7

289.7 127.4 18.92 93.7 28.49 68.7 37.46

Figure 5.14 Scheme of supercritical PC at optimal operating conditions.


37.46

0.0051158.333.1 48.25

MPa kJ/ ° C kg/s

Reproduced

with perm

ission of the

copyright ow

ner. Further


without

permission.

600 1262.430.913300.9

413.2] 220.03

LPEvaporator

5.50 13048.0 0.00512357.1 33.1 1190.70380.9| 11.18

0.913300.9111.5] 8.98413.2] 18.92

Condense]ReheatRH

0.031126'2.52 135070.005| 142.52 33.1 ] 238.95

423.9] 9.07 214.4] 9 ^ 7 94.0 110.794.31 12968.7 31.801xonom 190.817̂ 41

Condensate pump

374.95 1.78 238.95,642

268.!957.1 1.67 517.15 1.720.1031314.52 29.92110998 30.85 252.7 285.78 223.0

Upj er FWH0.10312047.6

123.0 238.95 ,893 238.95395.94|451.71

trainCoal0.00511583

I 0.103| 28332~ t 350 1429.91

>.02 1175.1I.103l 28734 [4537285.78

33.592.52 1830.2

0.031115831953 45.17Air heater 37.6 ] 48.25Deaerator

1 CT n \ I 1.05 [772.0\ S 5 ' 181.9] 293.19

Boiler feed pump0.9

535.6 0.074 394.5 0.031 289.70.223978.7 31.8 1806.81122.9 18.921.103] 473 11.18 30.75 190.8] 293.1946.7 1429.911

3 9 4 3 0.074 289.7535.6 032318.92 93.7

978.71122.9 3 34 28.49 68.7 37.4611.18 2273 30.75257.10.1031 MPal kJ/kg

°C I kg /s

Figure 5.14 Scheme o f supercritical PC at optimal operating conditions.

(For Hlinois#6 bituminous coal)

Table 5.2 Optimal process operations for supercritical PC.


Boiler temperature (°C) 600.0

Reheat temperature (°C) 600.0

HP turbine


2" stage-extract pressure (MPa) 3.29

IP turbine

stage-extract pressure (MPa)

2" stage-extract pressure (MPa)

Std stage-extract pressure (MPa)

2.52

1.27

0.90

LP turbine


2 nd z stage-extract pressure (MPa) 0.074

Std stage-extract pressure (MPa) 0.031

4th stage-extract pressure (MPa) 0.0050

Discharge pressure of boiler feed pump (MPa)

31.8

Discharge pressure of condensate pump (MPa) Preheated air temperature (°C)

1.83

350.0

Excess air (%) 15.0

Pressure drop in FWHs (%) <3.0

Pressure drop in boiler (%) <9.0

Boiler efficiency (%) >92.0

Turbine efficiency (%) >92.0

106


Table 5.2 Optimal process operations for supercritical PC.


Boiler temperature (°C) 600.0Reheat temperature (°C) 600.0HP turbine

1st stage-extract pressure (MPa) 25.342nd stage-extract pressure (MPa) 3.29

IP turbine1st stage-extract pressure (MPa) 2.522nd stage-extract pressure (MPa) 1.273rd stage-extract pressure (MPa) 0.90

LP turbine1st stage-extract pressure (MPa) 0.2232nd stage-extract pressure (MPa) 0.0743rd stage-extract pressure (MPa) 0.0314m stage-extract pressure (MPa) 0.0050

Discharge pressure of boiler feed 31.8pump (MPa)Discharge pressure of condensate 1.83pump (MPa)Preheated air temperature (°C) 350.0Excess air (%) 15.0Pressure drop in FWHs (%) <3.0Pressure drop in boiler (%) <9.0Boiler efficiency (%) >92.0Turbine efficiency (%) >92.0

106



This section reveals the efficiency drop due to the integration of the CO2 capture

unit into the supercritical pulverized coal-fired power plant. The reference plant obtained

from the optimal conditions was the MEA-based CO2 absorption unit with 90% CO2

removal efficiency.

Figure 5.15 illustrates the schematic diagram of the supercritical pulverized coal-

fired power plant integrated with the MEA-based CO2 absorption unit. Details of the

CO2 capture unit can be found in Section 4.6 presented earlier. Table 5.3 summarizes the

calculated power plant performance before and after integrated with the MEA-based CO2

absorption unit. The integration of the CO2 capture causes the net efficiency to drop from

43.1% to 31.4%. The ratio of CO2 emitted to the net power output decreased from 764.3

to 107.4 kg/MWh (305.72 to 30.57 tonne/hr). A comparison of the energy penalty due to

the CO2 capture between the subcritical and supercritical pulverized coal-fired power

plants is given in Figure 5.16.

For the effect of the CO2 removal efficiency on the net efficiency of the

supercritical pulverized coal-fired power plant, the finding is similar to the case of the

subcritical pulverized coal-fired power plant. Figure 5.17 shows the magnitude of the

energy penalty per unit of the CO2 removal efficiency. Apparently, the optimal removal

efficiency can be identified at 72% CO2 removal efficiency.

107



This section reveals the efficiency drop due to the integration o f the CO2 capture

unit into the supercritical pulverized coal-fired power plant. The reference plant obtained

from the optimal conditions was the MEA-based CO2 absorption unit with 90% CO2

removal efficiency.

Figure 5.15 illustrates the schematic diagram of the supercritical pulverized coal-

fired power plant integrated with the MEA-based CO2 absorption unit. Details o f the

CO2 capture unit can be found in Section 4.6 presented earlier. Table 5.3 summarizes the

calculated power plant performance before and after integrated with the MEA-based CO2

absorption unit. The integration of the CO2 capture causes the net efficiency to drop from

43.1% to 31.4%. The ratio of CO2 emitted to the net power output decreased from 764.3

to 107.4 kg/MWh (305.72 to 30.57 tonne/hr). A comparison o f the energy penalty due to

the CO2 capture between the subcritical and supercritical pulverized coal-fired power

plants is given in Figure 5.16.

For the effect o f the CO2 removal efficiency on the net efficiency of the

supercritical pulverized coal-fired power plant, the finding is similar to the case o f the

subcritical pulverized coal-fired power plant. Figure 5.17 shows the magnitude o f the

energy penalty per unit o f the CO2 removal efficiency. Apparently, the optimal removal

efficiency can be identified at 72% CO2 removal efficiency.

107


Reproduced w

ith permission o



ithout permission.

Fu

rnac

e/B

oil

er

r

Evaporator

0.103 11940

Coal

28734

C.

0.103 283.52

2.‘ 33.59 / 350 429.91

Icromiir

0.103 314.52 395.94 451.71

Reheat

4.31 2968.7 337.9 19.58

V 29.92 1099.8 30.85 957.8 04 2p.7 285.78 223.0 285.78

Upper FWH train

.02 1175. 1 285.78

Air heater

429.9

25 429.9

41J 5.50 1122.9 354 978.7

00 257.1 11.18 227.5 30.75

339 37133

25.34 3485.7 600 285.78

2.52 13507

31.801806.8 519.1 14.42

190.817.41

2.52195.3 45.17

Deaerator 978.7 31.8 806.8 30.75 190.8 293.19

% 1 1.05 772.0) 181.9 293.19

Boiler feed pump

0.45 104.8 25.02 512.0 0.10 104.7

25.0

Desuper-402 absorptionheater process/Reboile

0.9 3300.9 413.24.20 045 3300.9

409.9 124.1

0-9

0.45 734.2 145.0 636.1

0.07412695.4111.5 9.17

0.421157.46123.7 124.1

0.00512357.133.1 164.50

Condens

94.31 0 9.

2670 0.005 142 2

.0 .8

33.1 114.85

Condensate pump

1.67 517.15 1.72 374.95 1.78 268.80 123.0 114.85 89.3 114.85 64.2 114.85

Lower FWH train

1.831144.3633.11114.85

0.0051158.3 33.1 150.35

0.223 535.6 0.074394.5 0.031 289.7 0.031 158.3 1%) ---- 18.92 - 31.48 - 40.65 37.6 50.35

535.6 0.223 394.5 0.074 289.7 127.4 18.92 93.7 31.48 68.7 40.65

AL'a11 rc.J °C kg/s

512.0

Figure 5.15 Scheme of supercritical PC with MEA-based absorption unit operating at optimal conditions.


Reproduced

with perm

ission of the

copyright ow

ner. Further


without

permission.

o00

CO 2 absorption process/Reboiler

Desuperheater

•'Vii )..... IrVI _Vj—“ S f f i RH2 SHI

Evaporator j

LP

5.50 13048.0 O.OOSl2357.1

CondensiReheatRH

252 13507423.9| 9.074-11 12968.7 33.1 1114^5

Condensate pump

517.15 1.7229.9211099.8 30.85 252.7 285.78 223.0

U p jerF W H395J>4| 451.71

trainCoal1.05 1830.2I 0-10312835?

. SCO 4-943 OS1.103128734 [45472.32 1830.

Air heater Deaerator0“ I 1.051772.0J 181.91293.19

Boiler feed pump

0.0311289.7 0.031 1583978.7 31.30.75 190^|293.19

394.5 0.074

11.18 227.5MPa kJ/kg°C I kg/sAir

Figure 5.15 Scheme o f supercritical PC with MEA-based absorption unit operating at optimal conditions.


Table 5.3 Comparison of supercritical PC with and without MEA-based CO2 absorption

unit.

Description PC without MEA-

based CO2capture

PC with MEA-based CO2

capture

Gross power output MW 425.29 425.29

Energy consumption without MEA-based CO2absorption unit

MW 25.29 25.29

Energy consumption due to MEA-based CO2 absorption unit

MW 115.27




CO2 emitted tonne/hr 305.72 30.57

CO2 emitted kg/MWh 764.30 107.36

SO2 emitted tonne/hr 0.42 0.42

SO2 emitted kg/MWh 1.04 1.46





109


Table 5.3 Comparison o f supercritical PC with and without MEA-based CO2 absorption

unit.

DescriptionPC without MEA-

based C 0 2 capture

PC with MEA- based C 0 2

captureGross power output MW 425.29 425.29Energy consumption without MEA-based C02 absorption unit MW 25.29 25.29

Energy consumption due to MEA-based C02 absorption unit MW - 115.27




C02 emitted tonne/hr 305.72 30.57

C02 emitted kg/MWh 764.30 107.36

S02 emitted tonne/hr 0.42 0.42

S02 emitted kg/MWh 1.04 1.46





109


Net

Eff

icie

ncy

(%)

60

55 -

50

45 -

40 -

35 -

30 -

25 -

20

15 -

10 -

5

Subcritical Power Plant Supercritical Power Plant

Figure 5.16 Comparison of energy penalty

between subcritical and supercritical PCs.

