Practical Boiler Operation Engineering And Power Plant.pdf

Practical Boiler Operation Engineering and Power Plant Third Edition

Amiya Ranjan Mallick General Manager (Power Plant) B.K. Birla Group of Industries Maharashtra

Delhi-110092 2014

Practical Boiler Operation Engineering and Power Plant, Third Edition Amiya Ranjan Mallick © 2014 by PHI Learning Private Limited, Delhi. All rights reserved. No part of this book may be reproduced in any form, by mimeograph or any other means, without permission in writing from the publisher. ISBN-978-81-203-4855-4 The export rights of this book are vested solely with the publisher. Published by Asoke K. Ghosh, PHI Learning Private Limited, Rimjhim House, 111, Patparganj Industrial Estate, Delhi-110092 and Printed by Baba Barkha Nath Printers. Bahadurgarh, Haryana-124507.

I dedicate this book to

my Godlike uncle

Sri Raghunath Mallick who has brought me from darkness and illuminated my life.

Contents Preface   xix

1. Fundamentals

1–20



1.1 Introduction   1 1.2 Law of Conservation of Energy   1 1.3 Temperature   1



1.4 Pressure   3



1.5 Heat   4



1.6 1.7 1.8 1.9 1.10 1.11 1.12



1.13 Thermodynamic Cycle   12



Exercises   20







1.3.1 Absolute Temperature   3

1.4.1 Gauge Pressure and Absolute Pressure   3 1.5.1 Specific Heat   5

1.12.1 1.12.2 1.12.3 1.12.4 1.12.5 1.12.6

Constant Volume or Isochoric Process   9 Constant Pressure or Isobaric Process   9 Constant Temperature or Isothermal Process   10 Adiabatic Process or Isentropic Process   11 Free Expansion Process   11 Throttling Process   11

1.13.1 Carnot Cycle with Steam as Working Fluid   12 1.13.2 Rankine Cycle   13 1.13.3 Brayton Cycle   18

2. Heat Transfer Methods





Work   5 Power   5 Energy   6 Enthalpy   6 Laws of Thermodynamics   6 Specific Heat of Gas   8 Thermodynamic Process of Perfect Gas   8

21–28

2.1 Introduction   21 2.2 Heat Transfer by Conduction   21 2.2.1 Fourier’s Law   22 2.2.2 Thermal Conductivity   23

v

vi 

Contents



2.3 Heat Transfer by Convection   23



2.4 Heat Transfer by Radiation   24



2.5 Heat Transfer Methods in a Boiler   27 Exercises    28





2.3.1 Newton’s Law of Cooling   23 2.4.1 2.4.2 2.4.3 2.4.4

Absorption, Reflection and Transmission of Radiation   24 Emissivity   26 Stefan–Boltzmann Law   26 Geometrical Factor or Configuration Factor   27

3. Fuel and Combustion



3.1 Introduction   29 3.2 Solid Fuel   30 3.2.1 3.2.2 3.2.3 3.2.4

Wood   30 Coal   31 Coke   33 Biomass Fuel   33



3.3 Liquid Fuel   34 3.4 Gaseous Fuel   35



3.5 Proximate Analysis and Ultimate Analysis of Fuel   36



3.6 Calorific value of Fuel   37



3.7 Combustion   38



3.8 Some Important Properties of Coal   41 3.9 Gradation of Coal   42 3.10 Combustion of Coal   43



3.11 Combustion of Liquid Fuel   43 3.12 Excess Air   44 Exercises    45







3.4.1 Blast Furnace Gas   35 3.4.2 Coke Oven Gas   35

3.5.1 Proximate Analysis   36 3.5.2 Ultimate Analysis   37

3.6.1 Gross Calorific Value (GCV) or Higher Calorific Value (HCV)   37 3.6.2 Net Calorific Value (NCV) or Lower Calorific Value (LCV)   38 3.6.3 Empirical Relationship of GCV, UHV and NCV   38 3.7.1 Chemistry of Combustion   39

3.10.1 Combustion of Pulverised Coal   43

4. Properties of Steam



29–45

4.1 Introduction   46 4.2 Formation of Steam   46 4.3 Terms Associated with Steam   48 4.4 Steam Table   50 4.5 Mollier Diagram   52 Exercises    52

46–52

Contents 



5. Boiler Feedwater Chemistry



5.2.1 Sedimentation   54 5.2.2 Filtration   54 5.2.3 Coagulation   55

5.3 Dissolved Salts and Minerals   55 5.4 Internal Boiler Water Treatment   56



5.5 External Treatment of Feedwater   58



5.6 Removal of Dissolved Gases from Water   67



5.7 Some Parameters of Boiler Feedwater   68 Exercises    71



5.4.1 Soda Ash (Sodium Carbonate or Na2CO3) Treatment   56 5.4.2 Phosphate Treatment or High Pressure (HP) Dosing   56 5.4.3 Colloidal Treatment   58 5.5.1 Demineralising (DM) Water Plant   58 5.5.2 Reverse Osmosis Plant   63 5.6.1 Low Pressure (LP) Dosing   67

6. Introduction to Boiler



6.1 Introduction   73 6.2 Steam Generation in a Boiler   74 6.3 Different types of Boiler   76



6.4 Travelling Grate-fired Boiler   80 6.5 Spreader Stoker-fired Boiler   80 6.6 Pulverised Coal (PC)–fired Boiler   81



6.7 Fluidised Bed Combustion (FBC) Boiler   89



6.8 Supercritical Boiler   100



6.9 Biomass-fired Boiler   109 Exercises    109









53–72

5.1 Introduction   53 5.2 Removal of Undissolved Suspended Solid Materials from Water   53



vii

6.3.1 6.3.2 6.3.3 6.3.4 6.3.5 6.3.6

Fire Tube and Water Tube Boiler   77 Straight Tube, Bent Tube, Horizontal, Vertical and Inclined Boiler   77 Waste Heat Recovery Boiler (WHRB)   77 Package Boiler   78 Subcritical and Supercritical Boiler   78 Fuel-fired Boiler   78

6.6.1 6.6.2 6.6.3 6.6.4

Air System   81 Pressure Parts (Heat Transfer Surfaces)   82 Coal Feeding System   83 Ash Handling System   89

6.7.1 Atmospheric Fluidised Bed Combustion (AFBC) Boiler   90 6.7.2 Circulating Fluidised Bed (CFBC) Boiler   97

6.8.1 6.8.2 6.8.3 6.8.4 6.8.5

Furnace Design   103 Water and Steam Circuit   105 Heat Recovery Area (HRA)   107 Start-up System   107 Materials used in Supercritical Boiler   108

73–111

viii 

Contents

7. Fuel Handling System

7.1 Introduction   112 7.2 Handling of Liquid Fuels   112

7.2.1 Handling of LDO and HSD   112 7.2.2 Handling of HFO, FO and LSHS   113



7.3 Handling of Gaseous Fuel   114 7.4 Handling of Solid Fuel: Coal Handling Plant   115



7.5 Handling of other Solid Fuels   127 Exercises   128



7.4.1 Coal Transportation and Storage   115 7.4.2 Coal Preparation   116 7.4.3 Coal Pulverisation   125

8. Air Path



8.2.1 Affinity Laws   130 8.2.2 Fan Curve   131 8.2.3 System Resistance Curves   131

8.3 FD Fan   133



8.4 Air Heater (or Air Preheater)   134



8.5 Primary Air and Secondary Air   138 8.6 Excess Air   138 Exercises    139



8.3.1 FD Fan Air Flow Control   134 8.4.1 Steam Air Heater   137

9. Feedwater Path

9.1 Introduction   141 9.2 Deaerator   141



9.3 Basics of Pump   143



9.4 Boiler Feed Pump   150 9.5 Boiler Drum Level Control   151



9.6 Feed Control Station   155 9.7 Economiser   156 9.8 Evaporator   157



9.9 Blowdown   161 9.10 Gauge Glass   162 9.11 Hydrastep   165









129–140

8.1 Introduction   129 8.2 Basics of Fan   129



112–128

9.2.1 Tray Type, Direct Contact Deaerator   142 9.3.1 Centrifugal Pump   143 9.3.2 Positive Displacement Pump   149

9.5.1 Drum Level Control in Larger Capacity Boiler   154

9.8.1 Water Wall   158 9.8.2 Boiling Principle   159

141–172

Contents 





9.12 Waterside Scaling and Corrosion   165



9.13 Priming, Foaming and Carryover   170 Exercises   171



9.12.1 Scaling   166 9.12.2 Corrosion   169

10. Steam Path 10.1 Introduction   173 10.2 Steam Drum   173

10.3 Superheater   176



10.4 Methods of Superheater Temperature Control   178



10.5 Start-up Vent   184 10.6 Safety Valve   184



10.7 Steam Vent Silencer   187 Exercises    188





10.3.1 Outlet Temperature at Various Loads for Different Types of Superheaters   178 10.4.1 10.4.2 10.4.3 10.4.4 10.4.5 10.4.6 10.4.7

Gas Bypass Method   179 Excess Air Control Method   179 Tilting/Adjustable Burner Control Method   179 Separately-fired Superheater Method   180 Flue Gas Recirculation Method   181 Coil Immersion in Boiler Drum   181 Desuperheating or Attemperation Method   182

10.6.1 Basic Operation of Safety Valve   186

11. Flue Gas Path 11.1 Introduction   189 11.2 Furnace   190

11.2.1 Furnace Dimension   192



11.3 Different Zones of Flue Gas Path   194 11.4 Refractory and Insulation   195



11.5 ID Fan   199 11.6 Draft   200



11.7 Flue Gas Constituents   203







173–188

10.2.1 Drum Internals   175



ix

11.4.1 Refractory   195 11.4.2 Insulating Material   198

11.6.1 Natural Draft   201 11.6.2 Artificial Draft (Mechanical Draft)   201

11.7.1 11.7.2 11.7.3 11.7.4 11.7.5 11.7.6 11.7.7 11.7.8 11.7.9

Carbon Dioxide (CO2)   204 Carbon Monoxide (CO)   204 Oxygen (O2)   204 Nitrogen Oxide (NOx)   205 Sulphur Oxide (SOx)   207 Water Vapours   207 Volatile Organic Compounds (VOC)   207 Particulates   208 Heavy Metal Toxics   208

189–211

x 

Contents

11.8 Flue Gas Velocity   208 11.9 Chimney   209 Exercises    210

12. Ash Handling System



12.1 Introduction   212 12.2 Ash 212

12.2.1 Bottom Ash   213 12.2.2 Fly Ash   213



12.3 Bottom Ash Removal System   213



12.4 Different Ash Handling System   215



12.5 Selection of Suitable Ash Handling System   219 12.6 Fly Ash Separation System   220



12.7 Utilisation of Ash   233



Exercises    235





12.3.1 Dry Bottom Furnace Ash Removal   214 12.3.2 Wet Bottom Furnace Ash Removal   214 12.4.1 Hydraulic Ash Handling System   215 12.4.2 Mechanical Ash Handling System   217 12.4.3 Pneumatic Ash Handling System   217

12.6.1 12.6.2 12.6.3 12.6.4 12.6.5

Inertial Separators   221 Wet Scrubber   223 Fabric Separator (Bag Filter)   224 Electrostatic Precipitator (ESP)   227 ESP/Fabric Hybrid Filter   233

12.7.1 12.7.2 12.7.3 12.7.4 12.7.5 12.7.6 12.7.7

Construction of Embankments and Fills   234 Road Construction   234 Pozzolana Cement Manufacturing   234 Cement Concrete and Mortar   235 Brick Manufacturing   235 Manufacturing Building Components   235 Backfilling of Mines   235

13. Operation of Boiler

13.1 Introduction   237 13.2 Feedwater Fill-up in Boiler   237 13.3 Boiler Start-up   239



13.4 Boiler Load Increasing/Decreasing   243 13.5 Shutdown of Boiler   244



13.6 Normal Operation of Boiler   246 13.7 Abnormal Operating Conditions and Emergency Situations   247







212–236

13.3.1 Cold Start-up   239 13.3.2 Hot Start-up   242

13.5.1 Shutdown to Cold   245 13.5.2 Shutdown to Hot   245

13.7.1 Low Water Level   248

237–261

Contents 

High Water Level   249 Master Fuel Trip   249 High Steam Temperature   249 Furnace Explosion   250 Boiler Tube Failure   251



13.7.2 13.7.3 13.7.4 13.7.5 13.7.6



13.12.1 Input-output Method or Direct Method   256 13.12.2 Heat Loss Method or Indirect Method   257



13.8 Preservation of Boiler   252 13.9 Hydrostatic (Hydraulic) Test   252 13.10 Soot Blowing   254 13.11 Inspection of Boiler   255 13.12 Efficiency Calculation   255



Exercises   260

14. Pipes, Tubes and Fittings

14.1 Introduction   262 14.2 Tube and Pipe   262



14.3 14.4 14.5 14.6



14.7 Ferritic and Austenitic Steel   268 14.8 Chemical Composition and Mechanical Property of Different Standard Pipes and Tubes   268 14.9 Flow through a Pipe   269 14.10 Pressure Loss Due to Pipe Bends and Valves   272 14.11 Thermal Expansion of Pipe   273 14.12 Pipe Supports and Hangers   274 14.13 Insulation of Pipe   276 14.14 Steam Pipe Layout   277 14.15 Water Hammer   278 14.16 Pipe Fitting   278 Exercises    279







14.2.1 Difference between Tube and Pipe   263

14.6.1 Carbon Steel   266 14.6.2 Alloy Steel   267



15.1 Introduction   281 15.2 Flange   281



15.3 Trap   284



15.4 Valve   288



262–280

Pipe Schedule   263 Nominal Bore (NB) of Pipe   265 Different Standard Specifications for Tube and Pipe   265 Carbon Steel and Alloy Steel   266

15. Pipe Fittings and Ancillaries

xi

15.2.1 Gasket   284

15.3.1 Different Types of Traps   285 15.3.2 Problems, Losses and Testing of Traps   288

281–299

xii 

Contents



15.4.1 Different Types of Valves   289 15.4.2 Stem Sealing   292 15.4.3 Standard and Material Specification of Valve   294



15.6.1 Strainer Screens   299



15.5 Non-return Valve (NRV)   296 15.6 Strainer   298



Exercises   299

16. Steam Turbine

16.1 Introduction   300 16.2 Impulse and Reaction Turbine   301



16.2.1 Impulse Turbine   301 16.2.2 Reaction Turbine   304



16.4.1 Casing   309 16.4.2 Rotor   310 16.4.3 Moving Blade   310 16.4.4 Fixed Blades and Diaphragm   312 16.4.5 Steam Sealing System   313 16.4.6 Bearings   316 16.4.7 Gland   319 16.4.8 Exhaust Hood   320 16.4.9 Emergency Stop Valve (ESV)   320 16.4.10 Governing Valve and Control Valve   321



16.8.1 Mechanical Governor   327 16.8.2 Hydraulic Governor   328 16.8.3 Electrohydraulic Governor   328



16.15.1 Reheat Turbine   339 16.15.2 Multicasing Turbine   340 16.15.3 Multiflow Turbine   342 16.15.4 Feedwater Heating   343



16.3 Classification of Steam Turbine   306 16.4 Main Components of Steam Turbine   309



16.5 16.6 16.7 16.8



16.9 Control Oil System   331 16.10 Turbine Protection System   332 16.11 Turbovisory   333 16.12 Turbine Casing Drain System   336 16.13 Extraction System   336 16.14 Feedwater Heater   338 16.15 Large Capacity Steam Turbine   338



Exercises   344

Thermal Expansion of Turbine   322 Gland Sealing System   323 Barring Device   324 Governing System   325

300–346

Contents 



17. Auxiliary System of Steam Turbine



17.2.1 17.2.2 17.2.3 17.2.4 17.2.5 17.2.6 17.2.7

Oil Tank   348 Oil Pump   349 Oil Cooler   350 Oil Filter   350 Oil Centrifuge   350 Overhead Tank   352 Oil Accumulator   352

Condensate System   353 Gland Sealing System   354 Steam Ejector and Vacuum System   355 Condenser   357



17.3 17.4 17.5 17.6



17.7 Cooling Water System   361



Exercises   369



17.6.1 Dalton’s Law of Partial Pressure   360 17.6.2 Condenser Efficiency   361



17.7.1 Cooling Tower   362 17.7.2 Cooling Water Treatment   367

18. Operation of Steam Turbine



347–370

17.1 Introduction   347 17.2 Oil System   347





371–398

18.1 Introduction   371 18.2 Charging of Steam Pipeline or Heat Up   371 18.3 Operation of Cooling Water System   372 18.4 Operation of Lubrication Oil System   372 18.5 Barring Gear Operation   372 18.6 Condensate System Operation   373 18.7 Gland Steam Charging   373 18.8 Vacuum Build-up   374 18.9 Turbine Start-up   375 18.10 Turbine Shutdown   378 18.11 Emergency Situations in Turbine   378 18.12 Losses in Steam Turbine   381



18.12.1 External Losses   381 18.12.2 Internal Losses   382



18.14.1 Combined Cycle Technology   385 18.14.2 Supercritical (SC) and Ultra Supercritical (USC) Technologies   388



18.15.1 Advanced Ultra Supercritical (AUSC) Technology with Steam Temperature Greater than 700 °C   390 18.15.2 Integrated Gasification Combined Cycle (IGCC) Technology   391



xiii

18.13 Heat Rate   383 18.14 Best Available Technology for Efficient Power Generation using Fossil Fuel 385



18.15 Next Generation Efficient Technology for Thermal Power Generation   389







xiv 

Contents

18.16 Scenario of Power Generation Industry in India   395 18.17 Capacity Selection of Generating Sets   396 Exercises    397

19. Generator

399–418

19.1 Introduction   399 19.2 Important Parts of a Generator   400 Cylindrical Rotor   400 Stator   402 Bearings   403 Enclosure   403



19.2.1 19.2.2 19.2.3 19.2.4



19.3.1 Closed System Air Cooling   404 19.3.2 Closed System Hydrogen Cooling   404



19.4.1 Field Supply from Excitation Transformer or Static Excitation System   406 19.4.2 Excitation Through Exciter Generator or Brushless Excitation System   407



19.10.1 Parallel Mode of Operation   417 19.10.2 Isolated Mode of Operation   418



19.3 Cooling System of Generator   404



19.4 Excitation System   405



19.5 Automatic Voltage Regulator (AVR)   407 19.6 Voltage Build-up   410 19.7 Synchronisation   410 19.8 Desynchronisation or Islanding   412 19.9 Generator Protection   414 19.10 Different Operating Conditions of Generator   417



Exercises   418

20. Commissioning of Power Plant

20.1 Introduction   419 20.2 Commissioning of Boiler   419





20.2.1 Leakage Test of Pressure Parts and Flushing   420 20.2.2 Hydrostatic Pressure Test of Pressure Parts   420 20.2.3 Furnace Leakage Test   420 20.2.4 Chemical Cleaning of Pressure Parts   420 20.2.5 Alkali Boil-out   422 20.2.6 EDTA Cleaning   422 20.2.7 Safety Valve Setting   423 20.2.8 Commissioning of Boiler Feed Pump   423 20.2.9 Commissioning of Fans   423 20.2.10 Commissioning of Fuel Handling System   423



20.3.1 20.3.2 20.3.3 20.3.4 20.3.5 20.3.6



20.3 Commissioning of Turbine   424

Lube Oil Flushing   424 Steam Blowing   425 Turbine on Barring   427 Commissioning of Condensate System   427 Rolling of Turbine   428 Overspeed Test   428

419–438

Contents 





20.4 Commissioning of Cooling Water System   428



20.5 Commissioning of Electrical System   429



20.6 Performance Guarantee (PG) Test   435



Exercises    438



20.4.1 Commissioning of Cooling Tower   429 20.4.2 Flushing and Passivation   429



20.5.1 20.5.2 20.5.3 20.5.4 20.5.5



20.6.1 PG Test of Boiler   436 20.6.2 PG Test of Turbine   437 20.6.3 PG Test of Generator   437

Charging Switchgear Panels   430 Commissioning of Transformers   431 Commissioning of Motors   431 Commissioning of Generator Protection System   432 Commissioning of Generator   432

21. Maintenance of Power Plant

21.1 Introduction   439 21.2 Types of Maintenance Practices   440

Breakdown or Corrective or Reactive Maintenance   440 Preventive or Schedule Maintenance   441 Predictive Maintenance   442 Condition-based Maintenance (CBM)   443 Proactive Maintenance   443 Total Productive Maintenance (TPM)   444



21.2.1 21.2.2 21.2.3 21.2.4 21.2.5 21.2.6



21.3.1 Failure in Boiler   447 21.3.2 Failure in Turbine   450



21.4.1 21.4.2 21.4.3 21.4.4 21.4.5



21.6.1 Procedure for Annual Inspection of Boiler   459 21.6.2 Repairing Procedure of Boiler   461



21.8.1 Shield Metal Arc Welding (SMAW)   464 21.8.2 Gas Tungsten Arc Welding (GTAW) or Tungsten Inert Gas (TIG) Welding   466 21.8.3 Preheating   468 21.8.4 Post-weld Heat Treatment (PWHT)   468 21.8.5 Defects in Welding   469 21.8.6 Testing of Welding Joints   469



21.3 Failures in Power Plant   447



21.4 Non-destructive Test (NDT)   455



21.5 Different Types of Maintenance Programme of Turbine   457 21.6 Statutory Rules and Regulations Applicable to the Boiler   458



21.7 RLA Study   462 21.8 Welding   463







xv

Dye Penetration (DP) Test   455 Fluorescent Magnetic Test   456 Ultrasonic Test   456 Radiographic or X-ray Test   456 In-situ Metallography   457

21.9 Bearing   470

439–485

xvi 

Contents



21.10 Coupling   472 21.11 Shaft Alignment   475



21.12 Machine Vibration   482 Exercises   484



21.11.1 Straightedge and Filler Gauge Method   477 21.11.2 Dial Gauge Method   478

22. Control and Instrumentation

22.1 Introduction   486 22.2 Process Measurement   486



22.3 Measurement of Pressure   488



22.4 Measurement of Temperature   494



22.5 Measurement of Flow   497



22.6 Measurement of Level of Liquid   501



22.7 Measurement of Level of Solids   505 22.8 Continuous Weight Measurement   506 22.9 Measurement of Vibration   507 22.10 Process Control   507 22.11 PID Controller   509 22.12 Actuator or Output Device   510



22.13 Plant Automation   517



22.2.1 P and I Diagram   487



22.3.1 22.3.2 22.3.3 22.3.4

Bourdon Tube Pressure Gauge   488 Manometer   489 Pressure Sensor/Transmitter   490 Smart Transmitter   491



22.4.1 22.4.2 22.4.3 22.4.4 22.4.5 22.4.6

Thermocouple   494 Resistance Temperature Device (RTD)   495 Infrared Temperature Measurement Device   495 Liquid Expansion Type Temperature Measuring Device   496 Temperature Transmitter   496 Thermowell   496



22.5.1 22.5.2 22.5.3 22.5.4 22.5.5

Mechanical Flow Meter   497 Differential Pressure Type Flow Meter   497 Electromagnetic Flow Meter   499 Ultrasonic Flow Meter   499 Rotameter   500



22.6.1 Direct Method of Level Measurement   501 22.6.2 Indirect Methods of Level Measurement   503



22.12.1 Pneumatically Operated Control Valve   510 22.12.2 Solenoid Valve   513 22.12.3 Motorised Valve   513 22.12.4 Pneumatic Cylinder   514 22.12.5 Hydraulic Cylinder   515 22.12.6 Variable Speed Drive   516

486–524

Contents 





22.14 Programmable Logic Control (PLC)   518



22.15 Distributed Control System (DCS)   522 22.16 Human Machine Interface (HMI)   523 Exercises   523



22.14.1 Different Modules of PLC   519 22.14.2 PLC Programming   521 22.14.3 Other Features of PLC   522

23. Scope of Energy Conservation in Thermal Power Plants



xvii

23.1 Introduction   525 23.2 Energy Conservation 23.3 Energy Conservation 23.4 Energy Conservation 23.5 Energy Conservation 23.6 Energy Conservation Exercises   537

in in in in in

525–537

Boiler   525 Boiler Auxiliary Equipments   529 Steam Turbine   529 Steam Turbine Auxiliary Equipments   531 Other Auxiliary Systems of a Power Plant   532

Plant Calculations or Numericals

539–554

Appendices

551–554

Index

555–560

Preface I am fortunate enough to be associated with power generation industry for more than two decades and got an opportunity to work at different power plants at different hierarchies. This book is the collection of my field experience. Based on my practical experience at various thermal power plants, I have tried to make the book very practical. A reader can feel the practical approach of the subject while going through it. Well balance between theory and practical aspects and the use of lucid language provide an ease to its readers to grasp the basic concepts. In the beginning, I prepared some notes when I was preparing myself for BOE examination. Finally, those small notes have taken this present shape after a lot of additions and modifications. The book covers the entire cross-functional aspects of a thermal power plant. Some basic concepts of engineering related to power plant are discussed in Chapters 1, 2, 3 and 4. Water chemistry which is very important for a boiler is discussed in Chapter 5. From Chapter 6 to 13, details of various types of boiler, boiler auxiliary systems and operation of boiler are discussed. Tube, pipe and pipe fittings are discussed elaborately in Chapters 14 and 15. Chapters 16 to 19 describe steam turbine, steam turbine auxiliary system, operation of turbine and generator, respectively. Commissioning and maintenance of power plant are described in Chapters 20 and 21, respectively. Control and instrumentation (C&I) for power plant is explained in Chapter 22. Chapter 23 describes the scope of energy conservation in thermal power plant. Plant Calculations or Numericals given at the end of the chapters involves various types of calculations required in day-to-day functioning of a power plant. Feedbacks from my readers, friends and well wishers encouraged me to widen the scope and make this book suitable as a better reference book on thermal power generation. To make the book more useful, some essential topics like PC boiler, AFBC/CFBC boiler, supercritical boiler, combined cycle power generation, advanced supercritical (AD700) technology, IGCC, best available technology, next generation technology, capacity selection of generating sets, coal handling plant, RO plant, large capacity steam turbine, basics of welding, bearing, coupling, shaft alignment, machine vibration, pump, fan, etc. have been incorporated in this book. Around 500 self-test questions are given at the end of each chapter in total. I am personally associated with BOE examination. I suggest BOE examinees to prepare these questions which cover almost full syllabus of BOE examination conducted by various boiler boards. This book will be highly useful for the professional engineers, job seekers, BOE examinees and the students of various engineering colleges and power plant training institutes. I will be fortunate enough if this small book can satisfy the readers and this will be my little contribution to power generation industry. xix

xx 

Preface

Modification and refinement is an ongoing process. I request all my readers to give their valuable feedbacks so that the book can be made more appreciable in future. My wife, Mrs. Amita Mallick and son Amitya R. Mallick have sacrificed a lot for me. Thanks for their understanding, cooperation and support. I would like to thank my colleagues, friends and critics who encouraged me to write this book.

Amiya Ranjan Mallick

Chapter

1

Fundamentals

1.1  INTRODUCTION Before discussing in detail about boiler and power plant, some fundamental knowledge of mechanical engineering is essential. Some such important points are discussed in this chapter which are essential for a boiler operation engineer in his day to day job.

1.2  LAW OF CONSERVATION OF ENERGY This law states that energy can neither be created nor destroyed; it can only be transformed from one form to another. Energy is the capacity to do work. It is available in various forms like mechanical energy, electrical energy, chemical energy, heat energy, light energy, kinetic energy, potential energy etc. In a boiler, chemical energy available in fuel is converted into heat energy during combustion. This heat energy is utilised to convert water to steam. Heat energy is converted to kinetic energy in steam. Kinetic energy of steam is used in steam turbine to convert into mechanical energy. Turbine drives a generator to generate electricity. In generator, mechanical energy is converted into electrical energy.

1.3  TEMPERATURE Temperature of an object is the average energy of its molecules. Molecules move faster when they have more energy. So, the temperature is also related to the average speed of the molecules. Temperature of a body means the warmth or coldness felt during contact with that body. It is measured by a thermometer in quantitative way. Most materials expand when heated. Some materials like mercury expand linearly with temperature. Some other principles normally used to measure temperature are given below:

• • • • • •

Change of length such as length of a mercury column Change of volume such as volume of a fixed mass of gas at constant pressure Change of pressure such as pressure of a fixed mass of gas at constant volume Change in electric resistance as in a thermistor Flow of electricity due to Seebeck effect as in a thermocouple Radiation as in radiation pyrometers 1

2 

Practical Boiler Operation Engineering and Power Plant

There are three well known scales used to measure temperature. These are as follows:

• Centigrade or Celsius scale • Fahrenheit scale • Kelvin scale

Centigrade or Celsius scale:  This scale was developed by Anders Celsius (1701–1744). Celsius divided the difference in temperature between freezing and boiling points of water into 100 units. The point at which water frizzes under atmospheric pressure is considered as 0 °C and that at which water boils is considered as 100 °C. The scale is divided into 100 equal units. One unit is °C called as degree centigrade or degree celsius. This scale is widely used by the engineers in India. Fahrenheit scale:  Daniel Gabriel Fahrenheit (1686–1736) introduced this scale in 1724. As per this scale, freezing point of water is 32 °F and boiling point of water is 212 °F. The difference between these two points is divided into 180 equal units. Each unit is called as degree Fahrenheit or °F. The normal human body temperature is 98.6 °F. Kelvin scale:  Lord William Kelvin (1824–1907) introduced Kelvin (K) scale in 1854. The Kelvin scale is based on the principle of absolute zero. The zero point on Kelvin scale is the lowest possible theoretical temperature that exists in the universe, i.e., –273.15 °C or 0 K. As the temperature goes down, the average energy and the speed of the molecule decreases. There is a temperature at which the molecule stops moving. That temperature is called absolute zero. The freezing point of water is 273.15 K. Boiling point of water is 373.15 K. Each division in the scale is called Kelvin. Neither the term degree nor the symbol (°) is used. As there is no negative numbers on the Kelvin scale, it is very convenient to use Kelvin scale to measure extremely low temperatures for scientific research. A comparison of the above three scales is shown in Figure 1.1.

Figure 1.1  Comparison of different temperature scales.

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3

The temperature measured in one scale can easily be converted to another by using simple formulae given in Table 1.1. Table 1.1  Conversion of Degree Celsius, Degree Fahrenheit and Degree Kelvin into each other From °C °F K

To °C

°F

C (F – 32)/1.8 K – 273.15

(C  1.8) + 32 F (K – 273.15) 9/5 + 32

K C+ 273.15 (F – 32) 5/9 + 273.15 K

1.3.1  Absolute Temperature It is the theoretical lowest temperature possible in the universe. Absolute temperature is the theoretical temperature at which all the molecular motions stop and substances possess no thermal energy. Temperature of any substance cannot fall below this temperature. For calculation, absolute zero temperature is taken as –273 °C or 0 K.

1.4  PRESSURE Pressure is defined as the force per unit area exerted by a body on its surface in a direction normal to the surface. It is caused by the collision of molecules of a substance with the boundaries of the system. As molecules hit the walls, they exert force and try to push the wall outward. The unit of pressure depends upon the unit of force and the unit of area. Different units of pressure are used in power plant. Some of them are given below:

• • • • • • • • •

kilogramme per square centimetre (kg/cm2) kilogramme per square metre (kg/m2) Newton per square centimetre (N/m2) Pound per square inch (psi) Millimetre of mercury column (mmHg) Millimetre of water column (mmwc or mmH2O) Atmospheric absolute (ata) Barometric (bar) kilopascal (kPa)

Also, there are many more pressure units. But only some important units are mentioned here. The relation between all these units is given at end of the book.

1.4.1  Gauge Pressure and Absolute Pressure Pressure gauges are mounted at different pipelines and systems of a power plant. In practice, pressure gauge shows the difference between the actual pressure of the system and the atmospheric pressure. The reading of pressure gauge is known as gauge pressure. The actual pressure or

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absolute pressure of the system (Figure 1.2) can be obtained by adding gauge pressure with atmospheric pressure.

Absolute pressure = Gauge pressure + Atmospheric pressure

Figure 1.2  Absolute pressure and gauge pressure.

The value of atmospheric pressure is taken as 1.0332 kg/cm2 or 1.0132 bar absolute at sea level. If the height of the place is more than the sea level, then the atmospheric pressure of that place is less. At the sea level, the height of mercury column is 760 mm with the density of mercury taken as 13.5951 g/cm3.

1.5  HEAT Heat is the amount of energy in a system. It is transferred from higher temperature objects to lower temperature object through radiation, conduction or convection. Heat of an object is the total kinetic energy of its molecules (and the temperature of an object is the measurement of average energy of its molecules). Heat is denoted by Q and its SI unit is joule (J). Heat is measured by the quantity required to raise the temperature of a known mass of water through some known temperature. Following three units are used to measure the amount of heat:

• Calorie • Centigrade heat unit (CHU) • British thermal unit (BTU)

Calorie:  It is the amount of heat required to raise the temperature of one gram of water by one degree Celsius. Its larger unit is kilocalorie (kcal) which may be defined as the quantity of heat required to raise the temperature of one kilogramme of water through one degree Celsius.



1 kcal = 1000 cal

Centigrade heat unit (CHU):  It is the amount of heat required to raise the temperature of one pound of water by one degree Celsius. 1 pound = 453.6 g So, 1 CHU = 453.6 cal

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5

British thermal unit (BTU):  It is the amount of heat required to raise the temperature of one pound of water through one degree Fahrenheit. In SI unit, unit of heat is joule (J) or kilojoule (kJ). When m kilogramme of substance is heated up to T Kelvin and specific heat is C kilojoule per kilogramme degree Celsius, then the amount of heat (in kilojoules) required is given by H = mCT 1 kcal = 4.1868 kJ



1.5.1  Specific Heat Specific heat of any substance is defined as the amount of heat required to raise the temperature of a unit mass of a substance by one degree Celsius. It is normally denoted by C. Heat required to raise the temperature of one kilogramme of water by one degree Celsius is one kilocalorie. So, the specific heat of water is one. Specific heat of some substances which are required by a boiler engineer is given in Table 1.2. Table 1.2  Specific Heat of Some Substances Substance

Specific Heat (kcal/kg)

Steel Coal Coke Water Steam Air Oxygen Flue gas

0.117 0.241 0.200 1.00 0.500 0.237 0.221 0.23

1.6  WORK When force is applied on a body, the body moves and work is done. Work is the product of force applied on a body and the displacement of the body in the direction of applied force. If F newtons force acts on a body and produces a displacement of X metres in the direction of force, then the work done is given by

W=FX

Depending upon the units of force and displacement, the unit of work is decided. In MKS system, when force is one kilogramme and displacement is one metre, the unit of work is kilogram metre (kgm). In SI unit, the unit of work is newton metre (Nm).

1.7  POWER Power is the rate of doing work. It is defined as the work done per unit time.

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Practical Boiler Operation Engineering and Power Plant



Power =



P =

Work done Time taken dW dT

In metric system, the unit of power is metric horsepower. This is 4500 kgm/min. In SI system, the unit of power is watt (W). or Bigger unit of power is kilowatt.

1 W = 1 Nm/s 1 W = 1 J/s 1 kW = 1000 W

1.8  Energy Energy is the ability or capacity to do work. Different forms of energy like heat energy, light energy, chemical energy, electrical energy, atomic energy, etc. are available.

1.9  Enthalpy Enthalpy is a thermodynamic function of a system equivalent to the sum of the internal energy of the system plus the product of its volume and the pressure exerted on it by its surroundings. Symbolically, enthalpy H is the sum of the internal energy E and the product of the pressure P and the volume V of the system.

H = E + PV

1.10 Laws of Thermodynamics Thermodynamics is a branch of science concerned with heat and its conversion to mechanical energy. Following three laws are important in thermodynamics:

• Zeroth law of thermodynamics • First law of thermodynamics • Second law of thermodynamics

Zeroth Law of Thermodynamics Zeroth law of thermodynamics speaks about thermal equilibrium. According to this law, if systems A and B are in thermodynamic equilibrium and systems B and C are in thermodynamic equilibrium, then systems A and C are also in thermodynamic equilibrium.

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First Law of Thermodynamics First law of thermodynamics is the law of conservation of energy. It states that energy cannot be created or destroyed. It is converted from one form to another. For example, from heat to work, from heat to light, from chemical to heat, etc. Alternately, this law states that a definite amount of heat energy is required to produce a definite amount of mechanical energy and vice versa. According to this law,

W  H   or   W = JH

where J is a constant called as joule mechanical equivalent of heat. It is defined as the amount of work done by the unit quantity of heat. Total heat energy supplied is the sum of the external work done and the change in the internal energy. where H = heat supplied W = work done E = change in internal energy

H=E+W

Potential energy and kinetic energy are macroscopic forms of energy. These are visualised in terms of position and velocity of the substance. In addition to these macroscopic forms of energy, a substance poses several microscopic forms of energy due to rotation, vibration, translation and interaction among molecules of a substance. The sum of all these microscopic form of energy is called as internal energy. Second Law of Thermodynamics This law can be stated in the following two ways: Kelvin and Planck statement:  This is called as the first form of second law of thermodynamics or Kelvin–Plank statement of second law. According to this, it is impossible to convert all the heat supplied to an engine to get an equivalent amount of work. Some portion of the heat supplied is rejected. So, the heat converted into work is always less than the heat supplied to engine. The ratio of the heat converted into work to the heat supplied to engine is known as thermal efficiency of the engine. So, thermal efficiency of any engine is always less than unity. Clausius statement:  According to this, without any external energy, heat cannot flow from cold object to hot object. Heat can flow from higher temperature to lower temperature. But some external energy is required in case of reverse situation, i.e., when heat flows from lower temperature to higher temperature. Second law of thermodynamics also speaks about a useful state variable called as entropy, denoted by S. The change in entropy dS is equal to the heat transfer dH divided by temperature T.

dS =

dH T

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1.11  SPECIFIC HEAT OF GAS As discussed in previous section, specific heat of any substance is defined as the amount of heat required to raise the temperature of unit mass of that substance by one degree Celsius. It is important to note that all solids and liquids have one specific heat. But a gas can have a number of specific heats depending upon the condition under which it is heated. The idea about following two types of specific heat of gas is helpful for a boiler engineer: Specific heat at constant volume CV:  It is the amount of heat required to raise the temperature of a unit mass of a gas through one degree Celsius when the volume of the gas is kept constant. If m kilogramme of gas is heated from initial temperature of T1 degree Celsius to T2 degree Celsius at constant volume, then the heat required is given by

H = mCV(T2 – T1)

Specific heat at constant pressure CP:  It is the amount of heat required to raise the temperature of a unit mass of a gas through one degree Celsius when pressure is kept constant. If m kilogramme of gas is heated from initial temperature of T1 degree Celsius to T2 degree Celsius at constant pressure, then the heat required is given by

H = mCP(T2 – T1)

For a particular gas, CP and CV are assumed to remain constant. CP is always greater than CV . As CP and CV remain constant for a particular gas, so their ratio also remains constant and is more than unity.

g =

CP CV

1.12  THERMODYNAMIC PROCESS OF PERFECT GAS When flow of energy takes place, various properties of gas like pressure, volume, temperature, specific energy, specific enthalpy also change. With the change in properties of a system, state of the system also changes.  The path on which  state of  the  system changes is called  as thermodynamic process. One example of a thermodynamic process is increasing temperature of a fluid while maintaining constant pressure. Another example is increasing pressure of a confined gas while maintaining  a constant temperature.   There are different process like cyclic processes, reversible process, and irreversible process.   Cyclic process:  In cyclic process, a system moves from a given initial state, goes through a number of different changes in state (going through various processes) and finally, returns to its initial state. Therefore, at the end of a cycle, all the properties have the same value they had at  the  beginning.  Reversible process:  A reversible process of a system is a process that once taken place, can be reversed, leaving no change in either system or surrounding. But practically, there is no truly reversible process.  

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9

Irreversible process:  An  irreversible process  is a process in which both the system and the surrounding cannot return to their original condition.     Apart from these processes, following are some important processes which help a boiler engineer in his practical field. Methods of heating and expanding of gas may be applied in case of superheated steam also.

1.12.1  Constant Volume or Isochoric Process In this process, gas is heated at a constant volume. Temperature and pressure increase when heat is added to the system. As there is no change in the volume of the gas, so total heat supplied is stored in the gas as internal energy. If m kilogramme of gas is heated at constant volume from initial temperature of T1 degree Celsius to final temperature of T2 degree Celsius, then the heat supplied which is equal to increase in the internal energy of gas is given by

H = mCV(T2 – T1)

where CV is the specific heat of the gas at constant volume.

H=E+W

In this case, work done is zero. So, the heat supplied is equal to

H = E = mCV(T2 – T1)

This process is shown in the P–V and T–S diagram. P–V diagram [Figure 1.3(a)] shows the change in volume and pressure, whereas T–S diagram [Figure 1.3(b)] shows change in entropy and temperature of the gas. P–V and T–S diagrams are used to visualise the process in thermodynamic cycle and help to understand the changes in system parameter.

Figure 1.3  Constant volume process (a) P–V diagram and (b) T–S diagram.

1.12.2  Constant Pressure or Isobaric Process When a gas is heated at constant pressure, its temperature as well as volume increases. As the volume and temperature increase, heat supplied is utilised for doing some external work and increasing internal energy.

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Practical Boiler Operation Engineering and Power Plant

If m kilogramme of gas is heated at constant pressure from initial temperature of T1 degree Celsius to T2 degree Celsius, then the heat supplied is given by

H = E + W H = mCP(T2 – T1)

where, CP is the specific heat of gas at constant pressure. This process is shown in P–V and T–S diagram (Figure 1.4).

Figure 1.4  Constant pressure process (a) P–V diagram and (b) T–S diagram.

Work W done during this process is the shaded area below line 1–2. So, W = Area of 12V2V1 = Area of P12V2O – Area of P11V1O = P1V2 – P1V1 = P1(V2 – V1)

1.12.3  Constant Temperature or Isothermal Process In this process, heat is supplied to a gas in such a way that its temperature remains constant and the volume of the gas increases. The expansion of the gas is called as isothermal expansion. When heat is taken out at constant temperature, volume of the gas decreases. As there is no change in the temperature of the gas, change in internal energy is zero. All the heat supplied is used for doing external work. In this process, PV is constant. This process is shown in P–V and T–S diagrams (Figure 1.5).

Figure 1.5  Isothermal process (a) P–V diagram and (b) T–S diagram.

Work done in this process is equal to heat supplied, as there is no change in internal energy.

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1.12.4  Adiabatic Process or Isentropic Process In this process, the system neither receives nor rejects any heat. The expansion and contraction of the gas depend upon the change in internal energy of the gas. As the internal energy changes in this process, so the temperature of the gas also changes. External work is done in this process. In this process, PV g = Constant



where, g is the ratio of specific heats. This process is shown in the P–V and T–S diagram (Figure 1.6).

Figure 1.6  Adiabatic process (a) P–V diagram and (b) T–S diagram.

We know,

H=E+W

As there is no heat supplied, so H = 0 E = –W

or

1.12.5  Free Expansion Process In this process, the gas is allowed to expand suddenly into a vacuum chamber through an orifice of large dimension. No heat is added or no external work is done and no internal energy is developed. So, in this case,

H = 0   and   W = 0

1.12.6  Throttling Process In this case, the gas is expanded through an aperture of small dimension like a slightly opened valve. There is also no work done, no heat is supplied and no change takes place in internal energy.