110


a>

£§

"8£

□ Without C 02 capture With C 02 capture

43.0839.18

31.4427.62

Subcritical Power Plant Supercritical Power Plant

Figure 5.16 Comparison of energy penalty

between subcritical and supercritical PCs.

110


lum

p /

%C

O2

Rem

oval

0.17 0.16 -

0.14 -

0.12 -

0.10 -

0.08 -

0.06 -

0.04 -

0.02 -

0.00

o Subcritical coal-fired power plant

A Supercritical coal-fired power plant

0 25 50 75


100

Figure 5.17 Magnitude of energy penalty per unit of CO2 removal efficiency.

111


0.170.16 -

0.14 -14>o 0.12 -S£ 0.10 -

0 0.08 -uo ' 0.06 -—.

a.£ 0.04 -■o

0.02 -

0.00 -

§

o Subcritical coal-fired power plant a Supercritical coal-fired power plant

25 50 75 100

C 0 2 Removal Efficiency (% )

Figure 5.17 Magnitude o f energy penalty per unit o f C 0 2 removal efficiency.

I l l


Chapter Six

Economic Assessment

This chapter focuses on an economic assessment to reveal the cost of electricity

based on both subcritical and supercritical pulverized coal-fired power plants. The

assessment was based on a year-by-year basis counting effects of time, escalation rate

and present worth discount rate are performed to give comprehensive understanding on

economic analysis.

6.1 Economic Basis

Generally, the cost of structure of any industrial plants includes two main

components; fixed cost and operating cost. The fixed cost is commonly referred to as

capital investment associated with equipment cost, material cost, labor cost, engineering

cost, contingency cost, insurance, taxes, land costs, indirect cost and allowance for funds

used during construction (AFUDC). The operating cost includes operating and

maintenance cost (O&M cost), consumable cost (e.g., water, chemical, electricity), fuel

cost and others consumed during plant operation (Singer, 1991; Drbal et al., 1996; U.S.

DOE, 1999). The capital investment is basically converted to annual cost taking place

year-by-year during electric power produced. The operating cost is commonly presented

as the expense per kilowatt-hour of electricity ($/kWh). The sum of capital investment

and operating cost is referred to as cost of electricity (COE). The equation can be written

by

112


Chapter Six

Economic Assessment

This chapter focuses on an economic assessment to reveal the cost o f electricity

based on both subcritical and supercritical pulverized coal-fired power plants. The

assessment was based on a year-by-year basis counting effects o f time, escalation rate

and present worth discount rate are performed to give comprehensive understanding on

economic analysis.

6.1 Economic Basis

Generally, the cost o f structure o f any industrial plants includes two main

components; fixed cost and operating cost. The fixed cost is commonly referred to as

capital investment associated with equipment cost, material cost, labor cost, engineering

cost, contingency cost, insurance, taxes, land costs, indirect cost and allowance for funds

used during construction (AFUDC). The operating cost includes operating and

maintenance cost (O&M cost), consumable cost (e.g., water, chemical, electricity), fuel

cost and others consumed during plant operation (Singer, 1991; Drbal et al., 1996; U.S.

DOE, 1999). The capital investment is basically converted to annual cost taking place

year-by-year during electric power produced. The operating cost is commonly presented

as the expense per kilowatt-hour o f electricity ($/kW h). The sum o f capital investm ent

and operating cost is referred to as cost o f electricity (COE). The equation can be written

by

112


COE = ( TCR )

+(0M+FC+CC+OC) CF • Pw

(6.1)

where TCR, CF and P,„, represent total capital investment ($/year or $/hr), capacity factor

(%) and power output (kW) while OM, FC, CC and OC denote operating and

maintenance cost, fuel cost, consumable cost and other operating costs ($/kWh).

The conversion of the capital investment as previously mentioned is on a basis of

annual cost that decreases year-by-year (Drbal et al., 1996; Bohm, 2006). In other words

it does not remain constant throughout the entire lifetime of the plant. To normalize the

electricity cost, a factor of levelized fixed charge rate (FCF) must be included in the

calculation. Therefore, Equation (6.1) can be rewritten as

COE =( TCR

FCF + (OM + FC + CC + OC) (6.2) CF • Pw

The above equation is commonly used in several cost studies (Griffiths and Marr-Laing,

2002; Metz et al., 2005). The following is a discussion of the other parameters associated

with the economic assessment.

6.1.1 Allowance for Funds Used during Construction

AFUDC is a charge made by the owner for borrowing the construction fund. The

total AFUDC is considered an extra cost added into the capital investment. The equation

is expressed by (Drbal et al., 1996)

AFUDC rate = (/ + i)'" (6.3)

where i represents monthly or annual interest rate (%) and m represents number of

months or years before the plant is placed in service.

113


COE =C F -P

+ ( OM + FC + CC + OC) (6.1)w J

where TCR, CF and Pw represent total capital investment ($/year or $/hr), capacity factor

(%) and power output (kW) while OM, FC, CC and OC denote operating and

maintenance cost, fuel cost, consumable cost and other operating costs ($/kWh).

The conversion o f the capital investment as previously mentioned is on a basis o f

annual cost that decreases year-by-year (Drbal et al., 1996; Bohm, 2006). In other words

it does not remain constant throughout the entire lifetime o f the plant. To normalize the

electricity cost, a factor o f levelized fixed charge rate (FCF) must be included in the

calculation. Therefore, Equation (6.1) can be rewritten as

COE =C F P

FCF + (O M + FC + CC + OC) (6 .2)w J

The above equation is commonly used in several cost studies (Griffiths and Marr-Laing,

2002; Metz et al., 2005). The following is a discussion o f the other parameters associated

with the economic assessment.

6.1.1 Allowance for Funds Used during Construction

AFUDC is a charge made by the owner for borrowing the construction fund. The

total AFUDC is considered an extra cost added into the capital investment. The equation

is expressed by (Drbal et al., 1996)

AFUDC rate = (/ + i)m (6.3)

where i represents monthly or annual interest rate (%) and m represents number of

months or years before the plant is placed in service.

113


6.1.2 Levelized Fixed Charge Rate of Capital Cost

For any industrial plants placed in service, the annual fixed charge is composed of

several cost components, including debt, federal and provincial (or state) income taxes,

plant depreciation, property taxes, insurances and other administrator costs. Among these

costs, plant depreciation, property, taxes, insurances and other administrative costs

constantly reduce the capital requirement throughout the entire plant lifetime. However,

the other two cost components (an increase of return on debt and equity and decrease of

income taxes) significantly reduce the capital requirement over the years as illustrated in

Figure 6.1. The reduction in these costs can be estimated by the present worth factor.

Present worth factor = 1(1+ j)"

(6.4)

where j and n are present worth discount rate (%) and number of years placed in service,

respectively.

The fixed charge rate of capital cost is levelized by the sum of the present worth

of each annual cost divided by the total present worth factor given in Equation (6.4). Its

equation can be simplified by

Levelized fixed charge = E annual cost a x 1

1=1l + fi n

114

1i=1 a ± P n

(6.5)


6.1.2 Levelized Fixed Charge Rate of Capital Cost

For any industrial plants placed in service, the annual fixed charge is composed of

several cost components, including debt, federal and provincial (or state) income taxes,

plant depreciation, property taxes, insurances and other administrator costs. Among these

costs, plant depreciation, property, taxes, insurances and other administrative costs

constantly reduce the capital requirement throughout the entire plant lifetime. However,

the other two cost components (an increase o f return on debt and equity and decrease of

income taxes) significantly reduce the capital requirement over the years as illustrated in

Figure 6.1. The reduction in these costs can be estimated by the present worth factor.

where j and n are present worth discount rate (%) and number o f years placed in service,

respectively.

The fixed charge rate o f capital cost is levelized by the sum of the present worth

Present worth factor = o+jr (6.4)

of each annual cost divided by the total present worth factor given in Equation (6.4). Its

equation can be simplified by

^ annual cost n x

Levelized fixed charge = (6.5)

114


20-

Return on debt and equity

State and federal income taxes

Properties, taxes, insurances, and other administrative costs

Depreciation (straight line)

Year in service

Figure 6.1 Levelized fixed charge rate for capital cost.

(Source Drbal et al., 1996)

115

End of book life


20 »

15Return on debt

and equity

State and federal income taxes

5 - Properties, taxes, insurances, and other administrative costs

Depreciation (straight line)

End of1 2 3Year in service book life

Figure 6.1 Levelized fixed charge rate for capital cost.

(Source Drbal et al., 1996)

115


6.1.3 Levelized Operating Cost

The operating cost can be varied by the effects of several factors such as present

worth discount rate and annual escalation rate. The operating cost can be levelized by the

following equation (Drbal et al., 1996).

Levelized operating cost = (cost at beginning of first year) x (CRF) x 1-Kn (6.6a) j -es

1 + es K —

1 + j

l•CRF — (1+

(1 + j)° — 1

(6.6b)

(6.6c)

where es, j and n represent annual escalation rate (%), present worth discount rate (%)

and number of years placed in service.

6.1.4 Present Worth Cost

It is commonly known that time is the main factor indicating the present worth

cost. Even though a cost value shown in future is higher than the value in the present

time, it does not mean that the future value is worth more than the current value. For

comparison purposes, the cost values reported at different time periods must convert to

the present values (PV) using the following equation. (Singer, 1991; Drbal et al., 1996)

( 1+ :1) n —1 PV =US x kl±it

(6.7)

where US, j and n denote uniform series present worth factor, present worth discount rate

(%) and number of years placed in service.

116


6.1.3 Levelized Operating Cost

The operating cost can be varied by the effects o f several factors such as present

worth discount rate and annual escalation rate. The operating cost can be levelized by the

following equation (Drbal et al., 1996).

l _ K nLevelized operating cost = (cost at beginning o f first year) x (CRF) x ------- (6.6a)

j-es

K = (6.6b)* + j

CRF = + (6.6c)( l + j ) n - l

where es, j and n represent annual escalation rate (%), present worth discount rate (%)

and number o f years placed in service.

6.1.4 Present Worth Cost

It is commonly known that time is the main factor indicating the present worth

cost. Even though a cost value shown in future is higher than the value in the present

time, it does not mean that the future value is worth more than the current value. For

comparison purposes, the cost values reported at different time periods must convert to

the present values (PV) using the following equation. (Singer, 1991; Drbal et al., 1996)

P V = U S x (1 + ~ J (6.7)j ( l + j ) n

where US, j and n denote uniform series present worth factor, present worth discount rate

(%) and number o f years placed in service.