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1.13  Thermodynamic Cycle As discussed earlier, any change in the system like compression, expansion, heating and cooling, etc. can be represented on a P–V diagram. When any working fluid of a system undergoes a number of operations or processes in a certain order and finally, returns to the initial state, then a thermodynamic cycle takes place. In the P–V diagram, each operation has its own curve and finally, they form a closed figure. The work done during one cycle is given by the enclosed area of the P–V diagram. There are a number of cycles in the field of mechanical engineering. But only about those cycles are discussed here which are useful for a boiler engineer.

1.13.1 Carnot Cycle with Steam as Working Fluid Sadi Carnot, a French scientist and engineer in 1800, proposed an ideal cycle. In a heat engine, heat is always rejected. Work done is the difference between the heat absorbed and the heat rejected. The maximum efficiency is limited by temperature difference. The most efficient theoretical thermodynamic cycle which is possible between any two temperatures is given by Carnot cycle (Figure 1.7).

Figure 1.7  Carnot cycle (a) P–V diagram and (b) T–S diagram.

Carnot cycle is a four step process having two isothermal processes and two adiabatic processes (i.e., without heat transfer). In the isothermal steps, there is no change in internal energy and the heat supplied is equal to the work done. In two adiabatic processes, the heat is not exchanged. It is impossible to build such a system. This is an idealised process. The importance of the cycle is that it gives an idea about the highest efficiency of any cyclic process between two temperatures. The four steps of Carnot cycle are explained below: Isothermal expansion (1–2):  The first process performed is an isothermal expansion. Volume

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13

and pressure of the fluid change from V1 to V2 and P1 to P2 respectively. This process is represented by curve 1–2. Adiabatic expansion (2–3):  The second process is an adiabatic expansion. During this process, the fluid is allowed to expand till point 3. At this point the volume, temperature and pressure are dropped to V3, T3 and P3. This process is represented by curve 2–3. Isothermal compression (3–4):  The third process is again an isothermal compression. The fluid is compressed till point 4. This process is shown in curve 3–4. Adiabatic compression (4–1):  The fourth process performed on the fluid is an adiabatic compression. So, the fluid is compressed adiabatically from point 4 to point 1. Pressure and temperature return back to their original state as before starting of the cycle. This process is represented by curve 4–1. Work done during the cycle = (S2 – S1) (T1 – T3) Efficiency of Carnot cycle = 1 – T3 /T1 Carnot cycle is a theoretical cycle. No engine can be made on this cycle.

1.13.2  Rankine Cycle Rankine cycle was proposed by Scottish engineer W. J. M. Rankine (1820–70). This cycle is mostly used at thermal power plants for power generation by steam turbine. There are four processes in the Rankine cycle. During each process, the state of the working fluid changes. These states are identified by number in P–V and T–S diagrams of a Rankine cycle (Figure 1.8) using dry or superheated steam. Dashed lines are shown for Rankine cycle using superheated steam.

Figure 1.8  Rankine cycle (a) P–V diagram and (b) T–S diagram.

Process 4-1:  First, the working fluid (feed water) is pumped from low pressure to high pressure by a boiler feed pump into the boiler. Pumping requires power input (for example, mechanical or electrical). Process 1–2:  The high pressure liquid (feedwater) enters a boiler where it is heated at constant pressure by an external heat source to convert it into superheated vapour. Heat is obtained by burning fuel.

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Process 2–3:  The superheated vapour expands in a turbine to generate power. Ideally, this expansion is adiabatic. Temperature and pressure of the vapour decrease upto the condenser pressure. Process 3–4:  The vapour then enters a condenser where it is cooled to make saturated liquid. This liquid then reenters to the boiler through pump and the cycle repeats. The above discussed cycle is an ideal cycle. In practice, an actual rankine cycle is different from the ideal cycle. The actual cycle is 4–1–2–3, whereas the ideal cycle is 4–1–2–3, as shown in Figure 1.8 and 1.9.

Figure 1.9  Actual Rankine cycle.

An actual rankine cycle differs from the ideal rankine cycle for the following reasons: Turbine losses:  During the expansion of steam in the turbine, there is always a heat loss to the surroundings and the expansion does not exactly follow 2–3. Instead, it follows a path 2–3. Pump losses:  There is always a loss in the pump. So, the process follows 4–1 instead of actual path 4–1. Condenser losses:  Sometime, the fluid cools below the saturation temperature at condenser. This is called as subcooling. So, more heat is required to bring the liquid upto the saturation temperature. We know that carnot cycle can develop maximum power with certain high and low temperature limits than any other cycle. It is not practicable to get an efficiency equal to that of a carnot cycle. But, it is always expected to gain an efficiency close to that of a carnot cycle. In thermodynamic cycle, a small gain in overall efficiency is an important achievement. Following two methods are adopted to increase the efficiency of rankine cycle:

• By reheating the exhaust steam and using it again at turbine (reheat cycle) • By extracting some steam from the turbine and using it for feedwater heating (regenerative cycle) These thermodynamic cycles are called as modified rankine cycle.

Reheat Rankine Cycle Increasing boiler pressure increases the thermal efficiency. But steam becomes wet at the exhaust end. Wet steam causes erosion of turbine blades. In reheat Rankine cycle, this problem

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15

is avoided. Steam is extracted from high pressure turbine and then, it is reheated in the boiler again and sent back to the low pressure turbine for further expansion. Thus, excessive moisture in the low pressure stages of the turbine is avoided. There are two turbines working in series. As shown in Figure 1.10, steam after expanding at high pressure turbine from 3–4 is extracted and further heat is added to it at boiler. This is represented by 4–5. This reheated steam enters the low pressure turbine and further gets expanded till the condenser pressure is achieved. This process is represented by 5–6.



Figure 1.10 Reheat Rankine cycle (a) Flow diagram of reheat Rankine cycle and (b) T–S diagram of reheat Rankine cycle.

Benefits of reheat:  The benefits of reheat are given below:

• Boiler pressure can be increased without increase of moisture content at turbine exhaust. • Average temperature of the steam entering the turbine is increased, so the thermal efficiency of the cycle increases.

Regenerative Rankine Cycle In regenerative Rankine cycle (Figure 1.11), considerable amount of energy input is required at boiler to heat the high pressure feedwater from its normal temperature to the saturation temperature. To reduce this energy, the feedwater is preheated before it enters the boiler. Preheating of feed water is done by regeneration method. The device in which feed water is heated is called as feedwater heater. Some steam is extracted from various stages of the turbine and used to preheat the feedwater. Benefits of regeneration:  The benefits of regeneration are given below:

• Energy loss within the condenser is less, since less steam is condensed. • Temperature of feedwater entering the boiler increases. So, the efficiency of the cycle also increases.

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Figure 1.11 Regeneratiive Rankine cycle (a) Flow diagram of regenerative Rankine cycle and (b) T–S diagram of regenerative Rankine cycle.

Regeneration is achieved by open or close feedwater heaters. In closed system, the bled steam from the turbine is not directly mixed with the feed water and therefore, the two streams can be at different pressures. In practical steam power plants, various combinations of open and closed feedwater heaters are used. Deaerator is an open heater and low pressure/high pressure heaters are closed feedwater heaters. Combined Reheat and Regenerative Rankine Cycle In practice, the combination of reheat and regenerative Rankine cycle is used in thermal power plants. Single or double stage reheat along with a series of high pressure and low pressure feedwater heaters are used in practical power plant. The combined reheat and regenerative cycle is shown in Figure 1.12.



Figure 1.12 Benefits of combination of reheat and regenerative cycle: This arrangement increases the thermal efficiency of the plant.

Details about the reheat and regenerative heater arrangement are discussed later.

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Effect of Design Parameters on Rankine Cycle Power plant is required to be designed for the highest efficiency as far as possible and steam parameters are selected accordingly. Rankine efficiency increases with the increase in steam pressure and temperature. Regenerative or reheat cycle is selected depending upon the capacity of the plant and other conditions. The effects of parameters on Rankine cycle efficiency are discussed below: Effect of inlet steam pressure:  If the turbine inlet steam pressure is increased, then Rankine cycle efficiency also increases. It can be seen from Figure 1.13. Cycle area changes from 1–2–3–4 to 1–2–3–4. After the expansion at turbine, steam condition shifts towards the left, i.e., from 4 to 4. The steam becomes more moist. So, the inlet pressure should be selected in such a way so that minimum heat rate is achieved with allowable exhaust steam condition for a particular inlet steam temperature. Excessive moist steam can damage the turbine blades. Otherwise, to avoid excessive moist steam, reheat cycle can be considered.

Figure 1.13  Effect of inlet steam pressure on Rankine cycle.

Increase in work done is given by the difference of area A and area B, as shown in Figure 1.13. Effect of inlet steam temperature:  On increasing the turbine inlet steam temperature, the efficiency of Rankine cycle increases. This can be seen from Figure 1.14. Cycle area changes from 1–2–3–4 to 1–2–3–4.

Figure 1.14  Effect of the inlet steam temperature on Rankine cycle.

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It is clear that area 3–3–4–4 is added to the previous area 1–2–3–4. So, the net work done increases. For high temperature use, costly alloy steel is required and also, due to metallurgical limitations, temperature of the steam cannot be increased beyond certain limits. Effect of exhaust pressure:  If the turbine exhaust pressure decreases from 4 to 4, then the cycle efficiency increases, as shown in Figure 1.15. More work is done by the steam and the area of the cycle changes from 1–2–3–4 to 1–2–3–4.

Figure 1.15  Effect of exhaust pressure on Rankine cycle.

It can be seen from Figure 1.15 that area 1–2–4–4 is added to the earlier area 1–2–3–4. The condenser vacuum is to be maintained as low as possible. Air ingress in the vacuum system or scaling of condenser tube can increase the condenser pressure.

1.13.3  Brayton Cycle The Brayton cycle or Joule cycle is a thermodynamic cycle related to the gas turbine. Gas turbines are used for power generation. Mostly, the combined cycle technology is used worldwide for efficient way of power generation. Details about the combined cycle are discussed later. Brayton cycle consists of following three components:

• A compressor • A Combustion chamber • An expansion turbine

Usually, the gas turbine is operated on open cycle [Figure 1.16(a)]. Fresh atmospheric air enters the compressor where it is compressed. This compressed air then enters the combustion chamber where fuel is burnt and heat is added at constant pressure. After that, the hot compressed air enters the turbine where it is expanded to atmospheric pressure. After expanding, the exhaust gas is discharged to the atmosphere. A part of the power developed in the turbine is to be supplied to the compressor power requirements and the remaining is available to drive the turbine. In close cycle operation [Figure 1.16(b)], both the compression and expansion processes remain same as open cycle but the combustion process is replaced with the heat addition at constant pressure by the external source and the exhaust process is replaced with the heat rejection at atmospheric and constant air pressure.

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Figure 1.16  Brayton cycle arrangement (a) Open cycle operation and (b) Closed cycle operation.

The above process can be summarised as below:

• • • •

1–2 2–3 3–4 4–1

adiabatic compression at compressor constant pressure heat addition adiabatic expansion in the turbine constant pressure heat rejection

These four processes are shown in P–V and T–S diagrams given in Figure 1.17.

Figure 1.17  Brayton cycle (a) P–V diagram and (b) T–S diagram.

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EXERCISES

1. 2. 3. 4. 5. 6. 7. 8. 9.



10. 11. 12. 13. 14. 15. 16.

17. 18.

What kind of energy is available in the fuel? How does energy conversation take place in a boiler? What happens to the speed of the molecules in a material when it is heated? What is the theoretical lowest temperature possible in the universe? What is absolute zero temperature? What is the difference between gauge pressure and absolute pressure? How many kilojoules are there in one kilocalorie? What is specific heat? Can we convert the total heat energy supplied to an engine into work? Which law speaks about this? What is cyclic process? Is it possible to build an engine based on Carnot cycle? On which cycle does the steam turbine-based thermal power plant operate? What is the role of a boiler, steam turbine, condenser and feed pump in Rankine cycle? Why is an actual Rankine cycle not same as the ideal Rankine cycle? How can the efficiency of Rankine cycle be increased? What changes are observed in Rankine cycle when the turbine inlet steam temperature, pressure and exhaust pressure change? On which cycle does the combined cycle power plant work? What are the main equipments of a Brayton cycle?

Chapter

2

Heat Transfer Methods

2.1  INTRODUCTION In the previous chapter, we have discussed about the law of conversion of energy. Energy is available in nature in various forms. We can use the energy stored in a fuel to convert it into thermal energy and then, this thermal energy may be used to drive the turbines to produce electrical energy. In a boiler, the heat energy released by burning of fuel is transferred to feedwater. Thermal energy can originate from any kind of energy according to the first law of thermodynamics. It can be transmitted from one system to another which is governed by the second law of thermodynamics. Due to the difference in temperature, heat flows from a body at higher temperature to a body at lower temperature. In boiler, heat transfer takes place from flue gas at higher temperature to boiler tubes and then, to feedwater which is at lower temperature. So, a boiler operation engineer should have some idea about the heat transfer methods. Thermal energy is transferred from a hotter body to a colder body. The basic driving force of heat is the temperature difference or temperature gradient. Heat transfer is possible in three ways. These are as follows:

• Conduction • Convection • Radiation

In fluids, heat is often transferred by convection. The motion of the fluid itself carries heat from one place to another. Another way by which heat can be transferred is the conduction which does not involve any motion of a substance but rather, is a transfer of energy within a substance (or between substances in contact). The third way to transfer energy is the radiation which involves absorbing or giving off thermal waves. In a boiler, heat transfer takes place by all these three ways. These are discussed in detail in subsequent sections.

2.2  HEAT TRANSFER BY CONDUCTION Heat energy can be transferred from one substance to another when they are in direct contact. This type of heat transfer takes place in solid objects. Heat transfer in this method is linearly related to the temperature difference. This method of heat transfer is called as conduction. 21

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Conduction method of heat transfer is mainly seen in solid objects. It happens when any hot material comes in contact with a cold material. When heat is transferred through conduction, the substance itself does not move; rather, heat is transferred internally by vibrations of atoms and molecules. Electrons can also carry heat. Metals have many free electrons which move around randomly. They can transfer heat from one part of the metal to another. So, metals are generally good conductor of heat. Some solid materials are better conductor of heat than the others. For example, metals are good conductors of heat while a material like wood is not. When a metal is heated at one end, the other end also becomes hot while that does not happen with a piece of wood. Good conductors of electricity are often good conductors of heat. Since the atoms are closer together, solids conduct heat better than the liquids or gases. This means that two solid materials in contact would transfer heat from one to the other better than a solid in contact with a gas or a gas with a liquid. In 1822, Fourier proposed a fundamental law of heat conduction. This law is called as Fourier’s law.

2.2.1  Fourier’s Law The main condition of heat transfer by conduction is the temperature difference. Heat always flows from a hotter body to a colder body. Fourier’s law states that the rate of heat transfer is the product of area normal to the heat flow path, temperature gradient and thermal conductivity of the material. Mathematically, this can be written as

q=

dQ dt = - KA dt dx

(2.1)

where q = rate of heat transfer K = thermal conductivity of the conducting material A = area normal to the heat flow path dt/dx = temperature gradient or the rate of change of temperature with reference to the distance in the direction of heat flow. As the heat always flows in the direction of decreasing temperature, so temperature gradient dt/dx is negative. If A is the area of the surface in square metre, change in temperature, DT is in degree Celsius and heat q is in watts or joule per second, then the unit of thermal conductivity is watt per metre degree Celsius (W/m °C) or watt per metre degree Kelvin (W/mK). Now, Eq. (2.1) can be written as

q = - KA



q = -

DT 1

DT R

where, R = l/KA, called as thermal resistance of the material.

(2.2)

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23

Equation (2.2) is similar to the basic law of flow of current which is given by I =-

DV Ri

So, both the electricity and the heat flow system can be considered to be analogous. The electrical and thermal quantities which are analogous to each other are as follows:

V = Voltage Ri = Resistance I = Current Q = Charge

T = Temperature R = Resistance q = Heat flow Q = Heat

2.2.2  Thermal Conductivity Thermal conductivity is the physical property of a substance which is responsible for the heat transfer by conduction. As discussed earlier, the unit of thermal conductivity is watt per metre degree Celsius (W/m °C) or watt per metre degree Kelvin (W/m K). Thermal conductivity is different for different materials. It is highest for solids, lowest for gases and lies in between in case of liquids. The thermal conductivity for gas lies between 0.005 W/m K to 0.5 W/m K. For liquids, it is 0.08 W/m K to 0.6 W/m K. Thermal conductivity of solids lies between 0.04 W/m K to 300 W/m K. As the thermal conductivities of gases and liquids are less, so the heat transfer in these mediums is negligible by conduction.

2.3  HEAT TRANSFER BY CONVECTION Molecules of a liquid and gas are not confined to a certain point. They change their position. In this case, heat energy is transported from one point to another by the movement of these molecules. This phenomenon of heat transfer is called as convection. Heat transfer in fluids is generally done through convection. Hotter part of the fluid is not as dense as the cooler part, so there is an upward buoyant force on the hotter fluid, making it rise while the cooler and denser fluid sinks. Convection current is set up in the fluid. Convection may take place naturally through the creation of convection current or by applying some external force. In 1701, Newton proposed the fundamental heat convection equation called as Newton’s law of cooling.

2.3.1  Newton’s Law of Cooling The rate of heat transfer by convection is the product of heat transfer area, difference of temperature between surface and that of fluid and a constant called as convective heat transfer coefficient.

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The equation can be written as

q = hA∆T

where q = average rate of heat transfer by convection in watts or joule per second A = heat transfer area in square metre DT = difference of temperature between surface and that of the fluid in degree Celsius h = convective heat transfer coefficient in watt per square metre degree Kelvin From the fundamentals of convection, it is clear that the heat transfer takes place due to the movement of molecules. So, to determine h, knowledge of fluid mechanics is also required. When any liquid nearer to heat source becomes hot, then it becomes lighter than the cold liquid. Hotter liquid rises up and is replaced by colder liquid. So, the convection is not only a heat transfer mechanism. In this case, law of liquid dynamics also plays a role. The fluid motion may be achieved by the following two processes:

• Natural circulation (caused by density difference produced by temperature gradient) • Forced circulation (by using some external source)

The heat transfer coefficient which is defined in Newton’s law of cooling, depends on some properties of fluid. Some important properties are listed below:

• Fluid velocity V which further depends upon temperature difference DT, coefficient of volume expansion of the fluid b and acceleration due to gravity g (in case of natural circulation) • Fluid density r • Thermal conductivity of fluid k • Specific heat CP • Fluid viscosity m • Linear dimension of heat transfer surface

2.4  HEAT TRANSFER BY RADIATION Thermal energy is radiated in the form of electromagnetic waves. When a body absorbs these electromagnetic waves then heat transfer takes place. This type of heat transfer is called as radiation. We feel the hotness of sun through radiation. As discussed in earlier two methods of heat transfer, some medium is required for heat transfer. But in case of radiation, no material medium is required to transfer heat from one point to another. Heat transfer by radiation can take place in vacuum also.

2.4.1  Absorption, Reflection and Transmission of Radiation When electromagnetic waves fall on the surface of a body, then some part of the energy is reflected or scattered, some part is absorbed and some part is transmitted. This is shown in Figure 2.1.

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25

Figure 2.1  Total radiation utilised in different ways.

The fraction of incident radiation which is absorbed by the body is called as the absorptivity a. The fraction which is reflected is called as reflectivity r and the fraction which is transmitted is called as transmissivity t. For anybody, a+r+t=1 Different bodies have different absorptivity, reflectivity and transmissivity. Accordingly, the body may be classified as black body, white body and transparent body. Black Body When all the incident radiations are absorbed by the body and there is no reflection and transmission, the body is called as black body. In this case, a = 1,  r = 0  and  t = 0 Black body plays a vital role in the study of radiation. But practically, there is no black body. Some part of the energy is reflected and transmitted. All the energy cannot be absorbed. Theoretically, the heat retransfer equation by radiation is based upon black body and then, it is refined according to the situation. The Stafen–Boltzmann law is based upon black body. To have a clear idea about black body, Figure 2.2 may be referred. If we make a small hole in the wall of a hallow sphere and allow radiation to enter through this hole, then it is partially absorbed and partially reflected. The reflected radiation is again absorbed partially and the rest is reflected. Like this, most of the radiations are absorbed and finally, the energy escaped through the hole is so negligible that it can be considered as zero.

Figure 2.2  Concept of a black body.

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White Body A body which reflects all the incident radiation and does not absorb or transmit is called as a white body. In this case, a = 0,  r = 1  and  t = 0 Grey and Coloured Body Grey body emits only a fraction of thermal energy emitted by an equivalent black body. By definition, a grey body has a surface emissivity less than one and a surface reflectivity greater than zero. If the absorptivity of the body varies with the wavelength of the radiation, the body is called as coloured body. Transparent and Opaque Body When a part of the incident radiation is transmitted, the body is called as the transparent body. When there is no transmitted radiation, the body is called as opaque body.

2.4.2  Emissivity The emissivity of a substance depends upon its nature and the characteristic of its surface. The ratio of emissive power of the considered surface and that of a hypothetical black body is called as emissivity of that surface. It is denoted by e. By definition, a black body has a surface emissivity of one. The emissivity is also equal to the absorption coefficient or the fraction of any thermal energy incident on a body that is absorbed.

2.4.3  Stefan–Boltzmann Law In 1879, Stefan proposed that the total emissive power of a radiating surface of a black body is proportional to the fourth power of the absolute temperature of the surface. This was then proofed by Boltzmann in 1884. Mathematically, this law may be written as where

q = sAT 4 q = rate of heat emission by radiation A = area of the emitting body in square metre T = absolute temperature in degree Kelvin s = a constant known as Stafen–Botzmann constant

If heat transfer takes place from a black body to another black body, then the net transfer of heat by radiation is given by q = s AF (T14 - T24 ) Here, F is a factor which depends upon the geometry of the two surfaces.