116


6.2 Cost of Electricity of Pulverized Coal-Fired Power Plants

This section summaries the evaluation of electricity cost derived from both

subcritical and supercritical pulverized coal-fired power plant operations. The cost

evaluation was performed for a reference power plant (425 MW gross output) with and

without the CO2 capture unit. The economic inputs used in the evaluation are given in

Table 6.1. The calculation results are presented in Table 6.2. Note that the results

presented in the table were obtained for Illinois#6 bituminous coal and 90% CO2 removal

efficiency.

From the table, cost of electricity from the subcritical pulverized coal-fired power

plant with and without the CO2 capture unit is slightly lower than the cost from the

supercritical pulverized coal-fired power plant (i.e. 4.30 and 8.19 0/kWh for the

subcritical, and 4.37 and 8.20 0/kWh for the supercritical pulverized coal-fired power

plants without and with the CO2 capture unit). This finding is consistent with the results

from other studies (U.S.DOE, 1999; Kraemer et al., 2004; Bohm, 2006). Based on

U.S.DOE (1999) the capital requirement for supercritical pulverized coal-fired power

plant is higher than subcritical pulverized coal-fired power plant (i.e. $1226.7/kW for the

subcritical pulverized coal-fired power plant and $1274.6/kW for the supercritical

pulverized coal-fired power plant). This leads to a higher cost of the supercritical-based

electricity.

117


6.2 Cost of Electricity of Pulverized Coal-Fired Power Plants

This section summaries the evaluation o f electricity cost derived from both

subcritical and supercritical pulverized coal-fired power plant operations. The cost

evaluation was performed for a reference power plant (425 MW gross output) with and

without the CO2 capture unit. The economic inputs used in the evaluation are given in

Table 6.1. The calculation results are presented in Table 6.2. Note that the results

presented in the table were obtained for Illinois#6 bituminous coal and 90% CO2 removal

efficiency.

From the table, cost of electricity from the subcritical pulverized coal-fired power

plant with and without the CO2 capture unit is slightly lower than the cost from the

supercritical pulverized coal-fired power plant (i.e. 4.30 and 8.19 0/kWh for the

subcritical, and 4.37 and 8.20 0/kWh for the supercritical pulverized coal-fired power

plants without and with the CO2 capture unit). This finding is consistent with the results

from other studies (U.S.DOE, 1999; Kraemer et al., 2004; Bohm, 2006). Based on

U.S.DOE (1999) the capital requirement for supercritical pulverized coal-fired power

plant is higher than subcritical pulverized coal-fired power plant (i.e. $1226.7/kW for the

subcritical pulverized coal-fired power plant and $1274.6/kW for the supercritical

pulverized coal-fired power plant). This leads to a higher cost o f the supercritical-based

electricity.

117


Table 6.1 Economic inputs.

Parameter Reference

Economic life 35.0 years Griffiths and Marr-Laing (2002)

Construction period 4.0 years Drbal et al. (1996)

Annual escalation rate 7.0 Drbal et al. (1996)

Present worth discount rate 11.5 % Drbal et al. (1996)

Capacity factor 85.0 % U.S.DOE (1999)

Allowance for funds used during construction (AFUDC)

25.0 % Drbal et al. (1996)

Total plant cost 1129a $/kW U.S.DOE (1999) (no MEA-based CO2 capture) 11731' Total plant cost + MEA-based 2090a $/kW David and Herzog CO2 capture 2130 (2000) MEA consumption 1.5 kg MEA Hendriks (1994)

tonne CO,

MEA reagent cost 1250 $/tonne MEA Rao and Rubin (2002)

Operating & maintenance 10662a $/kWh U.S.DOE (1999) (O&M) cost (no consumable cost and fuel cost)

11064"

Consumable operating cost 5152 $/kWh U.S.DOE (1999)

Other capital investment cost 41V $/kWh U.S.DOE (1999) 42.51'

Fuel cost 33719' $/kWh U.S.DOE (1999)

a The given value is used for the subcritical pulverized coal-fired power plant. b The given value is used for the supercritical pulverized coal-fired power plant.

The given value is based on the 400 MW-based power plant with 38.97 kg coal/s and 9577 kJ/kWh. The supplied coal is Illinois#6 bituminous coal (U.S.DOE, 1999)

118


Table 6.1 Economic inputs.

Parameter ReferenceEconomic life 35.0 years Griffiths and Marr-

Laing (2002)Construction period 4.0 years Drbal et al. (1996)Annual escalation rate 7.0 % Drbal et al. (1996)Present worth discount rate 11.5 % Drbal et al. (1996)Capacity factor 85.0 % U.S.DOE (1999)Allowance for funds used during construction (AFUDC)

25.0 % Drbal et al. (1996)

Total plant cost(no MEA-based C 02 capture)

1129“1173b

$/kW U.S.DOE (1999)

Total plant cost + MEA-based C 02 capture

2090“2134b

$/kW David and Herzog (2000)

MEA consumption 1.5 kg MEA tonne C 0 2

Hendriks (1994)

MEA reagent cost 1250 $/tonne MEA Rao and Rubin (2002)

Operating & maintenance (O&M) cost (no consumable cost and fuel cost)

10662“11064b

$/kWh U.S.DOE (1999)

Consumable operating cost 5152 $/kWh U.S.DOE (1999)Other capital investment cost 41.0“

42.5b$/kWh U.S.DOE (1999)

Fuel cost 33719° $/kWh U.S.DOE (1999)a The given value is used for the subcritical pulverized coal-fired power plant. b The given value is used for the supercritical pulverized coal-fired power plant.c The given value is based on the 400 MW-based power plant with 38.97 kg coal/s and 9577 kJ/kWh. The

supplied coal is Illinois#6 bituminous coal (U.S.DOE, 1999)

118


Table 6.2 Results of economic analysis for subcritical and supercritical PCs with and

without MEA-based CO2 absorption unit.

Description

Without MEA-based CO2capture unit

With MEA-based CO2capture unit

Subcritical PC

Supercritical PC

Subcritical PC

Supercritical PC

Gross power output MW 424.74 425.29 424.74 425.29

Energy consumption without MEA-based

MW 24.74 25.29 24.74 25.29

Energy consumption from MEA-based CO2capture unit

MW 116.23 115.27

Net power output MW 400.00 400.00 283.77 284.73

Capital requirement $/kW 1129.20 1173.40 2090.00 2134.40

Allowance for funds used during construction

$/kW 282.30 293.35 522.50 533.60

Total plant investment $/kW 1411.50 1466.75 2612.50 2668.00

Other capital investment cost

$/kW 41.00 42.50 41.00 42.50

Total capital requirement

$/kW 1452.50 1509.25 2653.50 2710.50

0/kWh 2.75 2.86 5.02 5.13

Total operating and maintenance cost

$x1.000 10.66 11.06 15.03 15.54

Total consumable operating costs

$x1000 5.15 5.15 9.00 8.88

Fuel cost $x1000 30.46 28.89 42.93 40.58

Levelized cost of electricity (calculated at 85% capacity factor)

0/kWh 4.30 4.37 8.19 8.20

119


Table 6.2 Results o f economic analysis for subcritical and supercritical PCs with and

without MEA-based CO2 absorption unit.

Description

Without MEA-based C02 capture unit

With MEA-based C02 capture unit

Subcritical Supercritical PC PC

SubcriticalPC

SupercriticalPC

Gross power output MW 424.74 425.29 424.74 425.29

Energy consumption without MEA-based

MW 24.74 25.29 24.74 25.29

Energy consumption from MEA-based C 02 capture unit

MW 116.23 115.27

Net power output MW 400.00 400.00 283.77 284.73

Capital requirement $/kW 1129.20 1173.40 2090.00 2134.40

Allowance for funds used during construction

$/kW 282.30 293.35 522.50 533.60

Total plant investment $/kW 1411.50 1466.75 2612.50 2668.00

Other capital investment cost

$/kW 41.00 42.50 41.00 42.50

Total capital requirement

$/kW 1452.50 1509.25 2653.50 2710.50

0/kWh 2.75 2.86 5.02 5.13

Total operating and maintenance cost

SxlOOO 10.66 11.06 15.03 15.54

Total consumable operating costs

SxlOOO 5.15 5.15 9.00 8.88

Fuel cost SxlOOO 30.46 28.89 42.93 40.58

Levelized cost of electricity (calculated at 85% capacity factor)

0/kWh 4.30 4.37 8.19 8.20

119


However, it should be noticed that the supercritical pulverized coal-fired power plant

offers the higher net efficiency than the subcritical pulverized coal-fired power plant.

This means that the simple calculation for cost of electricity may not be the real indicator.

Therefore, cost of electricity difference year-by-year and capital equivalent method

should be considered to reveal the true effect. The results based on more complex

calculation are given in Figures 6.2 and 6.3. Figure 6.2 shows a rapid increase in cost of

electricity difference within the first 10 years before gradual drop. Regardless of the CO2

capture activity, the supercritical pulverized coal-fired power plant offers a lower cost of

electricity difference. This implies that cost of supercritical pulverized coal-fired power

plant may be lower than the subcritical pulverized coal-fired power plant. The economic

advantage of the supercritical pulverized coal-fired power plant can be seen more clearly

in Figure 6.3 when the present worth of operating cost is added to the total fixed charge

of capital cost on year-by-year basis throughout the plant lifetime. From the figure, the

cumulative present worth of annual cost for the supercritical pulverized coal-fired power

plants with and without CO2 capture is higher than the subcritical pulverized coal-fired

power plants with and without CO2 capture during the first 7th and 9th years of operation.

However, the cumulative present worth for the supercritical pulverized coal-fired power

plants becomes lower than that for the subcritical pulverized coal-fired power plants after

7th and 9th years of operation. The difference is significant in terms of the total cost when

the cumulative present worth is multiplied by the net power output. This suggests that

not only the supercritical pulverized coal-fired power plant gives a higher plant

performance and lower air pollutions, but also it offers a better economic cost than the

subcritical pulverized coal-fired power plant does.

120


However, it should be noticed that the supercritical pulverized coal-fired power plant

offers the higher net efficiency than the subcritical pulverized coal-fired power plant.

This means that the simple calculation for cost o f electricity may not be the real indicator.

Therefore, cost o f electricity difference year-by-year and capital equivalent method

should be considered to reveal the true effect. The results based on more complex

calculation are given in Figures 6.2 and 6.3. Figure 6.2 shows a rapid increase in cost of

electricity difference within the first 10 years before gradual drop. Regardless o f the CO2

capture activity, the supercritical pulverized coal-fired power plant offers a lower cost of

electricity difference. This implies that cost o f supercritical pulverized coal-fired power

plant may be lower than the subcritical pulverized coal-fired power plant. The economic

advantage o f the supercritical pulverized coal-fired power plant can be seen more clearly

in Figure 6.3 when the present worth o f operating cost is added to the total fixed charge

o f capital cost on year-by-year basis throughout the plant lifetime. From the figure, the

cumulative present worth o f annual cost for the supercritical pulverized coal-fired power

plants with and without CO2 capture is higher than the subcritical pulverized coal-fired

th fhpower plants with and without CO2 capture during the first 7 and 9 years o f operation.

However, the cumulative present worth for the supercritical pulverized coal-fired power

plants becomes lower than that for the subcritical pulverized coal-fired power plants after

7th and 9th years o f operation. The difference is significant in terms o f the total cost when

the cumulative present worth is multiplied by the net power output. This suggests that

not only the supercritical pulverized coal-fired power plant gives a higher plant

performance and lower air pollutions, but also it offers a better economic cost than the

subcritical pulverized coal-fired power plant does.

120


2.5

2.0 -

0.0

,att

4 I/

'

.0- -P 0 -a

P A 11 71 , lai ots

..,1 so

la 813 t 8 843

ob 'n'0

A 'a 1:3

sa ,0

'A 13 'Li

Subcritical PC without MEA-based CO2 absorption

° o Supercritical PC without MEA-based CO2 absorption

0 Subcritical PC with MEA-based CO2 absorption o

Supercritical PC with MEA-based CO2 absorption

0.0 5.0 10.0 15.0 20.0 25.0 30.0 35.0

Year in Service

Figure 6.2 Cost of electricity (COE) difference, (0/kWh, year, - yearn-1).

121


COE

Diff

eren

ce,

COE

year

- COE

ye

ar-i,

O'/k

Wh)

2.5

2.0

1.5

1.0

0.5 -

/A> T a ' q

P / "A 13Aa A~n" SA Vio'A ^

Ati

f

isorntion ption

□ Subcritical PC with MEA-based CO2 absorption

I

* * * * « « « *

/ • * * » „ 5 * 4

1 /i p _1 1 O Subcritical PC without MEA-based CO2 absorption w=06=$,

i ? p;

p A ^ A u j /~ ^r\ f: 0 ©

1 r o Supercritical PC without MEA-based CO2 absorption

/©1/ A Supercritical PC with MEA-based CO2 absorption

0 . 0 V ----------------- 1------------------ !------------------ 1-------------------1------------------ 1------------

0.0 5.0 10.0 15.0 20.0 25.0 30.0 35.0

Year in Service

Figure 6.2 Cost o f electricity (COE) difference, (0/kWh, yearn - yearn_i).

121


Cu

mu

lati

ve

Pre

sen

t Wo

rth

of A

nnual

Cos

t ($/

kW)

30000

25000 -

20000 -

15000 -

10000 -

5000 6

* Subcritical PC without MEA-based CO2 absorption

O Subcritical PC with MEA-based CO2 absorption

O Supercritical PC without MEA-based CO2 absorption

A Supercritical PC with MEA-based CO2 absorption

()Cumulative Present Worth Cost at 0th year Subcritical PC with MEA = 4534.2 $/kW Supercritical PC with MEA = 4628.9 $/kW

()Cumulative Present Worth Cost at 7th year Subcritical PC with MEA = 8405.7 $/kW Supercritical PC with MEA = 8387.2 $/kW

©Cumulative Present Worth Cost at 356 year Subcritical PC with MEA = 26170.9 $/kW Supercritical PC with MEA = 25632.9 $/kW

®Cumulative Present Worth Cost at 0th year Subcritical PC without MEA = 2490.4 $/kW Supercritical PC without MEA = 2587.7 $/kW

C)Cumulative Present Worth Cost at 9th year Subcritical PC without MEA = 6340.8 $/kW Supercritical PC without MEA = 6340.7 $/kW

()Cumulative Present Worth Cost at 35th year Subcritical PC without MEA = 17347.7 $/kW Supercritical PC without MEA = 17069.4 $/kW

4

0 5 7 910 15 20

Year in Service

Figure 6.3 Capital recovery period.

122

25 30 35


Cum

ulat

ive

Pres

ent

Wor

th

of An

nual

Cos

t ($

/kW

)30000

25000

20000

15000

10000

5000

>k Subcritical PC without MEA-based C02 absorption O Subcritical PC with MEA-based C02 absorption O Supercritical PC without MEA-based C02 absorption A Supercritical PC with MEA-based C02 absorption

© Cumulative Present Worth Cost at 0 year Subcritical PC with MEA =4534.2 $/kW Supercritical PC with MEA = 4628.9 S/kW© Cumulative Present Worth Cost at 7th year Subcritical PC with MEA = 8405.7 $/kW Supercritical PC with MEA = 8387.2 $/kW© Cumulative Present Worth Cost at 35111 year Subcritical PC with MEA = 26170.9 $/kW Supercritical PC with MEA = 25632.9 $/kW <

© .

&

$

©4

© Cumulative Present Worth Cost at 0th year Subcritical PC without MEA = 2490.4 $/kW Supercritical PC without MEA = 2587.7 $/kW© Cumulative Present Worth Cost at 91*1 year Subcritical PC without MEA = 6340.8 $/kW Supercritical PC without MEA = 6340.7 $/kW© Cumulative Present Worth Cost at 35th year Subcritical PC without MEA = 17347.7 $/kW Supercritical PC without MEA = 17069.4 S/kW

5 7 910 15 20 25 30 35

Year in Service

Figure 6.3 Capital recovery period.

122


6.3 Sensitivity Analysis for Electricity Cost

The objective of this section is to identify major economic parameters affecting

cost of electricity and also to reveal the effect of CO2 capture cost. The sensitivity

analysis by an approach of the rank correlation coefficient was carried out for a number

of parameters including capital requirement, energy consumption, net efficiency, fuel

cost, allowance for funds used during construction, operating and maintenance cost,

consumable operating cost, MEA reagent and other capital investment costs. The

economic inputs for the simulation are summarized in Table 6.3.

Figure 6.4 demonstrates the analysis results presented as the absolute value of

correlation coefficient of individual parameters. Based on the subcritical pulverized coal-

fired power plant, the influential parameters presented in descending order of importance

are energy consumed by the CO2 capture unit, capital requirement for the plant reference,

the net efficiency, the capital requirement for the CO2 capture, the fuel cost, the

allowance for funds used during construction, the operating and maintenance cost, the

consumable operating cost, other capital investment cost and the MEA reagent cost. For

the supercritical pulverized coal-fired power plant, the total capital requirement is the

major influential parameter. In addition, the effect of the net efficiency falls behind the

capital cost. According to the plant efficiency, the supercritical pulverized coal-fired

power plant obviously shows the superior net efficiency than the subcritical pulverized

coal-fired power plant (i.e. 27.62 and 31.44% net efficiency for the subcritical and

supercritical pulverized coal-fired power plants integrated with the CO2 capture units,

respectively). As the net efficiency had already been improved, other parameters (i.e.

capital cost) becomes more sensitive to the cost of electricity.

123


6.3 Sensitivity Analysis for Electricity Cost

The objective o f this section is to identify major economic parameters affecting

cost o f electricity and also to reveal the effect o f CO2 capture cost. The sensitivity

analysis by an approach o f the rank correlation coefficient was carried out for a number

o f parameters including capital requirement, energy consumption, net efficiency, fuel

cost, allowance for funds used during construction, operating and maintenance cost,

consumable operating cost, MEA reagent and other capital investment costs. The

economic inputs for the simulation are summarized in Table 6.3.

Figure 6.4 demonstrates the analysis results presented as the absolute value of

correlation coefficient o f individual parameters. Based on the subcritical pulverized coal-

fired power plant, the influential parameters presented in descending order o f importance

are energy consumed by the CO2 capture unit, capital requirement for the plant reference,

the net efficiency, the capital requirement for the CO2 capture, the fuel cost, the

allowance for funds used during construction, the operating and maintenance cost, the

consumable operating cost, other capital investment cost and the MEA reagent cost. For

the supercritical pulverized coal-fired power plant, the total capital requirement is the

major influential parameter. In addition, the effect o f the net efficiency falls behind the

capital cost. According to the plant efficiency, the supercritical pulverized coal-fired

power plant obviously shows the superior net efficiency than the subcritical pulverized

coal-fired power plant (i.e. 27.62 and 31.44% net efficiency for the subcritical and

supercritical pulverized coal-fired power plants integrated with the CO2 capture units,

respectively). As the net efficiency had already been improved, other parameters (i.e.

capital cost) becomes more sensitive to the cost o f electricity.

123


Table 6.3 Ranges of economic inputs for analysis of electricity cost.

Parameter Distribution Reference

Economic life 35.0 years Fixed Griffiths and Man-Laing (2002)

Construction period 4.0 years Fixed Drbal et al. (1996)

Annual escalation rate 7.0 Fixed Drbal et al. (1996)

Present worth discount rate 11.5 % Fixed Drbal et al. (1996)

Capacity factor 85.0 Fixed U.S.DOE (1999)

Allowance for funds used during construction (AFUDC)

25.0 % Triangular distribution Drbal et al. (1996)

Total plant cost 1129a $/kW Triangular distribution U.S.DOE (1999) (no MEA-based CO2 capture) 1173bTotal plant cost + MEA-based 2090a $/kW Triangular distribution David and Herzog CO2 capture 2134" (2000) MEA consumption 1.5 kg MEA Triangular distribution Hendriks (1994)

tonne CO,

MEA reagent cost 1250 $/tonne MEA Triangular distribution Rao and Rubin (2002)

Operating & maintenance 10662a $/kWh Triangular distribution U.S.DOE (1999) (O&M) cost (no consumable cost and fuel cost)

11064"

Consumable operating cost 5152 $/kWh Triangular distribution U.S.DOE (1999)

Other capital investment cost 41.0a $/kWh Triangular distribution U.S.DOE (1999) 42.5"

Fuel cost 33719c $/kWh Triangular distribution U.S.DOE (1999)

a The given value is used for the subcritical pulverized coal-fired power plant. b The given value is used for the supercritical pulverized coal-fired power plant.

The given value is based on the 400 MW-based power plant with 38.97 kg coal/s and 9577 kJ/kWh. The supplied coal is Illinois#6 bituminous coal (U.S.DOE, 1999)

124


Table 6.3 Ranges of economic inputs for analysis of electricity cost.