(2.3)

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27

If the bodies are not black, then

q = s AFg (T14 - T24 )

(2.4)

where, Fg is a factor which depends upon geometry, emissivity and relative location of the two surfaces.

2.4.4  Geometrical Factor or Configuration Factor The radiation between two surfaces depends upon the emission, absorption, reflection and characteristic of the two surfaces. Besides this, another factor is important which needs to be considered. This is the geometrical arrangement of the two surfaces. As discussed, for two black bodies, the heat transfer is given by Eq. (2.3), i.e., q = s AF (T14 - T24 ) From Eq. (2.3), the heat transfer between grey surfaces may be considered. If the emissivity of two surfaces is considered as e1 and e2, another configuration factor Fg replaces the geometric factor F. Here, Fg depends on the geometrical arrangement of the two surfaces as well as emissivity of the two surfaces. So, the heat transfer equation for any body is given by Eq. (2.4), i.e.,

q = s AFg (T14 - T24 )

2.5  HEAT TRANSFER METHODS IN A BOILER In a boiler, the thermal energy obtained by burning of fuel is transmitted to the feedwater by all the three methods of heat transfer. Heat transfer surfaces are placed at suitable location to get an efficient heat transfer. In a boiler, these heat transfer elements are evaporator, superheater, economiser and air heater. These heat transfer elements are discussed later. For a pulverised/oil/gas-fired boiler, the furnace layout is shown in Figure 2.3.

Figure 2.3  Locationwise heat transfer methods in a boiler.

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EXERCISES

1. What are the three methods of heat transfer? 2. What is the relation between heat transfer and temperature difference in case of conduction method of heat transfer? 3. Which law is connected to the conduction method of heat transfer? 4. Which method of heat transfer is depicted by Newton’s law of cooling? 5. Which law is connected to the radiation method of heat transfer? 6. What is the relation between heat transfer and surface temperature in case of radiation method of heat transfer? 7. What is black body? 8. Which method involves heat transfer in a boiler?

Chapter

3

Fuel and Combustion

3.1  INTRODUCTION The main constituents of fuel are carbon and hydrogen. So, fuel is also called as hydrocarbon. In fuels, the energy is stored in the form of chemical energy that can be released as heat by combustion or oxidation. This heat can be used for various purposes. Heat energy can be used directly or can be converted into mechanical energy. There are different types of fuels available in different forms. The fuels are classified as follows:

• • • •

Fossil fuel Byproduct fuel Chemical fuel Nuclear fuel

Fossil fuel is derived from fossil remains of plant and animals. These fuels are found in the inner layers of the earth. It takes million years to convert the fossils of plants and animals into fuel. Coal and petroleum are the examples of this type of fuel. Byproduct fuel is the co-product of some manufacturing processes. Coke oven gas is the example of this type of fuel. This gas is produced during the formation of coke from coal in coke oven. Blast furnace gas is another example of this type of fuel. Chemical fuel is not used in conventional boilers. Hydrazine (rocket fuel), ammonium nitrate, fluorine, etc. are the examples of chemical fuel. Nuclear fuel releases heat due to fusion. Uranium and plutonium are the examples of this type of fuel. Further, we may classify fuel as given below:

• Primary fuel • Secondary fuel

The fuel which is available naturally like coal, wood, petroleum and natural gas are called as primary fuel. Secondary fuel is derived from primary fuel like coke, fuel oil, petrol, diesel, kerosene, etc. The fuels are also classified into three categories depending upon the state of availability. These are as follows: 29

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• Solid fuel • Liquid fuel • Gaseous fuel

In the subsequent sections, we will discuss about some fuels which are normally used in boilers.

3.2  SOLID FUEL Solid fuels are available in solid form. Wood, coal, charcoal etc. are the examples of solid fuel.

3.2.1  Wood Wood is the first fuel known to man. Thousands of years back, ancient men discovered how to burn wood. Today also, wood is used as domestic fuel. In some cases, wood is also used in boiler to generate steam. The main constituents of wood are cellulose and lignin which are the compounds of carbon, hydrogen, oxygen, wax and water. As the percentage of water and oxygen is more in wood, so its calorific value is low. The proximate analysis of different constituents of wood is given below: Cellulose 50% Resin + Wax 2% Water soluble 1% Lignin 30% Moisture 15% Ash 2% Calorific value 4500 kcal/kg The ultimate analysis of wood is given below: Carbon Hydrogen Oxygen

50% 6% 44%

Wood chips, saw dust, bagasse and biowaste are used as fuel in boiler. Charcoal Charcoal is produced by carbonisation or by heating wood in the absence of air or oxygen upto 600 °C. The composition of charcoal is given as Carbon Oxygen and nitrogen Hydrogen Ash Calorific value   7500

80% 15% 2% 3% kcal/kg to 8000 kcal/kg

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31

3.2.2  Coal Coal is the major fuel used in today’s boilers. Most of the power boilers use coal as fuel to generate steam. The firing process may be different for different boilers like stoker fired boiler, FBC boiler, and pulverised boiler, etc. As the main constituent of coal is carbon, coal is called as black gold. Coal is a fossil fuel and is made from the remains of plants. Millions of years ago, the plants which were died, are covered by layers of mud and sediments. The process is initiated by anaerobic bacteria and continues under the action of temperature and pressure within the earth’s crust for several million years. Then, it is converted from peat to anthracite coal. This process is called as coalification. Coal is formed in various stages from peat to anthracite. Different stages of coal formation are given below: Plant debris  Peat  Lignite  Brown coal  Subbituminous coal  Bituminous coal  Semi-anthracite coal  Anthracite coal In these stages of coal formation, the preceding stage is more mature and of higher rank than the previous stage. Peat:  It is the first stage in the formation of coal. It is a spongy substance that contains a large amount of water. So, it is to be dried to reduce moisture before utilising it as fuel. When it is mined, the moisture content is as high as 60%. The ultimate analysis of air dried peat is given below: Carbon 55% Hydrogen 6% Oxygen 35% Nitrogen 3% Sulphur 1% Calorific value   5000 kcal/kg Lignite:  It contains high percentage of moisture. It exhibits woody structure. It occurs in thick seam (upto 30 m seam) and nearer to the earth’s surface, as shown in Figure 3.1. On exposure to air, moisture is reduced.

Figure 3.1  Availability of different stages of coal one earth.

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The ultimate analysis of lignite is given below: Carbon Hydrogen Oxygen Nitrogen Sulphur Calorific value   5500

70% 6% 22% 1% 1% kcal/kg

Bituminous coal:  In section 3.2.2, various stages of coal formation have been discussed to describe how coal is formed. But practically, coal is found as lignite, bituminous and anthracite. To avoid confusion of the reader, all the stages of coal which do not fall under lignite and anthracite are grouped under bituminous coal. Most of the coal available in India is of bituminous type. Further, bituminous coal is divided as follows:

• Caking bituminous coal • Non-caking bituminous coal

Caking coal softens and swells on heating. The pieces of coal adhere together and form a pasty mass. It burns with long flame. Non-caking coal burns with shorter flame. This coal is mostly used in Boiler. The ultimate analysis of bituminous coal is given below: Carbon Hydrogen Oxygen Calorific value

80%–92% 6%–4% 0.5%–15% 8000 kcal/kg

Anthracite coal:  It is the last stage of coalification. This type of coal is available in deeper surfaces of the earth with narrow seam. This is the most matured coal. This type of coal is having less volatile matter and high carbon percentage. It has sub-metallic lustre. Sometimes, it appears like graphite. It burns without smoke with short non-luminous flame. As volatile matter is less, it ignites with difficulty. The ultimate analysis of anthracite coal is given below: Carbon Oxygen Hydrogen Calorific value

over 90% 0.4%–3% 2.8%–3.9% 8600 kcal/kg

Cannel Coal and Bog Head Coal Previously discussed coals are called as humic coal. The conversion from peat to anthracite coal takes place in case of higher plants. There is another type of coal which is also derived from the vegetable origin but from smaller plant organisms like alge and spores. By their nature, this type of coal cannot be fitted into the peat to anthracite coal series. This coal is having high volatile matter and higher hydrogen corresponding to normal humic coal. It burns with long and steady flame.

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33

The ultimate analysis of bog head of coal is given below: Volatile matter Oxygen Hydrogen Calorific value

65%–90% 8%–15% 6%–10% 9500 kcal/kg

The ultimate analysis of cannel coal is as follows: Volatile matter Oxygen Hydrogen Calorific value

45%–56% 5%–12% 6%–10% 9500 kcal/kg

3.2.3  Coke Coke is produced by thermal decomposition of coal. It is produced when coal is heated in the absence of air. This process is called as carbonisation of coal. By heating, volatile matter is removed from coal. Coke is porous and it burns without smoke. The carbon content is 85% to 90%. Its calorific value is higher than that of the coal.

3.2.4  Biomass Fuel Biomass fuel is a renewable fuel obtained from the living organisms. It is obtained from the waste materials of plants, wood, agricultural wastes and dead parts of the plants. Biomass fuel does not add carbon dioxide to the atmosphere, as it absorbs the same amount of carbon dioxide in growing which it releases when used as a fuel. Biomass is an important source of energy and the most important fuel worldwide after the fossil fuels. Biomass can be burned loose as fuel directly or it may be compressed into briquettes. Briquetting is a densification process in which biomass is compressed to form blocks of different shapes to improve its utility and convenience of use. Normally, the availability of biomass varies from region to region. Following types of biomass are used as a fuel in the boiler for power generation:

• • • • • • • • • •

Wood chips Sawdust Rice husk Rice straw Corn straw Wheat straw Groundnut shell Soya shell Bagasse Cotton stalk

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The gross calorific value of the above biomass is 3300 kcal/kg–4500 kcal/kg. Biomass may be fired directly in a boiler or may be used as a co-fuel. In co-firing arrangement, certain percentage of biomass is mixed with the coal in coal-fired boilers. Either biomass is blended with coal or separately injected into the boiler in co-firing. Sometimes, gasification technology is used to use biomass fuel. In this case, biomass is first fed to gasifier to generate producer gas and then, it is fired in a boiler. In our day to day life, we generate appreciable quantities of waste or garbage. These wastes are known as municipality solid waste (MSW) and normally, these are dumped in landfill sites. Due to the shortage of landfill site and environmental pollution, it is creating a problem. It is found that about 40% of the waste generated by us is combustible. The calorific value of this waste is 1/5th that of the coal. So, this waste can be used as a fuel.

3.3  LIQUID FUEL Most of the liquid fuel is derived from petroleum. Liquid petroleum is obtained from the bore hole in earth’s crust. This liquid fuel consists of hydrogen and carbon. Like coal, petroleum is also a fossil fuel. It is made from remains of animals that lived millions of years ago. It is believed that petroleum is formed by decay and decomposition of marine animals under high pressure and temperature. Typical composition of petroleum is mentioned below (by weight percentage): Carbon Sulphur Oxygen Hydrogen Nitrogen

84%–87.5% 0.1%–3% 0.3%–1.8% 11%–15% 0.1%–1.55%

From petroleum, different fuels are obtained by distillation process (Figure 3.2). Petroleum is heated in oil refineries to separate the constituents. The products having low boiling point and molecular weight are separated first while the products having high boiling point and heavier molecular weight are separated at last.

Figure 3.2  Distillation process of petroleum.

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35

Mainly, in boiler, naphtha, diesel, light fuel oil and heavy fuel oil are used as fuel. These fuels are having high calorific value, i.e. 10000 kcal/kg to 11300 kcal/kg. As these fuels are having more hydrogen content (11.8%–14.5%), so their calorific values are high. They contain very low ash (0.01–0.02%). Sulphur content increases with the increase in boiling range. So, in case of naphtha, it is 0.01% and for heavy fuel oil, it is 2%–4%. During paper manufacturing process, some waste is obtained in paper mill. This is called paper pulp mill waste or black liquor. This black liquor is used as a fuel.

3.4  GASEOUS FUEL Some gases are obtained naturally and some are produced during some other processes. Natural gas is found nearer to petroleum fields. It is also collected from oil wells. This gas contains methane, ethane, carbon dioxide and carbon monoxide. Coal gas is obtained by carbonisation of coal. Mainly, this gas contains hydrogen, carbon monoxide, methane and ethane. Its calorific value is 5000 kcal/m3 to 6000 kcal/m3. Blast furnace gas and coke oven gas are obtained during preparation of steel in blast furnace and making coke in coke oven respectively.

3.4.1  Blast Furnace Gas It is a byproduct gas obtained during the process of making steel. It is a producer gas (produced during some processes). In a blast furnace, coke, iron ore, manganese, limestone and dolomite are charged for the manufacturing of pig iron. During the processing of pig iron, a hot, dusty, lean and combustible gas is obtained. It contains 10 g to 25 g of dust per newton cubic metre gas. The dust particle size varies from 0.1 mm to 5 mm. The gas is cleaned at gas cleaning plant before using it in tthe boiler. This gas is having low calorific value, i.e., 800 kcal/m3– 900 kcal/m3. The composition of this gas is as follows: Carbon monoxide Hydrogen Carbon dioxide Nitrogen Oxygen

23%–26% 2%–4.5% 12%–16% 51%–57% 0.2%–0.5%

This gas is used in boilers as a fuel in steel industries.

3.4.2  Coke Oven Gas While making coke from coal, this gas is produced. During high temperature carbonisation (heating coal in the absence of air), volatile matter as well as hydrogen is removed from the coal. So, the coke oven gas contains volatile matter and hydrogen.

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The composition of coke oven gas is given below: Carbon dioxide Hydrogen Methane Nitrogen Carbon dioxide Oxygen

7.5%–9% 55%–57% 24%–26% 2%–3% 2.5% 0.3%–0.6%

The calorific value of coke oven gas is higher than that of the blast furnace gas. It is around 5000 kcal/Nm3 to 6000 kcal/Nm3. This gas is used as a fuel in boilers.

3.5  PROXIMATE ANALYSIS AND ULTIMATE ANALYSIS OF FUEL During discussion about the fuel, we came across the terms proximate analysis and ultimate analysis. These two analyses mainly determine the quality of fuel. Proximate analysis of fuel (mainly coal) decides the adoption of coal and designs the coal handling system. Like this, from ultimate analysis, we know the suitability of coal. The calorific value can be calculated from ultimate analysis.

3.5.1  Proximate Analysis In this analysis, the range of constituents like moisture, volatile matter, ash and carbon is measured. These constituents play a major role in designing a boiler. Some important effects of the constituents are discussed here. Moisture:  It is not desirable in fuels. Transporting, handling and storage costs of coal increase, as its weight increases due to the increase in moisture. But heat value does not increase. Also, the heat produced in the furnace is carried out by moisture and goes out as vapour in the exhaust gas. Volatile matter:  Volatile matter in coal has combustible and incombustible gases. Volatile matter in the fuel decides the volume of furnace. Mostly volatile matter contains methane, carbon monoxide, hydrogen, etc. Ash:  It is undesirable in fuels. Presence of ash increases the weight of fuel but does not increase the heating value. Ash is also responsible for clinker formation. At higher temperature, clinker is formed due to the fusion of ash. It mainly contains silica, alumina, iron oxide and magnesium. When ash is heated, it first softens and finally, fuses and melts. The temperature at which ash fuses is called as fusion temperature of ash. Higher fusion temperature of ash indicates better quality of coal. Fusion temperature increases with the increase in alumina and silica contents in ash. Fixed carbon:  Fixed carbon contents of coal is the carbon found after volatile matter is removed. It is determined by removing the mass of volatile matter from the original mass of

Fuel and Combustion 



37

coal sample. This fixed carbon differs from the ultimate carbon contents of coal because some carbon is lost with volatiles.

3.5.2  Ultimate Analysis As discussed earlier, the ultimate analysis decides the heating value of the fuel. In this analysis the range of constituents like carbon, hydrogen, oxygen, sulphur, nitrogen and ash is measured. Each constituent plays a major role in the selection of fuel for a boiler. Carbon, hydrogen and sulphur increase the heat value of the fuel. Nitrogen does not play any role in the heating value. Sulphur adds a little heat value. But, it is undesirable, as it is responsible for clinkering, SOX formation, corrosion and air pollution. Solid fuels are tested by taking samples under specific conditions. The result is expressed on the basis of sample collection. Sampling is normally done on the following basis:

• • • •

As received (ar); includes total moisture (TM) Air dried (ad); includes inherent moisture (IM) Dry basis (db); excludes all moisture Dry ashfree (daf); excludes all moisture and ash

The proximate analysis of any coal, i.e., percentage content of moisture (M), ash (A), volatile matter (VM), fixed carbon (FC) and calorific value (CV) can be expressed on any sampling bases. The conversions are shown in Table 3.1. Table 3.1  Conversions of Different Sampling Bases Multiply By ad db ar

ad – (100 – IM%)/100 (100 – IM%)/(100 – TM%)

db 100/(100 – IM%) – 100/(100 – TM%)

ar (100 – TM%)/(100 – IM%) (100 – TM%)/100 –

3.6  CALORIFIC VALUE OF FUEL Energy is stored in fuel as chemical energy which can be released as heat when oxidation or combustion takes place. It is important to know the quantity of energy stored within a given fuel. This heat value of fuel is known as calorific value of fuel. It is the heat released by complete combustion of unit quantity of that fuel. It is expressed as kilocalorie per kilogramme (kcal/ kg). For gaseous fuel, the calorific value is measured on volumetric basis. It is expressed as kilocalorie per cubic metre (kcal/m3). The calorific value of fuel can be expressed in various forms as discussed here.

3.6.1  Gross Calorific Value (GCV) or Higher Calorific Value (HCV) From the ultimate analysis, it is found that fuels contain carbon, hydrogen, oxygen, and sulphur. These are responsible for calorific value of the fuel.

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Higher calorific value of fuel is given as

HCV = 8080C + 34500 (H2 – O2/8) + 2220 S

where, C, H2, O2 and S represent the weight of carbon, hydrogen, oxygen and sulphur respectively in a unit mass of fuel. When hydrogen present in the fuel oxidises during combustion, it forms H2O. This H2O consumes some heat released by fuel to convert into steam. In this case, heat taken out by H2O is not considered while calculating this calorific value of fuel. So, this value is called as gross calorific value (GCV) or higher calorific value (HCV).

3.6.2  Net Calorific Value or Lower Calorific Value (NCV or LCV) The total heat released by fuel during combustion is not utilised. Some heat is taken out by water vapour which is produced during combustion of hydrogen, as discussed earlier. The heat value obtained by considering the heat taken out by this water vapour is known as net calorific value (NCV) or lower calorific value (LCV). or

LCV = Higher calorific value – Heat taken out by water vapour to convert into steam LCV = HCV – (9H2  586)

Here, 586 is the latent heat of steam in kilocalorie per kilogramme and 9H2 is the amount of steam formation. The energy contents of Indian coal are expressed on the basis of useful heat value (UHV). It is an expression derived from ash and moisture contents for non-caking coals. UHV is defined by the formula UHV = [8900 – 138  (Percentage of ash content + Percentage of moisture content)]

3.6.3  Empirical Relationship of GCV, UHV, and NCV

Useful heat value (UHV) = 8900 – 138(A + MI) Gross calorific value (GCV) = (UHV + 3645 – 75.4 MT)/1.466 Net calorific value (NCV) = GCV – 10.02MT

where, A is percentage of ash, MI is percentage of inherent moisture and MT is the percentage of total moisture.

3.7  COMBUSTION The oxidation of fuel or its chemical combination with oxygen to produces light and heat is called combustion. In fuel, mainly hydrogen and carbon are present. During combustion, this carbon and hydrogen react with oxygen to form carbon dioxide and water vapours. For combustion, following three things are required:

• Fuel • Oxygen • Three Ts

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39

Fuel We have discussed about fuel in previous sections. Mostly, it contains carbon, hydrogen and some amount of oxygen and sulphur. Oxygen For combustion process, oxygen is obtained from air. Air contains 79% nitrogen and 21% oxygen by volume or 77% nitrogen and 23% oxygen by weight. As the Nitrogen percentage is more in air, so large amount of air is required to get the required amount of oxygen. This nitrogen does not take part in combustion but is required to be heated during combustion. To obtain 1 kg of oxygen, we require 4.35 kg of air and for 1 m3 of oxygen, we require 100/21 = 4.76 m3 of air. Three Ts Time, temperature and turbulence are called as three Ts. These three Ts are important for burning process. Time:  For complete combustion of fuel, sufficient time is required. Temperature:  The fuel should be at ignition temperature for burning. Different fuels are having different ignition temperatures. Temperature at which fuel starts to burn is called as ignition temperature. Turbulence:  For complete combustion, the fuel and air should mix properly. By creating turbulence, the fuel can be burnt with less excess air. Turbulence ensures the supply of oxygen to each molecule of the fuel. In a boiler, total air for combustion is divided into two parts. One part is primary air which supports the burning of fuel initially. Second part of the air is called as secondary air. This air is supplied into the boiler furnace to create turbulence and ensure complete combustion. The combination of fuel, heat and oxygen is called as Fire triangle. Absence of anyone from these three can extinguish the fire.