Parameter Distribution ReferenceEconomic life 35.0 years Fixed Griffiths and Marr-

Laing (2002)Construction period 4.0 years Fixed Drbal et al. (1996)Annual escalation rate 7.0 % Fixed Drbal etal. (1996)Present worth discount rate 11.5 % Fixed Drbal et al. (1996)Capacity factor 85.0 % Fixed U.S.DOE (1999)Allowance for funds used during construction (AFUDC)

25.0 % Triangular distribution Drbal et al. (1996)

Total plant cost(no MEA-based CO2 capture)

1129“1173b

$/kW Triangular distribution U.S.DOE (1999)

Total plant cost + MEA-based C02 capture

2090“2134b

$/kW Triangular distribution David and Herzog (2000)

MEA consumption 1.5 kg MEA tonne C02

Triangular distribution Hendriks (1994)

MEA reagent cost 1250 $/tonne MEA Triangular distribution Rao and Rubin (2002)

Operating & maintenance (O&M) cost (no consumable cost and fuel cost)

10662“11064b

$/kWh Triangular distribution U.S.DOE (1999)

Consumable operating cost 5152 $/kWh Triangular distribution U.S.DOE (1999)Other capital investment cost 41.0“

42.5b$/kWh Triangular distribution U.S.DOE (1999)

Fuel cost 33719° $/kWh Triangular distribution U.S.DOE (1999)“ The given value is used for the subcritical pulverized coal-fired power plant. b The given value is used for the supercritical pulverized coal-fired power plant.c The given value is based on the 400 MW-based power plant with 38.97 kg coal/s and 9577 kJ/kWh. The

supplied coal is Illinois#6 bituminous coal (U.S.DOE, 1999)

124


1.00

0.50

0.00

■ Supercritical coal-fired power plant

❑ Subcritical coal-fired power plant

a b c d e f g

a : Energy consumed by CO2 capture

b : Capital requirement (no CO2 capture cost) c : Net efficiency

d : Capital requirement for CO2 capture e : Fuel cost

h i j

f : Allowance for funds used during construction g : Operating and maintenance cost h : Consumable operating cost

i : Other capital investment cost j : MEA reagent cost

Figure 6.4 Results of sensitivity analysis for cost of electricity.

125


1.00

a>

0.50

■ Supercritical coal-fired power plant □ Subcritical coal-fired power plant

0.00

a : Energy consumed by CO2 capture b : Capital requirement (no CO2 capture cost) c : Net efficiencyd : Capital requirement for CO2 capture e : Fuel cost

e f g h 1 j

f : Allowance for funds used during construction g : Operating and maintenance cost h : Consumable operating cost i : Other capital investment cost j : MEA reagent cost

Figure 6.4 Results o f sensitivity analysis for cost o f electricity.

125


Chapter Seven

Conclusions and Future Work

7.1 Conclusions

This study is focused on a variety of the process designs and operations, the

developed power plant model, the optimal operation and the economic features in the

subcritical and supercritical pulverize coal-fired power plants for both with and without

the MEA-based CO2 absorption unit. This report is anticipated to give substantial

contributions to engineers and power industries working in project development, financial

analysis and environmental planning. Followings are the conclusions of this research.

• The major operating and design parameters affecting the net efficiency of the

pulverized coal-fired power plants are the moisture content in coal, the pressure

operations at the high-pressure, intermediate-pressure and low-pressure turbines,

the boiler efficiency, the preheated air temperature, the temperature of main steam

and the temperature of reheated steam.

• The supercritical pulverized coal-fired power plant offers a higher net efficiency

than the subcritical pulverized coal-fired power plant by a factor of 2.0 to 3.9

percent point depending upon the degree of the CO2 capture. Furthermore, the

supercritical pulverized coal-fired power plant generates a lower CO2 emission,

compared to the subcritical pulverized coal-fired plant. About 5.2 to 5.5 percent

reduction can be obtained.

126


Chapter Seven

Conclusions and Future Work

7.1 Conclusions

This study is focused on a variety o f the process designs and operations, the

developed power plant model, the optimal operation and the economic features in the

subcritical and supercritical pulverize coal-fired power plants for both with and without

the MEA-based CO2 absorption unit. This report is anticipated to give substantial

contributions to engineers and power industries working in project development, financial

analysis and environmental planning. Followings are the conclusions o f this research.

• The major operating and design parameters affecting the net efficiency o f the

pulverized coal-fired power plants are the moisture content in coal, the pressure

operations at the high-pressure, intermediate-pressure and low-pressure turbines,

the boiler efficiency, the preheated air temperature, the temperature o f main steam

and the temperature of reheated steam.

• The supercritical pulverized coal-fired power plant offers a higher net efficiency

than the subcritical pulverized coal-fired power plant by a factor o f 2.0 to 3.9

percent point depending upon the degree o f the CO2 capture. Furthermore, the

supercritical pulverized coal-fired power plant generates a lower CO2 emission,

compared to the subcritical pulverized coal-fired plant. About 5.2 to 5.5 percent

reduction can be obtained.

126


• The key to arriving at the optimal operation of the subcritical pulverized coal-

fired power plant is to operate pressure at 19.0 MPa HP inlet pressure with 5.1 HP

pressure ratio between the inlet and the outlet, at 3.4 MPa IP inlet pressure with

3.8 IP pressure ratio between the inlet and the 3rd stage outlet and at 0.9 MPa LP

inlet pressure with the 150.0 LP pressure ratio between the inlet and the

backpressure outlet as well as the temperature of main steam and reheated steam

at 545°C, the temperature of preheated air at 350°C, the boiler and turbine

efficiencies above 92%, and the lowest possible moisture content in coal. The

optimal operation of the supercritical pulverized coal-fired power plant can be

achieved by operating pressure at 25.3 MPa HP inlet pressure with the 4.6 HP

pressure ratio between the inlet and the 1St stage outlet, at 3.29 MPa IP inlet

pressure with the 3.7 IP pressure ratio between the inlet and the 3rd stage outlet

and at 0.9 MPa LP inlet pressure with the 180.0 LP pressure ratio between the

inlet and the backpressure outlet as well as the temperature of main steam and

reheated steam at 600°C.

• The integration of the MEA-based CO2 absorption unit into both subcritical and

supercritical pulverized coal-fired power plants causes a significant reduction in

the net efficiency up to 14.9 percent point (based on 97% CO2 removal

performance).

• The high percent CO2 removal performance relatively causes a high net efficiency

point drop but is not proportional to the net efficiency point drop per %CO2

removal efficiency. It was found that 97% CO2 removal efficiency gave the

highest net efficiency point drop while 72% CO2 removal performance offered the

127


• The key to arriving at the optimal operation o f the subcritical pulverized coal-

fired power plant is to operate pressure at 19.0 MPa HP inlet pressure with 5.1 HP

pressure ratio between the inlet and the outlet, at 3.4 MPa IP inlet pressure with

3.8 IP pressure ratio between the inlet and the 3rd stage outlet and at 0.9 MPa LP

inlet pressure with the 150.0 LP pressure ratio between the inlet and the

backpressure outlet as well as the temperature o f main steam and reheated steam

at 545°C, the temperature o f preheated air at 350°C, the boiler and turbine

efficiencies above 92%, and the lowest possible moisture content in coal. The

optimal operation o f the supercritical pulverized coal-fired power plant can be

achieved by operating pressure at 25.3 MPa HP inlet pressure with the 4.6 HP

pressure ratio between the inlet and the 1st stage outlet, at 3.29 MPa IP inlet

pressure with the 3.7 IP pressure ratio between the inlet and the 3rd stage outlet

and at 0.9 MPa LP inlet pressure with the 180.0 LP pressure ratio between the

inlet and the backpressure outlet as well as the temperature o f main steam and

reheated steam at 600°C.

• The integration o f the MEA-based CO2 absorption unit into both subcritical and

supercritical pulverized coal-fired power plants causes a significant reduction in

the net efficiency up to 14.9 percent point (based on 97% CO2 removal

performance).

• The high percent CO2 removal performance relatively causes a high net efficiency

point drop but is not proportional to the net efficiency point drop per %CC>2

removal efficiency. It was found that 97% CO2 removal efficiency gave the

highest net efficiency point drop while 72% CO2 removal performance offered the

127


optimal CO2 removal efficiency with the lowest net efficiency point drop per

%CO2 removal efficiency.

• The cost of electricity for the subcritical and supercritical pulverized coal-fired

power plants (with and without the CO2 capture unit) is nearly closed to each

other. However, the cumulative present worth of annual cost reveals that, after

about a quarter of plant lifetime, the supercritical pulverized coal-fired power

plant offers a lower cumulative cost.

• From the sensitivity analysis, the cost of electricity depends on the capital

requirement of the power plant, the energy consumption owing to the CO2 capture

unit, the capital requirement of the CO2 capture unit, the net efficiency, the fuel

cost, the allowance for funds used during construction, the operating and

maintenance cost, the consumable operating cost, other capital investment costs

and the MEA reagent cost as sequence.

7.2 Future Work

• The ultra-supercritical pulverized coal-fired power plant which is the most

advanced steam-power cycle, and other types of power plants such as PFB, CFB

and IGCC should be investigated.

• Other CO2 capture technologies besides the MEA-based CO2 absorption unit

should be evaluated.

• The algorithm code written in Microsoft Excel" should be rewritten in a

graphical-based computer program so that it is more users friendly.

128


optimal CO2 removal efficiency with the lowest net efficiency point drop per

% C 02 removal efficiency.

• The cost o f electricity for the subcritical and supercritical pulverized coal-fired

power plants (with and without the C 0 2 capture unit) is nearly closed to each

other. However, the cumulative present worth o f annual cost reveals that, after

about a quarter o f plant lifetime, the supercritical pulverized coal-fired power

plant offers a lower cumulative cost.

• From the sensitivity analysis, the cost o f electricity depends on the capital

requirement o f the power plant, the energy consumption owing to the C 0 2 capture

unit, the capital requirement o f the C 0 2 capture unit, the net efficiency, the fuel

cost, the allowance for funds used during construction, the operating and

maintenance cost, the consumable operating cost, other capital investment costs

and the MEA reagent cost as sequence.

7.2 Future W ork

• The ultra-supercritical pulverized coal-fired power plant which is the most

advanced steam-power cycle, and other types o f power plants such as PFB, CFB

and IGCC should be investigated.

• Other CO2 capture technologies besides the MEA-based C 0 2 absorption unit

should be evaluated.

• The algorithm code written in Microsoft Excel® should be rewritten in a

graphical-based computer program so that it is more users friendly.

128


List of References

Alie, C. (2004). CO2 Capture with MEA: Integrating the Absorption Process and Steam Cycle of an Existing Coal-Fired Power Plant : M.A.Sc. Thesis, University of Waterloo, Waterloo, Ontario, Canada.

Aroonwilas, A. and Veawab, A. (2007). Integration of CO2 Capture Unit Using Single-and Blend-Amines into Supercritical Coal-Fired Power Plants: Implications for Emission and Energy Management. International Journal of Greenhouse Gas Control. 1(2), 143-150.

Beer, J.M. (2000). Combustion Technology Developments in Power Generation in Response to Environmental Challenges. Progress in Energy and Combustion Science. 26(4), 301-327.

Bohm, M.C. (2006). Capture-Ready Power Plants — Options, Technologies and Economics: MSc. (TPP) Thesis, Massachusetts Institute of Technology, Cambridge, Massachusetts.

Canadian Electricity Association (CEA). (2006). Power Generation in Canada: A Guide.

Chattopadhyay, P. (2000). Boiler Operation Engineering-Questions and Answers : 2nd

Edition, McGraw-Hill, New York.

Cicconardi, S.P.; Gaggio, G.; Lensi, R. and Spazzafumo, G. (1991). Sensitivity Analysis of a PFB-CC Power System. Proceeding of the Intersociety Energy Conversion Engineering Conference. 26(5), 487-492.

Crystal Ball. (2004). Crystal Ball 7: User Manual. Decisioneering Inc., MAN-CBUM 070001-1.

David, J. and Herzog, H. (2000). The Cost of Carbon Capture. The 5th International Conference on Greenhouse Gas Control Technologies, August 13-16, Cairns, Australia.

de Nevers, N. (2000). Air Pollution Control Engineering : 2nd Edition, McGraw-Hill Higher Education, New York.

Desideri, U. and Paolucci, A. (1999). Performance Modeling of a Carbon Dioxide Removal System for Power Plants. Energy Conversion and Management. 40(18), 1899-1917.

129


List of References

Alie, C. (2004). CO2 Capture with MEA: Integrating the Absorption Process and Steam Cycle o f an Existing Coal-Fired Power Plant : M.A.Sc. Thesis, University o f Waterloo, Waterloo, Ontario, Canada.

Aroonwilas, A. and Veawab, A. (2007). Integration of CO2 Capture Unit Using Single- and Blend-Amines into Supercritical Coal-Fired Power Plants: Implications for Emission and Energy Management. International Journal o f Greenhouse Gas Control. 1(2), 143-150.

Beer, J.M. (2000). Combustion Technology Developments in Power Generation in Response to Environmental Challenges. Progress in Energy and Combustion Science. 26(4), 301-327.

Bohm, M.C. (2006). Capture-Ready Power Plants - Options, Technologies and Economics: M.Sc. (TPP) Thesis, Massachusetts Institute o f Technology, Cambridge, Massachusetts.

Canadian Electricity Association (CEA). (2006). Power Generation in Canada: A Guide.

Chattopadhyay, P. (2000). Boiler Operation Engineering-Questions and Answers : 2nd Edition, McGraw-Hill, New York.

Cicconardi, S.P.; Gaggio, G.; Lensi, R. and Spazzafiimo, G. (1991). Sensitivity Analysis o f a PFB-CC Power System. Proceeding o f the Intersociety Energy Conversion Engineering Conference. 26(5), 487-492.

Crystal Ball. (2004). Crystal Ball 7: User Manual. Decisioneering Inc., MAN-CBUM 070001-1.

David, J. and Herzog, H. (2000). The Cost o f Carbon Capture. The 5th International Conference on Greenhouse Gas Control Technologies, August 13-16, Cairns, Australia.

de Nevers, N. (2000). Air Pollution Control Engineering : 2nd Edition, McGraw-Hill Higher Education, New York.

Desideri, U. and Paolucci, A. (1999). Performance Modeling o f a Carbon Dioxide Removal System for Power Plants. Energy Conversion and Management. 40(18), 1899-1917.

129


Drbal, L.F.; Boston, P.G.; Westra, K.L. and Erickson, R.B. (1996). Power Plant Engineering: l g Edition, Black & Veatch, Springer, New York.

Energy Information Administration (ETA). (2005). International Energy Outlook 2005.

Fisher, K.S.; Beitler, C.; Rueter, C.; Searcy, K.; Rochelle, G. and Jassim, M. (2005). Integrating MEA Regeneration with CO2 Compression and Peaking to Reduce CO2 Capture Costs. U.S. Department of Energy, Washington, DC.

Geers, J.M. and O'Brien, C.M. (2002). Basis and Rationale for Potential Subcategorization of Coal-Fired Electric Utility Steam Generating Units. U.S. Environmental Protection Agency, Washington, DC.

Griffiths, M. and Marr-Laing, T. (2002). Thermal Power Generation Emissions National Guidelines for New Stationary Sources and Discussion Document — December 2001. Pembina Institute, Alberta, Canada.

Gwosdz, A.; Leisse, A. and Quenders, H.J. (2005). Pulverised Coal Firing System for the Operation of Steam Generators with Low Excessive Air. VGB Powertech. 85(11), 67-73.

Hendriks, C. (1994). Carbon Dioxide Removal from Coal-Fired Power Plants : 1stEdition, Kluwer Academic Publishers, Dordrecht/Boston/London.

Hobbs, J.C. and Heller, L.W. (1923). Pulverized Fuel for Large Boilers. Proceeding of Engineers ' Society of Western Pennsyvania, 39, 217-266.

International Energy Agency (IEA). (2006a). Key World Energy Statistics 2006, Paris, France.

International Energy Agency (IEA). (2006b). Focus on Clean Coal, Paris, France.

Kakaras, E.; Ahladas, P. and Syrmopoulos, S. (2002). Computer Simulation Studies for the Integration of an External Dryer into a Greek Lignite-Fired Power Plant. Fuel. 81(5), 583-593.

Kiga, T.; Yoshikawa, K.; Sakai, M. and Mochida, S. (2000). Characteristics of Pulverized Coal Combustion in High-Temperature Preheated Air. Journal of Propulsion and Power. 16(4), 601-605.

Kitto, J.B. (1996). Developments in Pulverized Coal-Fired Boiler Technology, Babcock & Wilcox.

Kjaer, S. (2002). The Advanced Supercritical 700°C Pulverized Coal-Fired Power Plant. VGB Power Tech. 7, 47-49.

130


Drbal, L.F.; Boston, P.G.; Westra, K.L. and Erickson, R.B. (1996). Power Plant Engineering: 1st Edition, Black & Veatch, Springer, New York.

Energy Information Administration (EIA). (2005). International Energy Outlook 2005.

Fisher, K.S.; Beitler, C.; Rueter, C.; Searcy, K.; Rochelle, G. and Jassim, M. (2005). Integrating MEA Regeneration with CO2 Compression and Peaking to Reduce CO2

Capture Costs. U.S. Department o f Energy, Washington, DC.

Geers, J.M. and O'Brien, C.M. (2002). Basis and Rationale fo r Potential Subcategorization o f Coal-Fired Electric Utility Steam Generating Units. U.S. Environmental Protection Agency, Washington, DC.

Griffiths, M. and Marr-Laing, T. (2002). Thermal Power Generation Emissions National Guidelines fo r New Stationary Sources and Discussion Document - December 2001. Pembina Institute, Alberta, Canada.

Gwosdz, A.; Leisse, A. and Quenders, H.J. (2005). Pulverised Coal Firing System for the Operation of Steam Generators with Low Excessive Air. VGB Powertech. 85(11), 67-73.

Hendriks, C. (1994). Carbon Dioxide Removal from Coal-Fired Power Plants : 1st Edition, Kluwer Academic Publishers, Dordrecht/Boston/London.

Hobbs, J.C. and Heller, L.W. (1923). Pulverized Fuel for Large Boilers. Proceeding o f Engineers ’ Society o f Western Pennsyvania, 39, 217-266.

International Energy Agency (IEA). (2006a). Key World Energy Statistics 2006, Paris, France.

International Energy Agency (IEA). (2006b). Focus on Clean Coal, Paris, France.

Kakaras, E.; Ahladas, P. and Syrmopoulos, S. (2002). Computer Simulation Studies for the Integration o f an External Dryer into a Greek Lignite-Fired Power Plant. Fuel. 81(5), 583-593.

Kiga, T.; Yoshikawa, K.; Sakai, M. and Mochida, S. (2000). Characteristics o f Pulverized Coal Combustion in High-Temperature Preheated Air. Journal o f Propulsion and Power. 16(4), 601-605.

Kitto, J.B. (1996). Developments in Pulverized Coal-Fired Boiler Technology, Babcock & Wilcox.

Kjaer, S. (2002). The Advanced Supercritical 700°C Pulverized Coal-Fired Power Plant. VGB Power Tech. 7, 47-49.

130


Kohl, A.L. and Nielsen, R.B. (1997). Gas Purification : 5th Edition, Gulf Publishing Company, Houston, Texas.

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Marion, J.L.; Liljedahl, G.N. and Black, S. (2004). A Review of the State-of-the-Art and a View of the Future for Combustion-Based Coal Power Generation. The 29thInternational Technical Conference on Coal Utilization & Fuel Science, April 18-22, Clearwater, Florida.

Martin, W.A. (1971). Sorting. Computing Surveys. 3(4), 147-174.

Metz, B.; Davidson, 0.; de Coninck, H.; Loos, M. and Meyer, L. (2005). IPCC Special Report on Carbon Dioxide Capture and Storage, Intergovernmental Panel on Climate Change, Cambridge University Press.

Miliaras, E.S. and Broer, W.T.F. (1991). Direct Coal-Fired Steam Electricity Plants with High Efficiency and Reduced CO2 Emissions. Proceedings of the American Power Conference. 53(1), 359-364.

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Niessen, W.R. (1977). Combustion and Incineration Processes: Applications in Environmental Engineering, Marcel Dekker, Inc., New York.

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131


Kohl, A.L. and Nielsen, R.B. (1997). Gas Purification : 5th Edition, Gulf Publishing Company, Houston, Texas.

Kraemer, T.G.; Nelson, G., Card, R.; Draper, E.L. and Mudd, M.J. (2004). Opportunities to Expedite the Construction o f New Coal-Based Power Plant, National Coal Council (NCC).

Lako P. (2004). Coal-Fired Power Technologies: Coal-Fired Power Options on the Brink o f Climate Policies (ECN-C-04-076), ECN Policy Studies, Netherlands.

Leung, P. and Moore, E.R. (1966). Analysis o f Cycle with First-Stage High Pressure Extraction Steam for Auxiliary Turbine Drives. Bechtel Corporation. Combustion. 38(6), 18-26.

Marion, J.L.; Liljedahl, G.N. and Black, S. (2004). A Review o f the State-of-the-Art and a View o f the Future fo r Combustion-Based Coal Power Generation. The 29th International Technical Conference on Coal Utilization & Fuel Science, April 18-22, Clearwater, Florida.

Martin, W.A. (1971). Sorting. Computing Surveys. 3(4), 147-174.

Metz, B.; Davidson, O.; de Coninck, H.; Loos, M. and Meyer, L. (2005/ IPCC Special Report on Carbon Dioxide Capture and Storage, Intergovernmental Panel on Climate Change, Cambridge University Press.

Miliaras, E.S. and Broer, W.T.F. (1991). Direct Coal-Fired Steam Electricity Plants with High Efficiency and Reduced CO2 Emissions. Proceedings o f the American Power Conference. 53(1), 359-364.