3.7.1  Chemistry of Combustion As discussed earlier, fuel contains some basic element like hydrogen, carbon and sulphur. These elements react with oxygen during burning and heat is released. Some of the important chemical equations connected to combustion are given below:

H2 + ½ O2 C + ½ O2 CO + ½O2 C + O2 S + O2 CH4 + 2O2

     

H2O + 57810 kcal/kmol (28905 kcal/kg) CO + 29430 kcal/kmol (2452 kcal/kg) CO2 + 68220 kcal/kmol (2436 kcal/kg) CO2 + 97650 kcal/kmol (8137 kcal/kg) SO2 + 69800 kcal/kmol (2181 kcal/kg) CO2 + 2H2O + 192400 kcal/kmol (12025 kcal/kg)

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Practical Boiler Operation Engineering and Power Plant

For combustion calculation, kilomole (kmol) is used as a unit. The molecular weight of any substance in kilogrammes represents one kilomole. So 1 kmol of hydrogen has a mass of 2 kg and 1 kmol of carbon has a mass of 12 kg, 1 kmol of methane has a mass of 16 kg. The molecular weights of some substances present in the fuel are given in Table 3.2. Table 3.2  Molecular Weights and Chemical Symbols/Molecular Formula of Some Substances Substance Hydrogen Carbon Sulphur Oxygen Nitrogen Carbon monoxide Methane Ethane Acetylene Ethylene Carbon dioxide Sulphur dioxide Steam or water

Chemical symbol/Molecular formula H C S O N CO CH4 C2H6 C2H2 C2H4 CO2 SO2 H2O

Molecular weight 2 12 32 32 28 28 16 30 28 28 44 64 18

Carbon combines with oxygen to form carbon dioxide, i.e., C + O2  CO2 or or

1 kmol of carbon + 1 kmol of oxygen = 1 kmol of carbon dioxide (by volume) 12 kg of carbon + 32 kg of oxygen = 44 kg of carbon dioxide (by weight) 1 kg of carbon + 8/3 kg of oxygen = 11/3 kg of carbon dioxide

It means 1 kg of carbon requires 8/3 kg of oxygen to produce 11/3 kg of carbon dioxide gas. Also, 8137 kcal of heat is produced during this. Similarly, 1 kg of hydrogen requires 8 kg of oxygen to form 9 kg of water or steam and 1 kg of sulphur requires 1 kg of oxygen to produce 2 kg of sulphur dioxide. If oxygen is already present in the fuel, then the net oxygen required for the combustion of fuel is given by 8/3 C + 8 H2 + S – O2 C, H2, S and O2 is the weight of carbon, hydrogen, sulphur and oxygen respectively in 1 kg of fuel. Air contains 77% nitrogen and 23% oxygen by weight. So, to obtain 1 kg of oxygen from air, the air required is given by

100 = 4.35 kg 23

The air required for combustion of fuel is given by

4.35[(8/3 C + 8H2 + S) – O2]



Fuel and Combustion 

41

This is the theoretical air requirement for 1 kg of fuel. It is also called Stoichiometric combustible mixture. In this case, fuel and air are mixed in such a manner that no excess or deficiency of air and fuel is found. But practically, some excess air is required for complete combustion of fuel. Otherwise, due to shortage of oxygen, fuel may not burn completely.

3.8  SOME IMPORTANT PROPERTIES OF COAL An idea of some important properties of coal helps the coal user to understand the concepts of coal better. As in most of the cases, coal is used as a fuel in the boiler, so it will be helpful to discuss these properties here. Weathering or Slacking Index of Coal When coal is stored in open space exposed to atmosphere, it has a tendency to break into small pieces due to alternate dry and wet conditions. This phenomenon is called as weathering. Weathering or slacking index is an indication of coal size stability when exposed to open atmosphere. Abrasiveness Index The abrasiveness index gives an idea about hardness of coal. This is responsible for wear and tear of equipments of coal handling plant. Grinding Index of Coal Coal is required to be crushed into required sizes to be used in the boiler. In pulverised boiler, the coal is to be grinded. Coal is supposed to have easy grinding nature. Grinding index gives us idea about the relative ease of grinding of coal. Caking Index of Coal Some types of coal soften and swell on heating. The pieces of coal adhere together and form a pasty mass. This is called as caking of coal. Caking index is the measure of binding property of coal. Swelling Index of Coal It is an index which indicates the caking capacity of coal. Coal swells when heated. Coal having more swelling index swells more and hence, having high caking power. Density Density is a measure of how much mass is contained in a given unit volume (density = mass/ volume). It is usually expressed in kilogramme per cubic metre (kg/m3). It is an indication about the weight of given volume of coal. It is required to decide the storage area required to store certain quantity of coal.

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Practical Boiler Operation Engineering and Power Plant

Angle of Repose Coal is stored in heaps at the power plant. The heap height depends on the angle of repose. It is the maximum angle that a heap of coal can form with the horizontal. It is higher in case of higher size coal. This angle plays an important role in the storage of coal. Porosity It describes about the porousness of coal. Liquid can easily enter into highly porous coal. Reactivity of Coal It is defined as the ability of coal to react with oxygen. It is the rate of reaction that determines the time required for combustion. Ash Fusion Temperature Ash fusion temperature gives an indication of the softening and melting behaviour of ash. Coal having low ash fusion temperature is responsible for slagging or fouling in the boiler.

3.9  GRADATION OF COAL Coal is classified based on the degree of impurity, i.e., quantity of inorganic material or ash left after burning. Depending upon the ash content in coal, Indian coal is grouped into seven groups, as shown in Table 3.3. Table 3.3  Different Groups of Coal Found in India Grade

Useful Heat Value (UHV) (kcal/kg) UHV = 8900 – 138(A + M)

Corresponding Ash percentage + Moisture percentage at (60% relative humidity and 40° C) Not exceeding 19.5

Gross Calorific Value (GCV) (kcal/kg) (at 5% moisture level)

A

Exceeding 6200

Exceeding 6454

B

Exceeding 5600 but not exceeding 19.6 to 23.8 6200

Exceeding 6049 but not exceeding 6454

C

Exceeding 4940 but not exceeding 23.9 to 28.6 5600

Exceeding 5597 but not exceeding 6049

D

Exceeding 4200 but not exceeding 28.7 to 34.0 4940

Exceeding 5089 but not exceeding 5597

E

Exceeding 3360 but not exceeding 34.1 to 40.0 4200

Exceeding 4324 but not exceeding 5089

F

Exceeding 2400 but not exceeding 40.1 to 47.0 3360

Exceeding 3865 but not exceeding 4324

G

Exceeding 1300 but not exceeding 47.1 to 55.0 2400

Exceeding 3113 but not exceeding 3865

Fuel and Combustion 



43

3.10  COMBUSTION OF COAL The process of combustion of coal taking place on the grate of a boiler is discussed here. This helps to understand the coal burning process. Total bed of the coal may be divided into four zones, as shown in Figure 3.3. Fresh coal is fed from the top. Primary air from forced draught fan enters from bottom of the fuel bed. It cools down the grate and ash and gets heated while passing over the grate.

Figure 3.3  Combustion of coal on overfeed stoker.

This heated air comes in contact with carbon present in coal at oxidation zone and forms CO2 gas. This CO2 gas further moves up in the bed and reacts again with carbon at reduction zone. When carbon dioxide reacts with carbon, carbon monoxide gas is formed.

CO2 + C = 2CO

This carbon monoxide gas mixes with the volatile matter (removed from the fresh coal) and burns at the furnace. In the furnace, secondary air is supplied to create turbulence and ensure complete combustion. By the same principle, coal burns under feed and travelling grate or chain grate boilers.

3.10.1  Combustion of Pulverised Coal Coal is pulverised in coal mills. This pulverised coal is blown into boiler furnace with the help of hot primary air (Figure 3.4). Secondary air is supplied into the furnace where this coal burns like liquid fuel. First, the volatile matter burns and then, the remaining coal particles. In this case, carbon of the coal reacts with oxygen and carbon dioxide gas is formed.

3.11  COMBUSTION OF LIQUID FUEL Liquid fuel is broken into fine particles by atomisation while admitting into the furnace. Atomisation is done mechanically by means of a rotary disc or by blast of air or steam in

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Practical Boiler Operation Engineering and Power Plant

Figure 3.4  Combustion or pulverised coal.

burner. Air and steam atomisation give better performance. The ratio of the maximum heat input rates to the minimum heat input rates (turn down ratio) is high in this case. In the furnace, this atomised fuel comes in contact with heat and evaporates. Carbon, hydrogen and sulphur are released due to evaporation. These elements react with oxygen and combustion takes place. For burning of oil, primary and secondary air are used to support the flame and complete combustion process respectively. Viscosity of heavy viscous oil is lowered by heating to make it easier to flow in the burners and pipeline.

3.12  EXCESS AIR The theoretical minimum air required for the complete combustion of any fuel. Air contains 79% nitrogen and 21% oxygen by volume. Only oxygen is required for combustion. So, it is required to handle large volume of air to get the required quantity of oxygen. Large quantity of heat is required to heat this total air. So, the efficiency of the system decreases. Also, if less air is supplied, then the complete combustion of combustible materials may not take place. Efficiency decreases in this case also.

Heat loss in flue gas = FGSG (TG – TA)

where FG = flue gas weight per hour SG = specific heat of the flue gas TG = flue gas exit temperature TA = combustion air temperature Stoichiometric combustible mixture is one in which no excess or deficiency exists in either fuel or oxygen. So, it is the chemically correct mixture of fuel and oxygen. But in practice, some excess air is supplied to ensure complete combustion of fuel. The amount of excess air varies with the type of fuel used and firing condition. It may vary from 10% to 40%.

Fuel and Combustion 



45

EXERCISES

1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13.



14. 15. 16. 17. 18. 19.

What do you understand by a fossil fuel? What is the difference between primary and secondary fuel? What are the stages of coal formation? What are the main biomass fuels? Why the calorific value of fuel oil is higher? Name the constituents of fuel measured in proximate analysis. What are the four bases of sample analysis of coal? Why is NCV lesser or than GCV? How are the energy contents of Indian coal expressed normally? What is the empirical relation of GCV and UHV? What are the minimum three things required for combustion? What do you understand by three Ts? What is the formula used to calculate the theoretical air required (in kg) to burn one kilogramme of fuel? What is excess air? What is ash fusion temperature? Why is grinding index of coal important? How is the gradation of coal done? What is turndown ratio? What is a stoichiometric combustible mixture?

Chapter

4

Properties of Steam

4.1  INTRODUCTION Steam is used as a medium for conversion of heat energy into mechanical energy. Heat energy is carried out by steam and converted into mechanical energy at steam turbine. Steam is nothing but the water vapours. When it is pure and dry, it is invisible. Superheated steam behaves like a perfect gas to some extent. In a boiler, steam is generated at constant pressure process. Before discussing the properties of steam, it is required to know how steam is formed at constant pressure.

4.2  FORMATION OF STEAM When water is heated in a vessel at atmospheric temperature, the temperature of the water goes on increasing till the boiling temperature. Initially, the volume of water increases slightly. The boiling temperature of water varies with the vessel pressure at which water is heated. At lower pressure, the boiling temperature is low and at higher pressure, the boiling temperature is high. At atmospheric pressure (1.033 kg/cm2), the boiling temperature of water is 100 °C. Once water reaches its boiling temperature, the temperature of water remains constant there even if heat is added. The heat added does not increase the temperature of water but the water gets converted into steam. The total heat required to raise the temperature of water upto the boiling temperature is called sensible heat (Figure 4.1). Any heat added to water after sensible heat starts steaming of water.

Figure 4.1 46

Properties of Steam 



47

The temperature of water remains constant at boiling temperature till all the water is converted into steam. Initially, the steam formed contains some water particles. This steam is called as wet steam. When heat is added further, all the water is converted into steam and the wet steam becomes dry but still at boiling temperature. This steam is called as dry saturated steam having no water particle. The heat added to water at boiling temperature to convert dry saturated steam is called latent heat of vaporisation. If further heat is added to dry saturated steam, then the temperature of steam starts increasing. This steam is called super heated steam. The heat added to steam is known as heat of superheat. The difference between the temperature of saturated steam and that of the superheated steam is called degree of superheat. If we consider formation of steam at different pressures and draw a graph, this will be like Figure 4.2.

Figure 4.2

As discussed earlier, if the pressure increases, then the boiling temperature of water also increases. Latent heat of vaporisation decreases in this case. It can be seen in the Figure 4.2. The line passing through point N, O and P is called as dry saturated line. Because at these points, the formation process of saturated steam is complete and beyond this line, the steam temperature starts increasing and steam becomes superheated. Region beyond this line is called as superheated region. Line connecting the points A, B and C is called as liquid line. At these points, water is at boiling temperature and further addition of heat starts steaming of water. The region before this line is called as water region. With the increase in vessel pressure, sensible heat increases and the latent heat of evaporation decreases. At point X, the latent heat becomes zero. Here, water is converted into superheated steam directly. This point is called critical point. Here, the pressure is called as critical pressure. This pressure is 225 kg/cm2 or 221.2 bar and the corresponding temperature is 374 °C. At critical point, the liquid line and dry steam line merge. At critical point, both the states of water, i.e., liquid state and gaseous state are possible. We know at triple point all the three states of water, i.e., solid state, liquid state and gaseous state are possible. The combination of pressure and temperature at which water, ice and water vapour can exist is called as triple point and it occurs at 273.16  K (0.01  °C) and a pressure

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of 0.006037 atm. At that point, it is possible to change ice, water or steam by making very small changes in pressure and temperature. From the above discussion, we came across some terms associated with the steam formation. These terms are discussed here in details.

4.3  TERMS ASSOCIATED WITH STEAM In day to day work, a boiler engineer comes across some terms related to steam. So, these are discussed in detail here. Sensible Heat This is the heat required to raise the temperature of one kilogramme of water from zero degree Celsius upto boiling temperature. It is also called as total heat of water. It is represented by HW or hf . 1 kcal heat is required to raise the temperature of 1 kg of water by 1 °C. For example, 1 kg water at 50 °C contains 50 kcal of heat. Latent Heat of Vaporisation This is the heat required to convert one kilogramme of water at its boiling temperature to dry saturated steam at corresponding pressure. While the water receives latent heat, its temperature remains constant. Latent heat is represented by L or hfg. When pressure increases, then the latent heat of vaporisation decreases. At atmospheric pressure, the latent heat of vaporisation of water is 540 kcal/kg. Wet Steam When the total latent heat is added, evaporation is not complete. Steam formed during this period contains water particles. This steam is called as wet steam. Wet steam is visible to eye. Further addition of heat makes this steam dry. Dry Saturated Steam When water absorbs total latent heat, the evaporation is complete. At this point, the steam produced does not contain any water particles. This steam is completely dry and not visible. Dry steam behaves like a perfect gas. In boiler drum, the dry saturated steam is collected for further heating. Dryness Fraction It is the ratio of weight of actual dry steam to the weight of total steam. For example, if W kilogramme of steam contains Wd kilogramme of dry steam, then the dryness fraction is

Dryness fraction =



X =

Weight of dry steam Weight of total steam Wd W

Properties of Steam 



49

Dryness fraction lies between 0 to 1. For dry steam where there is no water particle, dryness fraction is 1. or

Dryness fraction + Wetness fraction = 1 Wetness fraction = 1 – Dryness fraction

Total Heat of Wet Steam It is the quantity of heat required to convert one kilogramme of water at zero degree Celsius at constant pressure to wet steam of certain dryness fraction. It is represented by H or h. If the dryness fraction of wet steam is X, then the total heat of wet steam is given by where Hw = sensible heat of water. L = latent heat of vaporisation X = dryness faraction

H = Hw + XL

For dry steam, dryness fraction is 1, so the total heat of dry steam is

H = Hw + L

Superheated Steam When dry saturated steam is further heated, its temperature increases. This steam is called superheated steam. The volume of superheated steam is more than that of the dry steam at same pressure. Superheated steam has the following advantages:

• Its capacity to do work increases without increasing its pressure, as it contains more heat. • Due to high temperature, thermal efficiency increases. • The superheated steam can be expanded considerably in the turbine before it condenses or becomes wet at the last stage of turbine.

The temperature difference between the superheated steam and the dry saturated steam is termed as degree of superheat. Total Heat of Superheated Steam This is the quantity of heat required to raise the temperature of water at zero degree Celsius to get superheated steam at some desired temperature. It is represented by Hsup or HS. Hsup = Total heat of dry steam + Heat of superheat = Hw + L + Cp(Tsup – tsat) where CP = mean specific heat at constant pressure for superheated steam. Its value normally lies between 0.48 to 0.6 in MKS unit and 1.67 to 2.5 in SI units Tsup = temperature of super heated steam Tsat = temperature of dry saturated steam at a given pressure

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Practical Boiler Operation Engineering and Power Plant

Specific Volume of Steam This is the volume occupied by steam per unit mass at certain pressure. It is expressed in cubic metre per kilogramme (m3/kg). As the pressure of steam increases, its specific volume decreases. Specific volume of wet steam is given by Vwet = XVs



where, X is the dryness fraction and VS is the specific volume of dry steam at a specified pressure. For dry steam, the specific volume is given by Vs. When the temperature of gas increases, its volume increases at constant pressure as per Charles law. As the superheated steam behaves like a perfect gas, we may write as per Charles law Vsup



Tsup

=

Vs Ts

Vsup = Vs ¥

or

Tsup Ts

where Vs = specific volume of dry steam Tsup = superheated steam temperature Ts = saturated steam temperature at a given pressure

4.4  STEAM TABLE Steam is formed at constant pressure in a boiler. For each pressure, values such as saturation temperature, sensible heat, latent heat, total heat of saturated steam and total heat of superheated steam, etc. vary. It is difficult to calculate these values. For convenience, these quantities are experimentally determined and recorded in tabular form. This table is known as steam table. The value of quantities is given for one kilogramme of steam. The table is of two types. One is prepared on the basis of absolute pressure (Table 4.1) and other one is on the basis of temperature (Table 4.2). With the help of this table, calculation can be made easily. The table is made for the saturated water and steam as well as for the superheated steam (Table 4.3). Example of the table is given below for understanding. Table 4.1  Properties of Steam and Water based on Pressure Absolute Temperature Specific Volume Pressure (°C) (m3/kg) 2 (kg/cm ) Steam Water VW Vs 2 4 10

119.6 142.9 179

0.0011 0.0011 0.0011

0.9 0.47 0.198

Enthalpy (kcal/kg)

Specific Entropy (kcal/kg K)

Water Hw

Evaporation L

Steam H

Water Sw

Steam Ss

119.9 143.7 181.3

526.4 510.2 482.1

646.3 653.9 663.4

0.364 0.423 0.509

1.704 1.649 1.575

Properties of Steam 



51

Table 4.2  Properties of Steam and Water based on Temperature Temperature (°C)

10 100 150

Absolute Pressure (kg/cm2) 0.013 1.033 4.854

Specific Volume (m3/kg)

Specific Entropy (kcal/kg K)

Enthalpy (kcal/kg)

Water Vw

Steam Vs

0.001 0.001 0.0011

106.4 1.67 0.393

Water Hw

Evaporation L

10 100.1 151

591.7 539 505

Steam H 601.7 639.1 656

Water Sw

Steam Ss

0.036 0.312 0.44

2.126 1.757 1.633

Table 4.3  Properties of Superheated Steam Temperature (°C)

Pressure = 40 kg/cm2

Pressure = 45 kg/cm2

Pressure = 50 kg/cm2

Vs

H

Ss

Vs

H

Ss

Vs

H

320 500 650

0.063 0.088 0.107

719.6 823 905.1

1.542 1.695 1.792

0.0556 0.078 0.0949

716 821.7 904.3

1.525 1.681 1.779

0.0493 0.07 0.0853

712.5 820.3 903.4

Ss 1.509 1.668 1.767

From the following example, it will be easier to understand the use of steam table. EXAMPLE 4.1  Calculate the total heat of 1 kg of steam at a pressure of 10 kg/cm2 (absolute) when

(i) The steam is wet having dryness fraction of 0.8. (ii) Steam is dry saturated. (iii) The steam is at 200 °C. Considering the specific heat of superheated steam CP as 0.55.

Solution (i) H = Hw + XL In this case, dryness fraction is 0.8. From Table 4.1, it is found that for steam at 10 kg/cm2, Hw = 181.3 and L = 482.1. Putting these values, we get H = 181.3 + 0.8  482.1 = 566.98 kcal

(ii) For dry saturated steam,

H = Hw + L = 181.3 + 482.1 = 663.4 kcal H of dry steam can also be found from steam table directly. (iii) From the steam table, it is found that for steam at 10 kg/cm2, the saturation temperature is 179 °C. Total heat of superheated steam is given by

H + CP(Tsup – Tsat) = 663.4 + 0.55 (200 – 179) = 674.95 kcal

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Practical Boiler Operation Engineering and Power Plant

4.5  MOLLIER DIAGRAM Mollier diagram is the graphical representation of enthalpy H and entropy S. It is sometimes known as the H–S diagram and has an entirely different shape from the T-S diagram. The chart contains a series of constant temperature lines, a series of constant pressure lines, a series of constant moisture or quality lines and a series of constant superheat lines. The Mollier diagram is used by engineers to determine the steam condition.

EXERCISES

1. 2. 3. 4. 5. 6. 7. 8. 9.

Mention the factor(s) on which the boiling temperature of water depends. What is sensible heat? What happens to temperature of water when heat is added after boiling? Define latent heat. What is dry saturated steam? What do you understand by dryness fraction of steam? What is degree of superheat? Define critical point. What changes occur at critical point? Give reason why steam table is used.

Chapter

5

Boiler Feedwater Chemistry

5.1  INTRODUCTION Steam is formed in boiler from feedwater. The water used in boiler is called as boiler feed water. The water which is available from different natural sources such as river, pond, groundwater and sea water, cannot be used directly in boiler as feedwater. Depending upon the sources of water, it contains different impurities. Before using this water in a boiler, these impurities are removed by various methods. Water available from natural resources contains following impurities:

• Undissolved suspended materials like mud, sand, sediment, etc. • Dissolved salts and minerals, e.g. carbonate, bicarbonate, sulphate, silicate and nitrate of calcium/magnesium or potassium • Dissolved gases such as oxygen, carbon dioxide, etc. • Other materials, like acid, oil, etc.

The above impurities can be removed by different methods. Depending upon the type of boiler, feedwater quality is maintained. Permissible levels of impurities are different for different boiler. Feedwater impurities are responsible for corrosion and scale formation in boiler tube. Scale in the tube affects the heat transfer. So, the quality of feedwater is responsible for higher efficiency and life of the boiler.

5.2  REMOVAL OF UNDISSOLVED SUSPENDED SOLID MATERIALS FROM WATER In rainy days, river water usually becomes muddy. It contains insoluble or undissolved suspended solid matter like mud, sediment and sand.. The turbidity of this water is high. Turbidity indicates the presence of insoluble matter in water. These undissolved matters can be removed from water by following three methods:

• Sedimentation • Filtration • Coagulation 53

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Practical Boiler Operation Engineering and Power Plant

5.2.1  Sedimentation Sedimentation is a process in which water is kept standstill in a large settling tank (clarifier tank). Undissolved suspended solids are settled by gravity at the bottom of the tank. The sediment deposited in this process is removed by a slow moving horizontal scrapper. This process is very slow. It takes longer time to settle the suspended solids. Also, total solid cannot be removed completely in this process. Addition of coagulants (like alum) makes settling process faster. Polyelectrolyte is also used for this.

5.2.2  Filtration In filtration process, the water is passed through a filter bed (Figure 5.1) made of porous material (sand, gravel and charcoal). When water passes through this bed, the suspended solid matters are collected in the bed. Clear filter water is collected from the bottom of the filter bed.

Figure 5.1

After some quantity of water passed through the bed, the bed is washed to remove the collected sediments from the bed. After washing, this bed is used again. Normally, during washing cycle, water is passed in the reverse direction of the normal water flow. This is called as backwash. High pressure air from a blower is used to agitate the bed to remove the deposited sediments easily. In demineralisation (DM) plant, pressure filter and activated carbon filter are also used to make the water completely free from suspended solids. In pressure filter, water is passed through gravel and sand bed. When filter bed is packed with suspended particles, differential pressure across the bed increases. High differential pressure indicates that the bed is required to be backwashed. Pressure filter sand bed is agitated with the help of air from a blower to clean the bed thoroughly. Activated carbon or charcoal is used at activated carbon filter. Activated carbon is a black solid substance resembling granular or powdered charcoal. It is extremely porous with a large surface area and typically produced from organic precursors such as bamboo, coconut shells, palm kernel shells, wood chips, sawdust and seeds. Activated carbon reduces organic chemicals, chlorine, lead and unpleasant tastes and odours.

Boiler Feedwater Chemistry 



55

5.2.3  Coagulation In coagulation process, colloidal impurities are removed from water by conglomeration of small colloidal particles to the bigger particles having more mass to settle by gravity. Colloidal particles have same electric charges developed on the surface. So, they repel each other and cannot conglomerate into larger particles. By adding some stimulants, the charge of colloid particles is neutralised and these particles easily conglomerate to form larger particles. These larger particles are called floc which settle down easily by gravity and the stimulant is called coagulant. Aluminum sulphate [Al2(SO4)3], normally known as alum, is a commonly used coagulant. Practically, alum is dosed in the form of solution into the clarifier tank. This makes the settling process faster. A polyelectrolyte is also used for this. After the removal of suspended solids, the water is used as drinking water (chlorination is done to kill bacteria). But this water cannot be used as feedwater for steam generation. Only undissolved solids are removed by the above process. The water still contains dissolved salts and minerals. Presence of these salts and minerals is responsible for hardness of water. More the salts and minerals, more is the hardness. The hardness is classified as permanent hardness and temporary hardness. Bicarbonates of calcium and magnesium are responsible for the temporary hardness of water. Temporary hardness can be avoided by boiling the water. Permanent hardness is due to the presence of chlorides, sulphates and nitrates of sodium, calcium and magnesium. Small quantity of iron, aluminum and manganese salts are also present in water which contribute a little to the water hardness.

5.3  Dissolved salts and minerals In boiler, feedwater salts of calcium and magnesium are mainly responsible for the scale formation. Mostly, natural source water contains silica. Presence of silica is not desirable in feedwater, as it forms hard scale. Sometimes, silica is evaporated and carried out in steam which forms an insoluble deposit on the turbine blade. Mainly, calcium and magnesium salts are present in water in the following form:

• • • • • •

Calcium/Magnesium Calcium/Magnesium Calcium/Magnesium Calcium/Magnesium Calcium/Magnesium Calcium/Magnesium

carbonate (CaCO3/MgCO3) bi-carbonate [Ca(HCO3)2/Mg(HCO3)2] sulphate [CaSO4/MgSO4] chloride [CaCl2/MgCL2] nitrate [Ca(NO3)24H2O/Mg(NO3)26H2O] silicate (CaSiO3/MgSiO3)

The above dissolved salts can be removed from water by treating them with different processes. If these salts are removed from water inside the boiler, the treatment is called internal treatment. If these salts are removed before supplying to the boiler, the treatment is called external treatment.

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Practical Boiler Operation Engineering and Power Plant

5.4  INTERNAL BOILER WATER TREATMENT In internal treatment, chemicals are added in the boiler water. These chemicals react with dissolved salts to convert them into less harmful sludge which can stay in the boiler water without creating any harm to the boiler tube. Later on, this sludge can be removed from the boiler water by blowdown. The main aim of internal treatment is to precipitate the impurities present in the boiler water to get harmless salts or sludge. Following internal treatments are normally carried out in a boiler.

5.4.1  Soda Ash (Sodium Carbonate or Na2CO3) Treatment Soda ash (Na2CO3) treatment is done in smaller size boiler. In this process, soda ash is added into the boiler water which reacts with chlorides and sulphates of magnesium and calcium to form insoluble sludge. CaCl2 + Na2CO3  CaCO3 + 2NaCl MgSO4 + Na2CO3  MgCO3 + Na2SO4 CaSO4 + Na2CO3  CaCO3 + Na2SO4 Sometimes, caustic soda (NaOH) is also used instead of soda ash. At high temperature and pressure, soda ash reacts with water to form free caustic soda.



Na2CO3 + 2H2O  2NaOH + H2O + CO2

Caustic soda reacts in the same way as soda ash. In this case, instead of carbonate, hydroxide is formed. MgSO4 + 2NaOH  Mg(OH)2 + Na2SO4 From the above discussion, it is clear that by treating boiler water with soda ash or caustic soda, sulphates and chlorides of magnesium and calcium are converted into insoluble carbonate and hydroxide sludge. This sludge can then be removed by blowdown.

5.4.2  Phosphate Treatment or High Pressure (HP) Dosing In high pressure boiler, soda ash treatment cannot be used, as it forms caustic soda and increases with the increase in temperature. Hence, it is difficult to maintain pH of the boiler water. Also, at higher pH, solubility of calcium carbonate increases. So, in high pressure boiler, phosphate treatment is preferred as internal treatment. Phosphate treatment is preferred in drum type boiler. Phosphate is added to the boiler water at the boiler drum (Figure 5.2). If it is dosed at feed pipe, it may react with impurities and sludge may be deposited at the feed line. Phosphate dosing is done at boiler drum which is at higher pressure. So, this dosing is called as high pressure (HP) dosing. Phosphate dosing is done in only drum type boiler. In once, through boiler, phosphate treatment is not done. Trisodium phosphate (Na3PO4), disodium phosphate (Na2HPO4) and monosodium phosphate (NaH2PO4) are used in boiler for dosing. These chemicals are also called as orthophosphates. Trisodium phosphate (TSP) is highly alkaline. Disodium phosphate is less alkaline and monosodium phosphate is slightly acidic.



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Figure 5.2  High pressure dosing system.

There may be very negligible quantity of calcium and magnesium salts in feedwater after external treatment. But due to continuous evaporation of water, concentration of these salts increases in the boiler water. Presence of calcium and magnesium salts can form hard scale in the boiler tube. Particularly, calcium (calcium carbonate, calcium sulphate and calcium silicate) is highly prone to scale formation. The precipitation is more at higher boiler water pH (>10.5). Phosphate reacts with calcium and forms less sticky, loose and non-adherent sludge instead of hard scale. This sludge remains in the boiler water in suspended condition and then, removed from the boiler through blowdown. Normally, salts like tricalcium phosphate [Ca3(PO4)2] and hydroxyapatite [Ca10(OH)2(PO4)6] are formed due to the reaction of phosphate with calcium. Magnesium salt is converted into magnesium hydroxide or magnesium silicate (serpentine) due to phosphate treatment. These salts remain in the boiler water in suspended condition without any harm. Depending upon the total dissolved solid (TDS) level of boiler water, blowdown is given. Following are the three types of phosphate treatment:





• Conventional phosphate treatment:  In conventional phosphate treatment, phosphate residual and a hydroxide residual in the boiler water are maintained. Phosphate residual is typically maintained in the range of 20 mg/L–40 mg/L. Hydroxide alkalinity is maintained in the range of 125 mg/L–450 mg/L as CaCO3. This treatment provides an ideal condition for the precipitation of calcium as calcium hydroxyapatite and magnesium as serpentine, as discussed earlier. It also provides a residual of alkalinity to neutralise any acidic contamination. • Coordinated phosphate treatment:  In coordinated phosphate treatment, combination of tri, di and monophosphates are used to achieve an optimum boiler water pH, without any free hydroxide ions. Phosphate concentration is maintained in the boiler water so that calcium scale formation can be eliminated. The concentration of phosphate in boiler water is maintained around 5 mg/L otherwise at higher phosphate concentration, magnesium phosphate is formed which is an objectionable adherent sludge. The ratio of sodium to phosphate ions (Na/PO4) is maintained from 2.85:1 to 3:1 in this case. • Congruent phosphate treatment:  In congruent phosphate treatment, the ratio of sodium to phosphate ions (Na/PO4) is maintained from 2.3:1 to 2.6:1.

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Orthophosphate either in powdered form or in commercial liquid form is put in a tank. Quantity of water is added in such a manner so that continuous dosing can be done. One agitator is provided to steer the solution continuously. The solution is pumped into the boiler drum with the help of a high pressure positive displacement pump. Dosing rate can be adjusted by adjusting the stroke rate of the pump. Phosphate Hide-out It is seen in high pressure boiler, as steaming rate increases (load raises), the level of phosphate residual decreases. When load reduces, then phosphate concentration returns to normal. This phenomenon is termed as phosphate hide-out and is due to reduced solubility of sodium phosphate at temperatures above 250 °C. When phosphate hide-out occurs, there is a risk of permanent scale deposition or evolution of free caustic which may lead to caustic attack.

5.4.3  Colloidal Treatment The insoluble sludge particles formed due to soda ash treatment or phosphate treatment should not stick to each other or to any part of the boiler feedwater system. It should be removed easily by blowdown. Till blowdown, it should circulate with the feed water without any harm. Some organic colloidal materials are added in feedwater to keep this sludge in circulation. The sludge formed due to internal treatment is absorbed onto the surface of the colloidal material and can be easily removed by blowdown. Mostly tannin, lignin and starch are used as a colloidal material.

5.5  External treatment of feedwater Only above discussed internal treatment methods of feedwater are not sufficient in large steam generating plants where evaporation quantity is more. Higher concentration of salts in boiler water produces heavy sludge. So, the feedwater is treated externally to reduce salt concentration. Feedwater is treated externally before sending to the boiler. By using externally treated water, the quality of the boiler water can be maintained with little blowdown. Particularly, in case of once through boiler, the feedwater is treated externally, as no further internal treatment is possible. There are some methods to remove the dissolved salts and minerals externally. Among them, demineralising water treatment and reverse osmosis process are commonly used in steam generating plants. These two methods are discussed in the subsequent sections.

5.5.1 Demineralising (DM) Water Plant Dissolved salts and minerals in water can be removed completely by a series of cation and anion exchangers. This process of demineralisation is quite efficient than the other methods. It is economical too. Most of the steam generating plants uses this process for external treatment of feedwater. Water treatment in this method is done at demineralisation (DM) plant. Water

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produced in this plant is called as DM water. For once through boiler, the DM water parameters are maintained strictly. Colloidal silica cannot be removed at DM plant. Process of Demineralisation As discussed earlier, raw water contains salts of magnesium, calcium and potassium in the form of chlorides, sulphates, nitrates, carbonates, bicarbonates and silicates. These salts are having – – – – cations like Ca+, Mg+ and Na+ and anions like CO3, SO 4, Cl , SiO3, etc. Water free from undissolved suspended solids (from pressure filter and activated carbon filter) passes through a cation exchanger containing a bed of cross-linked polymers called cation resin. This resin contains hydrogen ions (H+). When water passes through the bed, earlier mentioned cations are substituted by these H+ ions of the resin. Water coming out from cation exchanger is acidic in nature which passed through another exchanger, i.e., anion exchanger. Anion exchanger contains another type of resin called as anion resin containing hydroxide ions OH–. When water from the cation passed through anion resin, earlier discussed anions are substituted by OH – ions of the resin.

Figure 5.3  Demineralisation process.

So, the cations of the salts are trapped at cation exchanger and the anions are trapped at the anion exchanger. The water coming out from anion exchanger is free from salts. Another exchanger called as mixed bed containing both cation and anion resin, is used to trap any slippage salts from the cation and anion exchangers. After flowing of certain quantity of water in the exchangers, bed resin gets exhausted. It cannot trap further cations or anions. In this condition, regeneration of bed is required. Cation resin is regenerated by hydrochloric acid (HCl) or sulphuric acid (H2SO4) and anion resin is regenerated by caustic soda. Normal operation and regeneration of cation and anion exchangers are discussed in separate sections. Two types of cation exchanger are used. These are given below:

• Strong acid cation exchanger (SAC) • Weak acid cation exchanger (WAC)

SAC can remove all the cations associated with strong acids like sulphuric acid, hydrochloric acid, nitric acid, etc. as well as with weak acids also. Whereas, WAC can remove cations associated with weak acids only like silicic acid and organic acid.

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Like this, two types of anion exchangers are used. These are as follows:

• Strong base anion exchanger (SBA) • Weak base anion exchanger (WBA)

SBA can remove all the anions associated with strong and weak acids. Whereas, WBA can remove the anions of strong acids only. In between the cation and anion exchangers, there is a degasifier unit. Here, carbonates and bicarbonates are removed. Depending upon the water quality requirement and salt concentration (ionic load) in the raw water, different combinations of cation and anion exchangers are used. Sometimes, SAC and WAC exchangers along with SBA and WBA exchangers are used. Some plant uses SAC along with SBA exchanger only. A simple DM water flow diagram is shown in Figure 5.3. Cation Exchanger Cation exchanger contains bed of cation resin. As discussed earlier, resin is a cross-linked polymers. The chemical formula of cation resin is given as R–H+. Here, R– is the complicated chemical composition of the resin. It will be easier to remember the resin with this formula. When raw water passes through this resin bed, cations of the salts like Ca+, Mg+ and Na+ are substituted by H+ ions of the resin. So, the salts of calcium and magnesium are converted into different acids (as mentioned below in Table 5.1) and mixed with water. So, the water coming out from cation exchanger is acidic. The cations are trapped at the resin bed. Table 5.1  Different Salts of Calcium and Magnesium–Their Conversion and Equations Salts

Converted to

Equation

– – Ca CO3 + R–H+ = Ca+R– + H2+CO3 – – Mg+ SO4 + R–H+ = Mg+R– + H2+SO4 – Ca+Cl2 + R–H+ = Ca+R– + H+Cl– +

Carbonates/Bicarbonates

Carbonic acid

Sulphates

Sulphuric acid

Chlorides

Hydrochloric acid

Nitrates

Nitric acid

Ca+(NO3)2 + R–H+ = Ca+R– + H+NO3

Silicates

Silicic acid

Ca+SiO3 + R–H+ = Ca+R– + H2+SiO3

–

–

–

–

As the cations are trapped at the resin, so it is exhausted after flow of some quantity of water through it. The resin cannot absorb more cations. So, it is required to regenerate the resin. This process is called as regeneration. Regeneration:  Before regeneration of resin, bed is backwashed (water flow is in reverse direction of the normal flow through the bed and drained out) for some time to wash the resin completely. Backwash also removes resin fines and filtered particles from the inter space of resin bed. This helps in efficient regeneration. After backwashing hydrochloric acid or sulphuric acid is injected into the resin bed. Normally 2% to 6% acid for SAC and 0.5% to 0.7% acid for WAC with 30% concentration is injected to the water stream which flows through the resin bed in reverse direction of the normal water

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flow and drained out. This method is called as counter flow regeneration. Sometimes, co-flow method is also adopted where regeneration is done in the same direction of the normal water flow. DM water or degassed water is used for regeneration. During regeneration, less flow is maintained. Hydrochloric acid or sulphuric acid reacts with exhausted resin in the following manner to recharge the resin again.

–

Ca+R– + H+Cl– = Ca+Cl2 + R–H+ + – – Mg+R– + H2 SO4 = Mg+SO4 + R–H+

It should be noted that Ca+R– and Mg+R– are the exhausted resin due to absorption of cations in cation exchanger during normal operation and R–H+ is the charged cation resin, as discussed earlier. Either hydrochloric acid or sulphuric acid can be used for this purpose. Remaining CaCl2 and MgSO4 are drained out with water. Certain quantity of acid is permitted to flow for some duration during regeneration. This duration and quantity of acid depend upon the bed depth and resin quantity. After acid injection is completed, water flow is continued for some time to rinse the bed. As during regeneration, less water flows, so this rinsing is called as slow rinse. Slow rinse is continued for some time. After slow rinse, raw water at normal flow rate and at normal direction is passed through the regenerated bed. But this water is drained out to rinse the bed thoroughly. This rinsing method is called as fast rinse. The water quality is checked for non-availability of hardness. Fast rinse is continued for some time and then, drain valve is closed. Now, the exchanger is fully charged and ready for further production of DM water. After regeneration of the exchanger for some number of times, the bed is regenerated with double quantity of acid. This is called as double regeneration. Degasser As stated in earlier section, when carbonates and bicarbonates are passed through the cation exchanger, carbonic acid (H2CO3) is formed. Carbonic acid is a weak acid. Soft drinks available in the market contain carbonic acid. This can easily be broken into water and carbon dioxide gas.

H2CO3  H2O + CO2

So, carbon dioxide gas is released when we open a soft drink bottle. Degasser is used to remove carbon dioxide gas from the cataionised water during DM water production process. In degasser unit, water coming out from the cation exchanger is sprayed from top of the degasser tower to increase its surface contact area, as shown in Figure 5.4. Low pressure air with the help of a blower called as degasser blower is blown from bottom of the column. By this process, carbonic acid breaks easily and carbon dioxide gas is liberated. This carbon dioxide gas is vented along with low pressure air at the top of the degasser tower. Degassed water is collected at a tank called as degasser tank. As told earlier, this degassed water is then passed through the anion exchanger. Also, this degassed water is used for the regeneration of cation exchanger. Normally, degasser tank is placed at higher elevation. It has some merits. Firstly, the carbon dioxide gas is vented at higher elevation. Secondly, by placing the degasser unit at higher

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Figure 5.4  Degasser

elevation, water can flow to the subsequent exchangers (anion and mixed bed) by gravity. So, further pumping is not required. Only one pump can be used to pump the water to the degasser through cation exchanger. Then, by gravity, water can flow through the anion exchanger and mixed bed. Degasser unit reduces load on anion exchanger. Anion Exchanger The water which is coming out from the degasser unit passes through anion exchanger. This exchanger contains another type of resin called as anion resin which is represented by R+OH–. The water coming out from the cation exchanger is acidic. Carbonic acid is eliminated at degasser. So, other acids are still present in this water. Following reactions take place while cationised water passes through the anion resin.

H2+ SO4– + R+OH–  R+SO4– + H2O H+Cl– + R+OH–  R+Cl– + H2O H2+ SiO3– + R+OH–  R+SiO3– + H2O

It can be noted that anions of the salts are absorbed by anion resin. H+ ion substituted with the cations of salts at cation exchanger reacts with OH– ions of the resin to form H2O. Like cation resin, anion resin is also exhausted after passing certain amount of cationised water. Further absorption of anions is not possible after exhaust of resin. In this condition, regeneration is required. Regeneration:  Like cation bed, anion bed is also backwashed before regeneration. For the regeneration of anion resin, caustic soda (NaOH) is used. Caustic soda, either flake form or liquid form can be used. 4% to 5% caustic solution is used. This caustic solution is injected into the water steam and passed through the resin bed either in co-flow or counter flow direction and drained out. Only DM water is used for regeneration in this case. Caustic soda reacts with exhausted anion resin (as below) to regenerate the resin.

R+SO4– + Na+OH–  Na+SO4– + R+OH–

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R+Cl– + Na+OH–  Na+Cl– + R+OH– R+SiO3– + Na+OH–  Na+SiO3– + R+OH–

It can be noted that R+SO4–, R+Cl–, R+SiO3–, etc. are the exhausted resin and after regeneration, these are converted into original resin(R+OH–). Remaining salts are drained out with water. The resin bed is slow rinsed like cation exchanger for some time and then, fast rinsed. The conductivity of the water is measured before putting the bed in service. Mixed Bed Exchanger Mainly, mixed bed is used to arrest silica slippage from the water coming out of the anion exchanger. Both cation and anion resins are used in this exchanger. Like other exchangers, this exchanger also requires regeneration after some flow of water. But as the bed contains both cation and anion resins, so regeneration process is different from the other exchangers. Regeneration is carried out in following steps: Backwashing and bed separation:  Resin bed is backwashed to remove any filtered particles. This backwashing also helps bed separation. Mixed bed contains two types of resin. Bed separation is required for regeneration, as cation and anion resins require acid and alkali respectively for regeneration. Cation resin is heavier than the anion resin. So, cation resin settles down and anion resin moves up during backwashing as the bed becomes fluidised. Acid injection:  Regeneration after the separation of bed is easier. Cation resin is settled at the lower portion of the bed. So, acid is injected at the middle interface collector of the bed and drained at the bottom after passing through the cation resin bed. Alkali injection:  As the anion resin is lighter, so it is settled at the top portion of the bed. To regenerate this resin, alkali is injected from top of the bed and drained from the middle interface collector. Rinsing:  Both the beds are rinsed to wash out the remaining acid or alkali. Mixing of bed:  Both the resins are mixed thoroughly with the help of high pressure air. Air is introduced from the bottom. This air agitates the bed and resins are mixed uniformly. Final rinsing:  After mixing of bed, water from the anion exchanger is passed through the bed with full flow for some time and then, drained out. Conductivity and silica are checked and the exchanger is put into service if it is found all right. To maintain pH of DM water, morpholine dosing is done. The water coming out of the mixed bed is stored in a DM storage tank and used in the boiler.