Neitzert, F.; Olsen, K.; Collas, P. (1999). Canada’s Greenhouse Gas Inventory: 1997 Emissions and Removals with Trends. Environment Canada.

New Energy and Industrial Technology Development Organization (NEDO) and Center for Coal Utilization Japan (CCUJ). (2004). Clean Coal Technology in Japan.

Niessen, W.R. (1977). Combustion and Incineration Processes: Applications in Environmental Engineering, Marcel Dekker, Inc., New York.

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Rao, A.B. and Rubin, E.S. (2002). A Technical, Economic, and Environmental Assessment o f Amine-Based CO2 Capture Technology for Power Plant Greenhouse Gas Control. Environmental Science & Technology. 36(20), 4467-4475.

Regan, J.W.; Borio, R.W.; Palkes, M.; Davidson, M.J.; Wesnor, J.D. and Bender, D.J. (1996). Major Improvements in Pulverized Coal Plant Design. Proceedings o f the 21th International Technical Conference on Coal Utilization & Fuel Systems. 21, 389-399.

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Sanders, W.P. (2004). Turbine Steam Path Vol. 3a-Mechanical Design and Manufacture, PennWell, Tulsa, Oklahoma.

Schilling, H.D. (1993). Prospects for Power Plant Technology. VGB Kraftwerkstechnik. 73(8), 564-576.

Singer, J.G. (1991). Combustion Fossil Power: a Reference Book on Fuel Burning and Steam Generation : 4th Edition, Combustion Engineering Power Systems Group, Windsor, Connecticut.

Smith, I. and Rousaki, K. (2002). Prospects fo r Co-Utilisation o f Coal with Other Fuels - GHG Emissions Reduction, IEA Coal Research, London, United Kingdom.

Smith, J.M., Van Ness, H.C. and Abbott, M.M. (1996). Introduction to Chemical Engineering Thermodynamics : 5th Edition, McGraw-Hill, New York.

Termuehlen, H. and Emsperger, W. (2003). Clean and Efficient Coal-Fired Power Plants: Development toward Advanced Technologies, ASME Press, New York.

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133


Appendix

Appendix A

Yes

START

Initial values [Tii] = [O]nrai

'Diane =1500°C

Tflame

ph ,C p jdT 25. c

Yes

Tome = max[Tii]

Graphical plots

END

Guess initial boundary condition for [Ti,j]

(except [Ti,j] at preheated air temperature nodes)

PDE for Laplace equation

Transform to algebraic difference approximation

Gauss-Seidel Method

Figure A.1 Algorithm to compute the temperature profile in furnace/boiler.

134


Appendix

Appendix A

Initial values

[Tij] = [0]imn

Tflame = 1500°C

N oy 1, t ~ Qfurmce

I Yes

N oYes

YesN o

END

START

Report outputs [Tij]

G auss-Seidel M ethod

Transform to algebraic difference approximation

Graphical p lots

PDE for Laplace equationi= l

G uess initial boundary condition for [Tij]

( e x c e p t [T ij] a t p r e h e a te d a i r te m p e r a tu r e n o d e s )

Figure A.1 Algorithm to compute the temperature profile in furnace/boiler.

134


START initial values

= 0.001, co = 1.001

{xi = 0

Initial boundary condition [A]ovo= [aid, (B)oid=

0

adaz2

[C] =

au 1.1

0

a im /a1,1

a23/a32 a1,„,/a1,2

a..1/ax.m a„.,/a,„,„ 0

b,/a,.,

b2/a22

{d} =•

b„/a„.,,

Yes

(x)ow = (x)

i=0

i = i +1

"0= d(i) - [Ci, I to ml X x

0

x(i) - x0,,,(0 x(i)

x100 —

END

Figure A.2 Algorithm for Gauss-Seidel method.

135


initial values a = 0.001, a »1.001{Xijnxl ~ 0

START

Initial boundary condition [A]nxm= [aij], {B}nxl={bij}

{d} =

b./a

b,/a

b./a,

[C] =

No

Yes

i = 0

Yes

No

i = i + l

x(i) = d(i) - [Ci, l to

x 100

END

Figure A.2 Algorithm for Gauss-Seidel method.

135


I 1 2 2

NO(mol NO

) NO(kg NO . kg coal

) mol NO

maw( hr N0( kg NO

) kg coal

M.Wh PW(MW)

Note: Equilibrium constant (Kp) can be found in Niessen, 1977.

Figure A.3 Algorithm for NO calculation.

(Original in color)

136


DetermineTflame f ro m fTj.jl

■1/2 ' l

P n o NO

mol NO kg coalkg NONO( )' NO(

kg coal mol NO

Note: Equilibrium constant (Kp) can be found in Niessen, 1977.

Figure A.3 Algorithm for NO calculation.

(Original in color)

136


R2 = 0.99

P4

6000

0

0 2000 4000 6000

Enthalpy (kJ/kg) — Actual Steam Properties

Figure A.4 Parity plot of enthalpy between actual data and empirical correlation.

137


R2 = 0.996000

g

I? 1 4000 ^ &■<e &>> un, —■3 g 5 'Sa '& 2000w a

u

0 2000 4000 6000

Enthalpy (kJ/kg) - Actual Steam Properties

Figure A.4 Parity plot o f enthalpy between actual data and empirical correlation.

137


Table A.1 Emission factors for bituminous and subbituminous coal combustion without

control equipment.

Furnace type

Emission factor, lb/ton of coal burned

All particles a Prvaiti- io a

PC, wall-fired, dry bottom 10A 2.3A

PC, wall-fired, wet bottom 7A 2.6A

PC, tangential fired, dry bottom 10A 2.3A

Cyclone 2A 0.26A

Spread stoker 66 13.2

Hand-fired 15 6.2

a Capital letter A on all particulate and P1\410 values represents the percentage by weight of ash in the coal should be multiplied by the factor given.

(Source: de Nevers, 2000)

138


Table A.1 Emission factors for bituminous and subbituminous coal combustion without

control equipment.

Furnace type

Emission factor, lb/ton of coal burned

All particles a PM10a

PC, wall-fired, dry bottom 10A 2.3A

PC, wall-fired, wet bottom 7A 2.6 A

PC, tangential fired, dry bottom 10A 2.3A

Cyclone 2A 0.26A

Spread stoker 66 13.2

Hand-fired 15 6.2

a Capital letter A on all particulate and PMio values represents the percentage by weight o f ash in the coal should be multiplied by the factor given.

(Source: de Nevers, 2000)

138


Reproduced w

ith permission o


Furth


ithout perm

ission.

Table A.2 List of enthalpy and entropy correlations of streams.

Point Enthalpy Entropy

For subcritical PC shown in Figure 3.5

k = 0.80886p3-600.24144 p 4+1497 .74518 • p 3-1404.4 5177 .7),2 +752.02583 • P,

+ 163.25297 -log P, + 514.44909

112 = h,+v, , • (p-P1)

3 123=0.0000/ • T33-0.00303 -T32 +4.52429•T3-11.99660

4 114=0.0000/ • T43-0.00303 • 7:4 2 +4 .52429 -T4-11.99660

5 h5=0.00001 • T53-0.00303 - T52 +4 .52429 • T5-11.99660

6 126=0.00001- T63-0.00303. T62+4.52429 -T6-11.99660

7 h7=h6

8 128=1.12026- T83-13.88425 - T82+99.26822 - T8+271.21790 • log 7, + 676.05097

9 119- 118+V8(P9 138

10 1210 119

11 h„=0.00001•TH 3-0.00303- T1, 2 +4.52429 - T -11.99660

12 12.12=0.00001-T123-0.00303 • T,22 +4.52429 • T,2-11.99660

13 h13=-3. 14478 - 13,32 +96.89882 - p 3-0.00338 - T32 + 6.76784 -7;3 + 11.47682 s ,3=-0.035230- P13+0.00396 .7;3 ± 4.80006

14 h14 = 66.67716 • Pi4 ± 59607233 • s - 1095.82677 S14=1714 S13

15 h„ = 1114

16 11,6=0.00001 • T163-0.00275 • T162+4.42947 T16-4.81626

17 hi, = 1116

18 11180.00001 • T,83-0.00275 -T182+4.42947 • 7,8-4.81626

19 hig-h18

Reproduced

with perm

ission of the

copyright ow

ner. Further


without

permission.

Table A.2 List o f enthalpy and entropy correlations o f streams.



1h, = 0.80886P/-600.24144P/+1497.74518 ■ P 3-1404.45177■ P,2 + 752.02583 ■ P,

+ 163.25297-log P, +514.44909

2 h2 =h,+v, -(Pr Pj)

3 h, =0.00001 ■ T3 3-0.00303 - T 2 +4.52429 -T ,-l1.99660

4 h4=0.00001 ■ T43 -0.00303 - Tt 2+4.52429 -T4-l 1.99660

5 h5=0.00001 ■ T 3-0.00303 ■ T 2+4.52429 ■ T,-11.99660

6 h6=0.00001-T63 -0.00303 ■ T 2+4.52429-T,-11.99660

7 h?=h6

8 hs=l.12026■ T 3-13.88425■ Ts2+99.26822 ■ Ts+271.21790 ■ log Ta + 676.05097

9 h9 =hs+vs(P,J-P s)

10 hio~h9

11 hn=0.00001■Tn3-0.00303-TI 2+4.52429-Tn-11.99660

12 h,2=0.00001■ Tl23-0.00303 ■ Tl22+4.52429 ■ Tn-11.99660

13 hu=-3.14478■ PI32+96.89882 ■ P, ,-0.00338- T, 2 + 6.76784 ■ TI3 + 11.47682 s ,,=-0.035230-PI}+0.00396■ T„ +4.80006

14 hl4 = 66.67716■ PI4 + 596.07233■ sI4 -1095.82677 SJ4 Oh ' sn

15 hIS=hI4

16 h,,=0.00001 ■ T j -0.00275 ■ T„2+4,42947 ■ 7],,-4.81626

17 h/7 = hl6

18 hIS=0.00001 ■ T j -000275 ■ T, ,+4.42947 -Tls-4.81626

19 hi9~hIS

Reproduced w

ith permission o



ithout permission.