5.5.2  Reverse Osmosis Plant Reverse osmosis is a process in which much pure water suitable for boiler feedwater can be obtained. As told earlier, in reverse osmosis process, reactive as well as colloidal silica can be removed. So, this water is more suitable for high pressure boilers. We will discuss step by step about the production process of reverse osmosis (RO) plant in the subsequent sections.

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Reverse Osmosis Process In osmosis process, liquid from an area of low salt concentration moves naturally through a semi-permeable membrane to an area of high salt concentration when no external pressure is applied. The flow can be reversed by applying external pressure on the high concentration side (Figure 5.5). This phenomenon is called as reverse osmosis. This process is the reverse of osmosis process. In reverse osmosis, dissolved salts are separated from the water by forcing the water through a semi-permeable membrane under high pressure.

Figure 5.5  Reverse osmosis.

A semi-permeable membrane is a membrane that passes smaller size atoms or molecules. Pure water passes through it. But the contaminants that are too large cannot pass through the tiny pores in the membrane. Pure water passes through the membrane and the dissolved salts remain behind on the surface of the membrane. The membrane would quickly choke up with the dissolved minerals that it traps from the water. So, a part of the water fed into the system is used to flush them away to increase the life and effectiveness of the membrane. The pure water obtained is called as permeate and the rejected water is called as concentrate. Pretreatment Membrance of RO system is highly prone to fouling. To get more useful life of the plant, the water is pretreated before passing through RO membrane. There are various pretreatment configurations used in a reverse osmosis plant, as shown in Figure 5.6. Various physical and chemical water treatment processes are used at upstream of the reverse osmosis membrane. Details about the process are discussed below: Sand filter and activated carbon filter:  As discussed earlier, these filters are used to separate suspended particles from raw water. Backwashing of these filters removes these particles from the bed. Raw water pumps are used to pump water through these filters. Ultrafiltration unit:  Membrane type modular ultrafiltration units are mostly used at RO plants. Ultrafiltration is a technique used to remove very fine colloidal particles and macromolecules from the water. It separates particles on the basis of their molecular size. Pore diameters of ultrafiltration membranes are in the range of 0.001 µ to 0.02 µ. Molecules having diameter smaller than the pore size of the membrane pass through the membrane and known as permeate.



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Normally 90% permeate is obtained from the ultrafiltration unit and 10% rejected water is drained out to the pit tank. Average life of this membrane unit is 3–5 years. In order to remove built-up particles from the membrane surface, the module needs to be backwashed regularly. To restrict fouling of ultrafiltration membrane, backwashing and flushing are carried out. This cycle is initiated automatically either by a timer or differential pressure across the membrane. After several filtration and backwash cycles, some ingredients of the feedwater may remain on the membrane surface and form a fouling layer. This layer is removed effectively by adding cleaning chemicals to the backwash water or by chemically enhanced backwash cycles (CEB). In CEB, during specific backwash sequences, chemical dosing pumps are operated to dose cleaning chemicals to the backwash water. Sodium hypochlorite (NaOCl), hydrochloric acid (HCl) and caustic soda (NaOH) are used for CEB. A chemically enhanced backwash (CEB) sequence maximizes membrane life and minimizes downtime due to system fouling.

Figure 5.6  RO plant flow diagram.

Sometimes, clean in place (CIP) is performed to clean the ultrafiltration membrane. This is carried out as and when required. The frequency of CIP depends upon the quality of water and is normally required in 1–3 months. The water coming out of ultrafiltration unit is stored in a tank which is then pumped by RO feed pump. At the outlet of ultrafiltration unit, turbidity, silt density index and pH value are measured. Here, silt density index (SDI) is an important test carried out to measure suspended

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solids concentration in the RO  feedwater.  SDI is measured  to monitor the performance of pretreatment equipment and indicates the fouling potential of a reverse osmosis feedwater. The silt density index (SDI) should be maintained at less than three. RO Unit Modular RO membrane units are used at RO plant. A reverse osmosis  membrane is a semipermeable material, i.e., a material through which water passes while other substances cannot. RO membranes (Figure 5.7) are made of a thin, porous material constructed of organic polymer (cellulose acetate, polyamide and charged polysulphone). The average life of this membrane unit is 3–5 years.

Figure 5.7

Before starting up an RO system, it is to be ensured that all pretreatment systems are working perfectly as per their specifications. Ultrafiltered water is pumped by a high pressure RO feed pump. Water passes through a 5 µ cartridge filter and then, through RO membrane. Pure water coming out from RO unit is called as permeate. Around 80% water is recovered as permeate and rest 20% is rejected. TDS of reject water is around 2000 mg/L. Chemical treatment is done at upstream water to eliminate scaling, corrosion and biological fouling of the RO membranes. Biocides and antiscalants are used either on line or as part of a cleaning program to control unwanted membrane fouling  and biofouling in  reverse osmosis membranes. When used as an on-line treatment, the biocides and antiscalants  are dosed prior to the RO system to control biogrowth in the membranes. In case of polyamide membrane, free chlorine level must be 0.0 ppm. In this case, sodium metabisulfite (SMBS) is dosed. Backwashing of membrane is regularly done with permeate water. During operation, fouling on membrane surface takes place which reduces the permeate flow. Differential pressure increases and higher feed pressure is required to maintain the output. Membrane cleaning is an important activity of any reverse osmosis plant. It is essential to clean membranes at an early stage of fouling, as it is difficult to clean excessively fouled membranes. To clean the membrane periodically, clean in place method is adopted like ultrafiltration unit.

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As salt concentration in reject water is more which exceeds the solubility during operation, it should be rinsed properly prior to any shutdown (>15 minutes). Rinsing of the membranes with permeate water before shutdown also removes colloids and bacteria from the membrane surface.

5.6  REMOVAL OF DISSOLVED GASES FROM WATER From the discussions so far, we understand how the suspended undissolved particles and dissolved salts are removed from water by various methods. Some gases like oxygen, carbon dioxide, nitrogen, etc. are present in water in dissolved condition. Particularly, the presence of oxygen is highly objectionable in boiler feedwater, as oxygen is responsible for corrosion of boiler tube. For removal of dissolved gases, deaeration is done in an equipment called deaerator. Chemical dosing (hydrazine) is done in the feedwater to remove oxygen. This is called as low pressure (LP) dosing.

5.6.1  Low Pressure (LP) Dosing Deaerator is used for degasification or to remove dissolved gasses, mainly CO2 and oxygen. Another process called as deoxygenation is adopted for removal of oxygen by chemical techniques. Chemical such as sodium sulphite (Na2SO3) and hydrazine (N2H4) is used for deoxygenation. Presence of dissolved oxygen in feedwater is highly objectionable, as it acts as depolariser and is responsible for the corrosion of metal tube. O2 + 4e– + 2H2O  4OH– Fe2+ + 2OH–  Fe(OH)2



Sodium sulphite reacts with oxygen present in the feedwater and forms sodium sulphate.



2Na2SO3 + O2  2Na2SO4

Sulphite is an inorganic oxygen scavenger. It increases dissolved solids of the feedwater which can be controlled by blowdown. If feedwater temperature is high, less sulphite is required. Hydrazine is preferred by most of the boiler engineers, as no solid residue is formed in this process. Hydrazine is available as hydrazine hydrate (N2H4. xH2O), hydrazine hydrochloride (N2H4.HCl) and hydrazine sulphate (N2H4.H2SO4) form. The chemical reaction of hydrazine with dissolved oxygen in feedwater is given as



N2H4 + O2  N2 + 2H2O

Nitrogen gas is formed in this reaction which is not harmful. Hydrazine reacts with oxygen at temperature greater than 100 °C and pH more than seven. So, normally, hydrazine is added to the feedwater in the deaerator storage tank. Some engineers prefer to add it at the boiler feed pump suction. A set of dosing pump is required to dose hydrazine. As the dosing is done at the low pressure side of the feedwater, so it is called as low pressure (LP) dosing. The pipeline and the dosing tank are made of stainless steel.

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It is ensured that there is no dissolved oxygen in the feedwater when hydrazine is traced in it. So, the presence of hydrazine in boiler water is tested regularly.

5.7  SOME PARAMETERS OF BOILER FEEDWATER Boiler feedwater plays a vital role in scale formation and durability of boiler tube. This feedwater is tested regularly in laboratory to know about the quality of feedwater. Some important parameters of feedwater are discussed below. From these parameters one can easily understand about feedwater quality. Turbidity Pure water free from suspended solids is colourless. Cleanliness of water decreases when water is contaminated with any suspended insoluble particle like mud, sand, sediment, etc. Cleanliness of water is measured as turbidity. Less turbidity means clear water and high turbidity indicates that water is contaminated. The unit of turbidity is normal turbidity unit (NTU). Turbidity decreases when filtration is perfect. pH Value pH value of the water indicates whether the water is acidic or alkaline. It plays important role in corrosion. pH value of different solution varies from 0 to 14. It is derived from the amount of hydrogen ion present in the solution. pH value is the logarithm of reciprocal of the hydrogen ion concentration. Pure water contains 10–7 g of hydrogen ion per litre. So, its pH is 7. pH 7 indicates normal solution. pH more than 7 is alkaline and less than 7 is acidic. It is clear that in alkaline solution, hydrogen ion concentration is less and in case of acidic solution, hydrogen ion concentration is more. Pure alkaline solution is having 10–14 g of hydrogen ion per litre. So, its pH is 14. Pure acidic solution is having 1 (100) g of hydrogen ion per litre. So, its pH is 0. As per the law of mass action, in mass dissociation, H+  OH– = 10–14 at 20 °C. So, if hydrogen ion concentration is more in the solution, then hydroxyl (OH–) ion concentration reduces. If a solution has H+ concentration as 10–10, then OH– concentration will be 10–4. So, the alkaline solution has lesser hydrogen ion concentration and hence, higher hydroxyl ion concentration. pH of the solution depends on whether hydrogen or hydroxyl ions predominate. As the pH value is logarithmic function, so pH 8, 9 and 10 are respectively 10, 100 or 1000 times more alkaline than the pH value 7. Hardness Hardness of the water is due to the presence of calcium and magnesium salts, as discussed earlier. More the salt in the water, more is the hardness. Sometimes, the presence of aluminium and manganese contributes to the hardness. These salts are deposited in boiler tube as hard scale which disturbs the heat transfer and leads to tube failure. Hardness is of two types, i.e., carbonate and non-carbonate hardness. The unit of hardness is milligrame per litre (mg/L) or parts per million (ppm).

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Total Dissolved Solids (TDS) Total dissolved solid is due to the presence of dissolved non-volatile substances in water. It is an important parameter to know about the condition of boiler water. If TDS of the boiler water is more, then blowdown is given to reduce this. By giving blow down, some fresh water with little or no TDS can be introduced into the system to balance TDS. The unit of TDS is milligramme per litre (mg/L) or parts per million (ppm). Conductivity If TDS of the water increases, then its specific electrical conductance or conductivity also increases. Pure water has zero conductance. By measuring conductivity, one can also know about the TDS of the water. The unit of conductivity is microsiemens per centimetre (μScm–1). To calculate TDS of water, the conductivity is multiplied by a conversion factor. The conversion factor depends on the chemical composition of the TDS and may vary between 0.54 – 0.96. A value of 0.67 is commonly used as an approximation if the actual factor is not known. Alkanity The alkanity of water is due to the presence of HCO–3, CO32– and OH– ions. SiO–23 and PO–3 4 ions also contribute towards alkanity. The unit of alkanity is milligramme per litre (mg/L) or parts per million (ppm). According to the presence of above ions, the alkanity is classified as follows:

• Carbonate (CO2– 3 ) alkanity denoted by Ac • Bicarbonate (HCO3–) alkanity denoted by Ab • Hydrate (OH –) alkanity denoted by Ah

To know about the alkanity, two types of alkanity are measured in laboratory. These are as follows:

• •

M-alkanity M or methyl orange alkanity M-alkanity is called as total alkanity. M-alkanity = Ac + Ab + Ah P-alkanity P or phenolphthalein alkanity P-alkanity = Ah + 1/2 Ac

Some cases are given here to know the exact alkanity of water. Case 1:  When P = 0 (pH  8.2), M is called as bicarbonate alkanity. Case 2:  When P = M, M is called as hydroxide alkanity. Case 3:  When 2P < M (suitable for boiler water), there is no OH– concentration, CO2– 3 concentration is equal to 2P and HCO–3 concentration is M–2P. Case 4:  When 2P > M, OH– concentration is present and equal to 2P – M, CO–2 3 concentration – is equal to 2(M – P) and HCO3 is zero. – – Case 5:  When 2P = M, CO2– 3 concentration is 2P. Here, OH concentration and HCO3 concentration are nil.

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Silica Silica can exist in following three physical/chemical forms:

• Dissolved silica (monomer, soluble/reactive) • Colloidal silica (polymeric, unreactive) • Particulate silica (granular, suspended)

Silica in dissolved state is called as reactive silica. This is volatile and easily carried over by steam and deposited at turbine blade where temperature and pressure of the steam drop. This silica is not desirable in boiler water. Silica concentration in boiler water can be controlled by giving blowdown. At DM plant, only reactive silica is removed. Colloidal silica is called as non reactive silica. At RO plant, colloidal silica along with reactive silica can be removed. Iron and Copper In boiler feedwater, presence of iron (as Fe2O3) and copper is not desirable. For different boilers, the higher limits of these two are specified. Oil Presence of oil in feedwater is responsible for foaming. So, oil should not be present in the feedwater. Dissolved Oxygen If oxygen is present in feedwater, then it accelerates corrosion of the boiler tube. So, to make the feedwater free from dissolved oxygen, oxygen scavenger is used. Earlier, sodium sulphite was used for this purpose.

2Na2SO2 + 2O2  2Na2SO4



But nowadays, hydrazine is widely used for oxygen scavenging.

N2H4 + O2  2H2O + N2



It is a common practice to have traceable quantity of hydrazine in feedwater to eliminate the chances of presence of oxygen in the feedwater. Parameter limits of different water used in power plant is given in Table 5.2. Table 5.2  Parameter Limits of Various Water used in Power Plant Parameter

Unit

High Pressure Boiler

Low Pressure Boiler

Turbine Condensate

DM Water

Cooling Water

9.5–10.5

8.5–9.5

6.5–7.5

7.5–8.5

Feed Water

Boiler Water

Feed Water

Boiler Water

9–9.4

9.4–9.7

8.5–9.5

pH

 

Conductivity

µs/cm

0.2 maximum

100 maximum

10 maximum

200 maximum

5 maximum

0.15 maximum

2500 maximum

Silica

mg/L or 0.02 ppm maximum

0.5 maximum

0.02 maximum

10 maximum

0.02 maximum

0.02 maximum

100 maximum (Contd.)

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Table 5.2  Parameter Limits of Various Water used in Power Plant (Contd.) Parameter

Unit

High Pressure Boiler Feed Water

Low Pressure Boiler

Boiler Water

Feed Water

Boiler Water

Turbine Condensate

DM Water

Cooling Water

P-alkanity

mg/L or − ppm

−

5 maximum

15 maximum

−

−

−

M-alkanity

mg/L or − ppm

−

10 maximum

35 maximum

−

−

−

Iron as Fe

mg/L or 0.01 ppm maximum

0.05 maximum

0.02 maximum

0.5 maximum

−

−

−

Dissolved Oxygen

mg/L or 0.007 ppm maximum

−

0.01 maximum

−

−

−

−

Total Hardness

mg/L or Nil ppm

Nil

Nil

Nil

Nil

Nil

1200

Calcium Hardness

mg/L or − ppm

−

−

−

−

−

800

Total Dissolved Solids Hydrazine

mg/L or − ppm

50 maximum

−

120 maximum

−

−

1500 maximum

mg/L or 0.01-0.02 ppm

−

0.5 maximum

−

−

−

−

Phosphate

mg/L or − ppm

5–10

−

15–30

−

−

−

Exercises

1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15.

What are the methods used to remove undissolved suspended solid particles from water? Name the chemical used for coagulation. What do you understand by dissolved salts? How can the dissolved salts be removed? What are the internal treatment methods? What is HP dosing? Name the chemical used for this. Why is phosphate dosing done at the drum of the boiler? What factor(s) are responsible depending upon which blowdown is given? What is phosphate hide out? To which treatment does demineralisation belong–internal or external? Where are the cations of salts trapped in a DM plant? Where are the anion of salt trapped in a DM plant? What is the function of a cation exchanger? Why is the water coming out from a cation exchanger acidic? Which chemical is used for the regeneration of cation exchanger?

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16. 17. 18. 19. 20. 21. 22. 23. 24. 25. 26. 27. 28. 29. 30. 31. 32. 33. 34. 35. 36. 37. 38. 39. 40. 41. 42.

How is a cation exchanger regenerated? Define co-flow and counter flow regeneration. What is the function of a degasser? Why is a degasser placed at higher elevation? What is the function of an anion exchanger? How is an anion exchanger regenerated? Which chemical is used for the regeneration of anion exchanger? What is the function of mixed bed exchanger? How is mixed bed exchanger regenerated? Which type(s) of silica can be removed by a reverse osmosis plant? Why is ultrafiltration unit used at RO plant? Which water is called as permeate? Which chemicals are used for CEB in RO plant? What is clean in place? What is SDI and what is its permissible limit in a RO plant? Why is sodium metabisulphite (SMBS) dosed? What are the methods adopted to remove dissolved gases from the boiler water? Why is LP dosing done? Name the chemical used for this. How is the TDS level of boiler water is controlled? On what factor(s) does the hardness of water mainly depend? What is indicated by pH of water? What is the relation between TDS and conductivity? Define P-alkanity and M-alakanity. Mention the OH– concentration in boiler water when 2P < M? What are the three forms in which silica is present in water? Which type of silica cannot be removed in a DM plant—reactive or colloidal? Which chemical is used to remove oxygen from the boiler feedwater?

Chapter

6

Introduction to Boiler

6.1  INTRODUCTION Boiler is a closed vessel in which the heat produced by combustion of fuel is transferred to feedwater to generate steam. Boiler is a heat exchanger. As per Indian boiler Act-1923, boiler means any closed vessel exceeding 22.75 L in capacity which is used expressly for generating steam under pressure and includes any mounting or other fitting attached to such vessel which is wholly or partially under pressure when steam is shut off. For effective heat transfer, heat transfer units are arranged in different ways. The requirement of high pressure and high temperature steam in today’s power houses to drive steam turbine has made the boiler design complicated. High capacity boilers are operated above critical pressure range (221.2 bar). These boilers are called as supercritical boilers. There are different types of boilers depending upon their design features. These are discussed in subsequent sections. A good boiler should have some essential qualities. These are as follows:

• • • • • • •

Capable to meet large load fluctuations Fuel efficient or to produce maximum steam with minimum fuel consumption Able to quick start-up Easy for maintenance and inspection Occupy less floor space Less friction loss in water and flue gas circuit Require little attention for operation and maintenance

A boiler mainly contains following systems.:

• • • • • •

Feed water system Steam system Air system Flue gas system Fuel handling system Ash handling system

All these above systems are discussed separately in the subsequent chapters. For satisfactory functioning of the boiler, there are boiler mountings and accessories. 73

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Boiler Mountings Fittings on a boiler which are required for its safe operation are called mountings. These are given below:

• • • • • • • • • •

Safety valve Water level sight glass (gauge glass) Pressure gauge Blowdown valve Main steam stop valve Feedwater check valve (NRV) Fusible plug (used in fire tube boiler) Air vent Start-up vent Manhole

Boiler Accessories The devices which are used in a boiler as an integral part and help to run the boiler efficiently are called boiler accessories. These are given below:

• • • • • • • • • • •

Superheater Desuperheater Economiser Air heater Soot blower Feed pump Induced draught (ID) and Forced draught (FD) fans Ash removal system Fuel supply system Dosing system Deaerator

All the above mountings and accessories are discussed in detail in further chapters. Before we proceed further it will be helpful to know how steam is produced in a normal boiler.

6.2  STEAM GENERATION IN A BOILER As discussed earlier, fuel is burnt in a boiler to get heat energy which is converted from the chemical energy stored in the fuel. This heat energy is utilised to produce steam from the feedwater. The fuel is fired in the furnace of a boiler. Different fuels are used in different boilers and accordingly, the furnace is designed. Water tubes are arranged around the furnace and flue gas path. Water tube arrangement made around the furnace is called water wall. Feedwater is circulated in these tubes.

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Water tubes are arranged in a closed system. Cold water comes to the tube from a boiler drum. Then, this water is circulated back to the drum after absorbing heat. Due to difference in density, water circulates in these tubes naturally (Figure 6.1).

Figure 6.1  Natural circulation of water in a boiler tube.