Table A.2 List of enthalpy and entropy correlations of streams. (continued)



20 h2 =-117.12271. P202+870.84593 • P20-0.00085 • T202+3.21142 .720 + 482.57351 520-1.18335 • log P20+3.42339- log T20- 1.42544

21 h21=-31.90952 • P2,2+279.46951- P21+113.42764 • 52,2-920.46874- s21 + 3620.89619 521=1121 S20

22 h22=-161.65890 • 1222+64103202 • P22+118.41893. s222-1078.84349 s22 + 4244.44719 S 22 17 22 5 20

23 h23=-166.98757• P232 +641.74374• P23+113.37429.5232-1041.85363- s23 +4254.70448 s 23= 17 23 • S20

24 h24=h23

25 h15=-1439.95286 • P2, 2+1853.85191- P25+37.37623- 52, 2+32.02752- x25 + 189.25439 325 1725 520

26 h26=397.07724 • P26 2+160138985- P26+11.04908 • s26 2+246.39584 • s26 + 73.70142 S 26= 7 7 26 520

27 h22=6813.82750 • P27+372.21059- s22-519.84303 S27=7727 's20

28 h„ =hi + x•hig

29 h790.0000/ • T293 - 0.00275 • T292+4.42947 • T29-4.81626

30 h30=h29

31 h310.00001.73,3 - 0.00275 -T3,2+4.42947 -T3,-4.81626

32 h32 = h3,

33 h33=0.00001 • T333 - 0.00275 -T332+4.42947 -T33-4.81626

34 h34 = h33

35 h350.00001 753 - 0.00275 -T352+4.42947 .T35-4.81626

36 h36

37 h37 = h9

Reproduced

with perm

ission of the

copyright ow

ner. Further


without

permission.

Table A.2 List o f enthalpy and entropy correlations o f streams, (continued)

Point E nthalpy E ntropy


20 h20=-l 17.12271 ■ P2O2+870.84593 ■ P2o-0.00085 ■ T j +3.21142 ■ T10 + 482.57351 s20=-l .18335 ■ logP20+3.42339 - log T20-l.42544

21 h2,=-31.90952-P2l2+279.46951-P2I+113.42764-s2,2-920.46874-s2I +3620.89619 S2 ~ rl2l 'S20

22 h22= -l61.65890-P222+641.03202-P22+ l18.41893-s222-1078.84349-s22 +4244.44719 S22~V22 ’S20

23 h23= -l66.98757-P232+641.74374-P23+ l13.37429-s232-1041.85363-s23 + 4254.70448 2̂3 23 'S20

24 h24=h23

25 h2 =-1439.95286 ■ P25 2+1853.85191 ■ P25+3 7.3 7623 ■ s 25 2+32.02752 -s25 + 189.25439 S25~V25 'S20

26 h2 =397.07724 ■ P26 2+ l601.38985-P26+ l 1.04908 ■ s26 2+246.39584-s26 + 73.70142 S26~V26 'S20

27 h27=6813.82750 ■ P27+372.21059 ■ s2J-519.84303 2̂7 27 ‘ S20

28 h2S=hf +x-hfg

29 h29=0.00001- T j - 0.00275■ T j +4.42947-T29-4.81626

30 3̂0~̂ 2<>

31 h3f=0.00001 -7 2 - 0.00275-T3I2+4.42947-T3,-4.81626

32 h32 = h31

33 h33=0.00001 -TI3 - 0.00275■ T3/+4.42947-T3S-4.81626

34 •Vi1! ;

Ol I

35 h3S=0.00001 ■ T j - 0.00275-Ts 2+4.42947-Tls-4.81626

36 f̂i ll s* b;

37 K = K

Reproduced w

ith permission o



ithout permission.



For supercritical PC shown in Figure 3.6

h, = 0.80886P15-600.24144P14+1497.74518 • P 13 -1 404.45 177 • P 12 ÷

+ 163.25297 log P, + 514.44909

752.02583 P,

2 h2 = h1-Fv2 • (P2-P1)

3 113=0.00001- T33 -0.00303. T32+4.52429 -T3-11.99660

4 h4=0.00001•T43 -0.00303 • T 42 +4.52429 -T4-11.99660

5 45=0.00001 •T83-0.00303 - T 52 +4.52429 -T5-11.99660

6 h6=0.00001 •T63 -0.00303 .T62+4.52429. T6-11.99660

h,=h6

8 h8=1.12026 -T83-13.88425 • T82+99.26822 -T8+271.21790. log 7'8 + 676.05097

9 h9-h8+v8(P9 P8)

10 h,o=h9

11 h,1=0.00001 .T13-0.00303 • T,2 +4.52429 T1-11.99660

12 k2=0.00001 • T123-0.00303. T1, 2+4 .52429 -T„-11.99660

13 h„=-576.43919 • log P,3+4238.42638 • log7;3-7480.10078 s„=-1.60628 • log P,3+5.00953 • log T13-5 32560

14 h14 = 66.67716. P,4 + 596.07233 • s14 - 1095.82677 S 14 = 1714 -S13

15 his = 66.67716 • 115 + 596.07233. s15 - 1095.82677 s 15=7 7 15 S 13

16 h,6=0.00001 -T,63-000275 • T162+4.42947- 1'i6-4.81626

17 h„ = h16

18 h„=0.00001 •T,83-0.00275 -T182+4.42947 • T8-4.81626

19 h„= h„

Reproduced

with perm

ission of the

copyright ow

ner. Further


without

permission.



For supercritical PC shown in F igure 3 .6

1h, = 0.80886P*-600.24144P*+1497.74518-P*-1404.45177 • P 2 + 752.02583 - P,

+ 163.25297 logP, +514.44909

2 h2 = h,+v,-(P2-PI)

3 h3=0.00001-T2 -0.00303-T2 +4.52429 Tr l 1.99660

4 ht =0.00001 ■ Tf -000303 ■ T42+4.52429 ■ T4-11.99660

5 h,=0.00001 • r / -0.00303 - T 2+4.52429 ■ Ts-11.99660

6 h6=0.00001 ■ T / -0.00303- T / +4.52429 ■ T6- l 1.99660

7 h,=h6

8 h =1.12026 - T /-13.88425-T 2+99.26822 ■ Ts+271.21790 ■ log Ts + 676.05097

9 h,=hs+vs(P9-P s)

10 1̂0~̂ 9

11 h U=0.00001 Tn3-0.00303 -Tu2+4.52429 -Tn- l 1.99660

12 hu=0.00001 TJ-0.00303 Tn2+4.52429-TU-11.99660

13 hl3=-576,43919 ■ logPI3+4238.42638 ■ logTn-7480.10078 sI3=-l.60628 ■ log PI3+5.00953 ■ log TI3-5.32560

14 hI4 = 66.67716■ PI4 + 596.07233■ s,4 - 1095.82677 S14=Tll4 ' SB

15 h,s = 66.67716 Pl5+ 596.07233 su -1095.82677 SlS=TllS ' S!3

16 hl6=0.00001 -T j -0.00275 ■ T j +4.42947-T16-4.81626

17 h/7 = his

18 hl8=0.00001 ■ T,2-0.00275 ■ T„2+4.42947 ■ TIS-4.81626

19 hi9~hi8

Reproduced w

ith permission o



ithout permission.




20 h„=-117.12271 • P202+870.84593 • P20-0.00085 • 72, 2+3.21142 • T20 +482.57351 s„=-1.18335 -log P„+3.42339 • logT20-1.42544

21 h„=-31.90952 • P212 +279.4695 1 • P21+113.42764 • s 232-920.46874 • s2, + 3620.89619 S21-7721 S20

22 h22=-161.65890 • P22 2 +64 1.03202 P22+1 18.4 1893 • s12 2-1078.84349 • s22 + 4244.44719 s 22= 7722' 520

23 h23=-166.98757 • P„ 2+64174374 • P23+11337429 • s „ 2 -1041.85363 • s23 + 4254.70448 s 23=1123' S20

24 h 14 = 4 23

25 h25=-1439.95286 • P252 +1853.85 191 • P„+37 3 7623 • 52, 2+32.02752 • s „ + 189.25439 S25= 7725 S20

26 h26-397.07724 • P262+160138985. P16+11.04908- s262+246.39584. s26 + 73.70142 S26= 7726 "S20

27 h27=6813.82750 • P27+372.21059.527-519.84303 527= 7127 ' S20

28 h,=hf +x•h f g

29 h29=0.00001 • 7;93 - 0.00275 • T292+4.42947 -T29-4.81626

30 11304123

31 h„=0.00001.7 - 0.00275 - T3,2+4.42947 • T31-4.81626

32 h32 h 31

33 1/330.00001- 7333 - 0.00275 - T332+4.42947 • T33-4.81626

34 h34 h 33

35 h3 =0.00001•13, 3 - 0.00275 • T3, 2+4.42947 • T„-4.81626

36 h36 - h 35

37 h„ = h,

38 h38=0.0000255 •T 383 -0.01373-T382 +6.94766-T382 -191.14775

39 1139-0.00001.7393 - 0.00275-T392+4.42947-T394.81626

Reproduced

with perm

ission of the

copyright ow

ner. Further


without

permission.


Point E nthalpy E ntropy


20 h20=-IJ 7.12271 ■ P j +870.84593 ■ P2O-0.00085 ■ T j +3.21142 ■ T20 + 482.57351 s20=-l.18335 ■ logP20+3.42339 ■ logT20-l.42544

21 h2I=-31.90952-P2 2+279.46951 ■ P2l+ l l3.42764■ s 2,2-920.46874-s2, + 3620.89619 S21~Tl2I ' S20

22 h22=-161.65890-P222+641.03202-P22+ l18.41893-s22 -1078.84349-s22 +4244.44719 S22~ 022 ' S20

23 h2 =-166.98157- P23 2+641.74374 ■ P2J +113.37429 ■ s232-1041.85363 ■ s23 + 4254.70448 S23~ 023 ' S20

24 h - h ,t

25 h2S=-1439.95286-P252+1853.85191 ■ P2S+37.37623-s2S2+32.02752 ■ s 2S +189.25439 S25=Tl25 ' S20

26 h2 =397.07724-P2f2+1601.38985-P26+ l1.04908-s262+246.39584-s26 + 73.70142 2̂6 9 26 ' S 20

27 h27=6813.82750-P27+372.21059-s27-519.84303 S27~ 027 ' S20

28 h2S =hf +x - hfg

29 h29=0.00001 - T j - 0.00275■ T29+4.42947-T29-4.81626

30 h3a-h 29

31 h3 =0.00001-Tj,3 - 0.00275-T3I2+4.42947-TSI-4.81626

32 h32 = h3i

33 h33=0.00001- T13 - 0.002 75-T33 +4.42947 ■ Tss-4.81626

34 h3t = 3̂3

35 h3 = 0 . 0 0 0 0 1 - - 0.00275-Tj+4.42947-T35-4.81626

36 h36 =h3S

37 h37 = h9

38 h3S=0.0000255 -T 3«3 -0.013 73 -T 3s2 +6.94766-T 332 -191.14775

39 h39=0.00001-T19 - 0.002 75 ■ T39+4.42947 ■ T39-4.81626

monte carlo simulation of pulverized coal-fired power plants ...

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