The force causing circulation is given by

F = rCH1 – rHH2

where rC = density of cold water rH = density of hot water H1 and H2 are the heights of water and steam respectively. In some cases, forced circulation is done by adding a pump. During circulation of water in the tube, steam is generated and collected at the steam drum. This steam is saturated steam corresponding to the boiler drum pressure. This steam is further heated to get superheated steam. Boiler drum is filled with fresh feedwater. The feedwater before entering into drum is heated at the economiser which is placed at the flue gas path. Most of the heat of flue gas is utilised inside the boiler. Still, considerable amount of heat energy is available in it. This heat is utilised in economiser to heat up the feedwater. For burning of fuel, the required oxygen is obtained from atmospheric air. Air required in boiler furnace for combustion is supplied by forced draught (FD) fan. This air is heated at air heater before sent into the furnace. If cold air is used, then there will be loss of energy. Air heater is placed at the flue gas path after economiser. Air heater is a heat exchanger which exchanges the heat of flue gas with the cold air. By heating the air, burning of fuel is easier and the loss of energy is minimised. If hot flue gas would not be used to heat up the feedwater at economiser and the air at air heater, then it would be escaped to the atmosphere. Finally, the flue gas passes through electrostatic precipitator (ESP) and exhausted to atmosphere through chimney. At ESP, the dust particles in the flue gas are trapped and clean gas is escaped to the atmosphere. ESP is not required where clean fuel like oil and gas is used. Fuel is stored in the fuel storage area. From there, fuel is fed to the boiler as per the requirement. Ash which is produced in the boiler due to combustion of solid fuel is collected

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at the boiler bottom. Also, ash is collected from the ESP. This ash is then disposed of with the help of suitable ash handling system. The basic arrangement of all six systems are shown in Figure 6.2.

Figure 6.2  Basic arrangement of different systems in a boiler.

All the boilers are not necessarily having all these systems. For example, waste heat recovery boiler does not have fuel handling system. The above figure is meant to have an idea about the functioning of a boiler.

6.3  DIFFERENT TYPES OF BOILER Different types of boilers are used for steam generation. Boilers are classified depending upon the fuel used, pressure of steam, mode of flow of heat carrying substance etc. Mostly boilers are classified on the basis of the following considerations:

• • • • • •

Heat source (fuel-fired, waste heat, nuclear powered, electric powered etc.) Mode of circulation of feedwater (natural circulation, forced circulation) Type of fuel used (coal-fired, oil-fired, gas-fired, bagasse-fired) Position and type of furnace (external-fired, internal-fired) Material of construction (cast iron boiler, steel boiler) Shape and position of tubes (straight tube, bent tube, horizontal, vertical and inclined boiler) • Content of the tube (fire tube, water tube) • Operating pressure of the Boiler (low pressure, high pressure, subcritical, supercritical)

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• Purpose of utilisation (marine, locomotive, power and industrial boiler) • Manufactures trade name (Benson, LaMont, Babcok & Wilcox, Velox) Details of some of the commonly used boilers are discussed in the subsequent sections.

6.3.1  Fire Tube and Water Tube Boiler In fire tube boiler, hot flue gas flows inside the tube. The tube is surrounded by feedwater. Rate of steam generation in this boiler is less. As flue gas flows inside the tube, only inner surface is exposed to the flue gas. So, for same number of tubes, the heating surface is less as compared to the water tube boiler. Chance of explosion is less in this boiler. But in case of explosion, the risk of damage is very high. In water tube boiler, feedwater flows inside the tube. This water receives heat from hot flue gas which flows at its outer surface. As the outer surface of the tube is exposed to the flue gas, so the heating surface is more as compared to the fire tube boiler having same tube. The rate of steam generation is faster in this case. The chance of explosion is more as compared to the fire tube boiler. But the risk of damage in this case is less. To reduce pressure loss in water tube, water tubes are arranged in parallel path.

6.3.2  Straight Tube, Bent Tube, Horizontal, Vertical and Inclined Boiler In straight tube boiler, the tube arrangement is straight. So, the fabrication is not simple. But the bent tube boiler is most suitable, as it is easier to fabricate by welding. Tubes are easily accessible for inspection, cleaning and maintenance. Boiler inside space can be utilised efficiently. Also, bent tube boiler has higher steam generating capacity. Depending upon the geometric position of the boiler, boilers may be classified as into three categories—horizontal boiler, vertical boiler and inclined boiler. When the principal axis is horizontal, the boiler is called horizontal boiler. When the axis of the boiler is perpendicular to the horizontal plane, the boiler is called vertical boiler. When the axis is in inclined position, the boiler is called inclined boiler.

6.3.3  Waste Heat Recovery Boiler (WHRB) Waste heat recovery boilers are used to utilize the heat energy from the system which would otherwise go waste. Mass of hot gas and its temperature are the main factors that decide the design of a waste heat recovery boiler. In sponge iron kilns, lot of hot gas is produced. This hot gas is utilised in the boiler for steam generation. The hot gas contains significant amount of abrasive dust. These dust particles may damage the boiler tube due to erosion. Erosion problem is minimised by lowering the gas velocity. By providing abrupt change in the direction of flue gas flow, dust particles settle down and are removed by suitable ash handling system. Lot of hot gas escapes from cement kiln preheater and cooler. By installing WHRB in these areas, steam can be generated.

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Hot exhaust gas from gas turbine is used in the waste heat recovery boilers for steam generation. The steam is used to drive steam turbine. This arrangement is called combined cycle. In some chemical processes, heat is produced due to exothermic reaction. For example,

N2 + 3H2  2NH3 + 22 kcal of heat 2SO2 + O2  2SO3 + 45 kcal of heat.

Chemical nature, corrosiveness and abrasive dust load in the gas are considered before designing such boiler.

6.3.4  Package Boiler Package boilers are mostly shop assembled. Mostly liquid and gaseous fuels are used in these boilers. These are small in size for easy transportation. These boilers are mostly used to meet process steam requirement in industry. In some cases, these boilers may be hooked up with the other boilers to produce power.

6.3.5  Subcritical and Supercritical Boiler If there is an increase in the pressure and temperature, then the heat contents of the steam (enthalpy) also increases. More work can be done by this steam. So, plant efficiency increases. Nowadays, modern power plants are using high pressure and high temperature steam to reduce the cost of power generation. The velocities of feedwater and steam are more in high pressure boilers. Due to high velocity of feedwater in the tube, chance of scale formation is minimised. These boilers can be started quickly and are suitable to meet variable load. High pressure steam can do more work. But in high pressure boiler, natural circulation of water is limited upto critical pressure (218 ata). As discussed earlier, natural circulation is due to density difference between steam and water. But at critical pressure, the density difference of steam and water is zero. So, this boiler is once through type. Boiler which is operated above critical pressure is called as supercritical boiler and the one which is operated below critical pressure is called as subcritical boiler. Subcritical boiler has economiser, evaporator and superheater. But in supercritical boiler, feedwater from economiser is admitted to the furnace tubes at one end and superheated steam is collected from other end of the tube. There is no drum in this boiler.

6.3.6  Fuel-Fired Boiler Different types of fuels are fired in the furnace of a boiler to generate steam. Fuels may be in the form of solid, liquid or gaseous form. Depending upon the fuel used, boilers may be classified as oil-fired, gas-fired, coal-fired, bagasse-fired, etc. Oil-fired and gas-fired boilers are approximately having same design features except in fuel handling system. Coal-fired boilers may be classified as hand-fired, grate-fired, stoker-fired, pulverised, FBC, etc.

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All these types of boilers are discussed here. Oil-fired Boiler Most of the oil-fired boilers use oil, derived from natural petroleum. High speed diesel (HSD), Light diesel oil (LDO), heavy fuel oil (HFO), low sulphur heavy stock (LSHS) and furnace oil (FO) are used as fuel in oil-fired boilers. Fuel handling system of oil-fired boiler is very simple consisting of fuel oil storage tank, fuel oil pump, oil heater, oil filter, oil trip valve and oil return valve or oil pressure control valve. For handling HFO and LSHS, special attention is given, as this oil is very viscous. Details about this is discussed in the next chapter. High pressure oil is sprayed into the boiler furnace with the help of suitable oil burner. For easy burning, oil is atomised with the help of high pressure air or steam. Complete combustion of oil takes place inside the boiler with the help of primary and secondary air. Small boiler is having one oil burner. Larger boilers have multiple oil burners arranged in the furnace at different elevations (tiers). Oil is supplied to individual burner through an isolating valve. By closing this isolating valve, fuel supply to that particular burner can be stopped. Depending upon the load on the boiler, these burners may be taken into service or taken out of service. Oil pressure is controlled by pressure control valve to meet variable load demand. Oil fired boilers are very much suitable for fluctuating loads. After combustion inside the furnace, flue gas enters different passes for effective heat transfer. Platen type radiant superheater is used to utilise furnace radiation energy. Evaporation takes place at furnace wall tube, roof tube and bank tubes. Ash handling system is not required, as no ash is produced during burning of oil in oil-fired boiler. Boiler house is maintained clean, as no ash is produced. Gas-fired Boiler More or less the design of gas-fired boiler is similar to the oil-fired boiler. Gas is fired at the furnace by gas burner. By controlling the gas supply to the burner, load on the boiler can be adjusted. The combustion air is preheated to get higher efficiency. Like oil-fired boiler, gas-fired boiler also does not produce ash. So, the boiler is very clean. Different gases like petroleum gas, coal gas, blast furnace gas, coke oven gas, etc. are used as fuel in gas-fired boiler. Coal-fired Boiler Different grades of coal are used in boiler as fuel. Combustion system in the boilers is also different. Depending upon the firing system, coal fired boilers are classified differently. Hand firing system is used in small boilers. Response to load fluctuation is less in this case. These boilers are mainly used in small industries to meet process steam requirement. Locomotive boilers which were in use few years back for traction purpose is an example of hand-fired boilers. Pulverised coal (PC), atmospheric fluidised bed combustion (AFBC) and circulating fludised bed combustion (CFBC) boilers are commonly used nowadays. Different types of coal-fired boilers are discussed in the subsequent sections.

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6.4  Traveling Grate-fired Boiler In traveling grate-fired boiler, coal is fed onto the grate which moves at the bottom portion of the furnace. The moving grate is having suitable openings to admit combustion air from the bottom of the grate. This air cools down the grate as well as ash and is used as primary air for the burning of coal. Chain grate and bar grate are similar to each other except in the construction of the grate. In chain grate, cast iron links are connected in series by pins to form a chain. In bar grate, cast iron surfaces are mounted on bars. These bars are mounted on drive chain. In both the cases, the chain is driven by two sprocket wheels. One of the sprockets, mostly at the front of the furnace is driven by a variable speed drive. The depth of coal on the grate is varied with the help of an adjustable gate (Figure 6.3). The speed of the grate can also be adjusted. The coal is fed from the furnace front end and ash is collected from the rear end of the grate.

Figure 6.3  Traveling grate-fired boiler.

Primary air from FD fan is supplied through air ducts under the grate. Secondary air is supplied above the grate for complete combustion of coal. This type of boiler is not suitable to use caking bituminous coal having low ash fusion temperature. As clinker is formed at the grate, it closes the primary air path of the grate.

6.5  Spreader Stoker-fired Boiler In spreader stoker-fired boiler, coal is fed with the help of a rotating feeding device called feeder or spreader. It is a rotating drum having large number of blades mounted on it. When the spreader rotates, it throws coal into the furnace. Some portion of coal, particularly fine particles, burns in suspension and remaining large size coal falls to the stationary or moving grate where it burns. The stationary grate is moved periodically to remove ash from

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the grate. Primary air is supplied to the furnace through the openings of the grate. Secondary air is supplied through nozzles. Depending upon the load on the boiler, spreader speed is adjusted.

6.6  PULVERISED COAL (PC)–FIRED BOILER Coal is used widely for power generation. Pulverised coal firing is the most commonly used technology in coal-fired thermal power plants throughout the world. This matured technology is well developed and is based on many decades of experience. Pulverised coal (PC) or pulverised fuel (PF) fired power plants dominate the world’s power generation industry. Pulverised coal is the most efficient way of using coal for steam generator in a boiler. Larger capacity boilers upto 1200 MW are based on this technology. Supercritical and ultrasupercritical units are utilising this technology. Pulverisation is the best method of preparing coal for burning. When coal is pulverised, it becomes a homogeneous powder and the exposed surface area increases. Combustion becomes faster and requires less excess air for burning. Coal is grounded (pulverised) to a fine powder of +300 µm less than 2% and 70%–75% is below 75 µm (200 Mesh). Pulverised coal burns like oil or gas, resulting in more efficient combustion. The pulverised coal is blown with part of the combustion air (primary air) into the boiler through a series of burner. Fine coal particles are exposed to radiant heat of furnace. The volatile matter is distilled off in the form of gas and burns first and heats up the remaining carbon. Combustion takes place in the suspension spontaneously. Pulverised coal has many advantages in addition to increased thermal efficiency such as flexibility for using wide range of coal variety, fast response, ease of handling large quantity of fuel etc. Therefore, for larger capacity power boilers, pulverised coal firing is always preferred. Pulverised coal (PC) boilers mainly comprise of following systems:

• • • •

Air system Pressure parts Coal feeding system Ash handling system

6.6.1  Air System Primary Air System The function of primary air system is to supply the drying agent for coal pulverisation system and blow the coal dust into the furnace of the boiler. Primary air is obtained from primary air (PA) fan. A part of the primary air is heated at air heater and the other part is not. Cold and hot primary air is adjusted at coal mill to get the required pulveriser outlet temperature. Secondary Air System The function of secondary air system is to supply air for combustion. Secondary air is obtained from forced draught (FD) fan. Prior to feeding it to the boiler, this air is heated at the air

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heater. This preheated air is supplied to the windbox. Windbox acts as a distributing media for supplying secondary air to the furnace for combustion. Sometimes, tertiary air is used. Tertiary air is a part of secondary air which is supplied for delayed combustion to reduce NOx formation. Seal Air System The function of seal air system is to prevent hot air and coal dust escaping from the coal mills and coal feeders into the atmosphere and prevent ingress of coal dust into gear box lubrication oil.

6.6.2  Pressure Parts (Heat Transfer Surfaces) Pressure parts of the boiler consist of water and steam circuit, as mentioned below. These are located at different heat transfer zones as per the boiler design.

• Water circuit

–  Economiser –  Water wall panels (evaporator)

• Steam circuit

–  Primary superheater –  Final superheater –  Reheater Typical arrangement of a PC-fired boiler is shown in Figure 6.4.

Figure 6.4  Typical arrangement of a wall-fired PC boiler.

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6.6.3  Coal Feeding System Raw coal with a particle size of approximately 25 mm–30 mm is stored in a local storage bunker. This coal is fed to the coal mills through coal feeders as per the requirement. Bunker storage capacity is designed to be enough for around 8–10 hours of operation at boiler maximum continuous rating (BMCR) (worst coal). The coal feeding system consists of the following:

• Coal feeder • Coal pulveriser or coal mill • Coal burner

Coal Feeder Coal feeder is used to supply the required quantity of coal to the pulveriser. Feeders are divided into two categories—volumetric feeder and gravimetric feeder. A volumetric feeder discharges certain volume of coal in a particular period while a gravimetric feeder weighs coal. Volumetric feeding may become inaccurate if the bulk density varies. The feeder cannot recognize any change in density because it simply discharges certain volume per unit time.  Example of volumetric type feeders are screw feeder, belt feeder, rotary feeder and vibrating feeder. Gravimetric feeder relies on weighing the material to achieve a required discharge rate. There are two ways of gravimetric feeding—continuous and batch. A continuous gravimetric system controls the weight per unit time like kilogramme per hour. A batch system simply controls the weight of material such as 50 kg. Example of gravimetric feeder is weigh belt. Rotary volumetric feeder:  The main components of a rotary feeder are housing, rotor, head plates and bearings. A numbers of plates are bolted to the rotor wheel along its periphery thereby a number of pockets are formed. When rotor rotates, the plates bolted to the rotor revolve around the stationary cylindrical housing. This feeder is connected from the top to the coal bunker and from the bottom to the pulveriser through coal pipe. When the feeder runs, coal is received by the pockets formed by the plates and emptied into the pulveriser. The rate of feeding depends on the speed of the feeder. Variable speed drive is used to drive this feeder. This is connected through a speed reducing gearbox. A chain connects the sprocket on gearbox unit to the sprocket on feeder shaft. Gravimetric feeder:  Gravimetric feeder is a weigh belt which measures the mass of coal per unit length of the belt and is multiplied by the speed of belt to determine the rate of coal flow. The weighing is done by electronic strain gauges. The fabricated feeder body is having an inlet chute connected to the coal bunker at the top and an outlet opening at the bottom is connected to the mill. Driving pulley of the belt is connected to a variable speed drive. As material moves along the belt, it is continuously weighed by load cell. Speed of the belt is measured by suitable arrangement. The output of the load cell and belt speed is transmitted to the feeder controller for processing and correcting the speed to meet the demand.

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Coal Pulveriser or Coal Mill The function of pulverisation system is to receive raw coal from raw coal bunker which is then dried, pulverised and mixed with primary air and finally, sent to the burners at a controlled quantity. Normally, identical and independent mills are kept in parallel operation with one standby mill arrangement for 100% BMCR design coal (with worst coal quality) requirement. Coal is first crushed by coal crushers to a size of 20 mm to 25 mm. A coal mill requires more power when higher size coal is fed to the mill. Crushed coal is sent by conveyor to bunker near the boiler. Below each bunker, there is a feeder. Crushed coal is continuously fed to the coal mill through this coal feeder as per the requirement. Coal is grinded by grinding elements in stages inside the mill. Coal particles are recirculated before achieving the required fineness. The classifier allows finer particles to escape from the mill outlet while coarse particles are returned to mill for further grinding. The required fineness of coal is 75% through 200 mesh and 99.5% through 50 mesh. The correct quantity of primary air is supplied to the mill to maintain the required air to coal ratio. The main requirements of a pulveriser are given below:

• • • • • • •

Optimum fineness for design coals over the entire pulveriser operating range Quick response to load changes Continuous, stable and safe operation over long operating periods Minimum maintenance requirements, particularly grinding elements Ability to handle variations in coal properties Ease for maintenance Minimum space requirement

Based on their operating speed, pulverisers are classified into following types:

• Slow speed mills (ball mill or tube mill or drum mill) • Medium speed mills (contact mills, i.e., bowl mill or ball and racer mill) • High speed mills (impact or hammer mills)

In PC-fired thermal power stations, various types of coal mills are used. Mostly bowl mill, ring roll mill or ball race mill are found in use. Ball Mill or Tube Mill or Drum Mill:  The ball mill or tube mill has a slowly revolving cylinder which rotates at about 20 rpm. The shell of mill is made of heavy rolled plate. The shell and heads are lined inside with steel plates of adequate thickness so that they last for several years. The entire mill drum is supported and rotates on two antifriction bearings. Shell is rotated by a driving motor with speed reducing gear arrangement and gearwheel which is embedded on the shell. Lubricating oil system lubricates the meshing point of gearwheel and pinion. The interior of this cylinder is filled about half its volume with steel balls whose diameters vary from 25 mm to 50 mm. While in rotation, these balls are carried up about two-third of its way up the periphery at the rising side of the cylinder. Then, the balls fall down. This continuous climbing and falling of the balls crush the coal pieces and reduce them to powdered form.

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Larger pieces are broken by impact and fine grinding is done by the rolling and sliding action of the balls. Hot air enters the mill through the hollow tubes at each end (Figure 6.5). This air picks up the coal fines and enters into a classifier. The function of a classifier is to segregate the coal dust and control the range of particle sizes in the pulverised fuel which leave the mill. Larger particles are recycled to the mill for further grinding and smaller particles are sent to burners.

Figure 6.5  Ball mill.

Ball mill produces 70% to 75% dust having 200 mesh fineness. Contact mill:  Contact mills have a stationary and a rotating element arranged to have rolling action with respect to each other. Coal is passed between them again and again until the desired pulverisation size is obtained. Many variations of contact mills are available with certain changes in the construction. The grinding elements may consist of rollers rolling in a ring or bowl (ring roll mill) or balls running over a surface (ball race mill). An air stream is circulated through the grinding compartment of the mill. Classifier located at the mill top permits fine particles to pass in the air stream and rejects oversized particles which are returned to mill for regrinding. Bowl mill and ball race mill are two commonly used coal mills in PC-fired power plants. Bowl mill (ring roll mill):  Bowl mill is a vertical spindle medium speed mill. In a bowl mill (Figure 6.6), coal is pulverised between two moving surfaces. Grinding rollers are stationary, while the disc called as ring or bowl is rotated by a worm gear drive. Pressure to grind the coal is obtained by heavy springs or pneumatic or hydraulic cylinders. Powerful springs force the grinding rollers against the ring to provide the pressure required to pulverise the coal.

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Figure 6.6  Bowl (ring roll) mill.

Ball race mill:  In ball race mill, a ball between two races provides the grinding surfaces on which pulverisation occurs. One or both of the races may rotate against the ball. Pressure to crush the coal is obtained by forcing these two races with heavy springs or hydraulic pressure. The feeder discharges coal to the centre of the pulveriser onto a revolving bowl. Centrifugal force pushes the coal towards the perimeter of the bowl. Coal passes between race and grinding rolls which impart the pressure necessary for grinding. Partially grounded coal moves outward towards the edge of the race. Hot air is fed into the mill for drying and conveying of the dust particles. A classifier creates a cyclonic flow where the hot air fuel mixture enters (Figure 6.7). Coarser particles are returned back for further grinding.

Figure 6.7  Ball race mill.

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Coal Burner Powdered coal from the pulveriser is directly blown to the burner of the boiler. Burners are arranged at multiple levels mostly on wall (wall mounted) or at corners (tangential-fired) of the furnace. Function of the coal burner is to prepare two individual flows, a coal dust–air mixture and secondary air for ignition and burning in the furnace space. For this purpose, fuel air mixture and hot secondary air are introduced into furnace space at different speeds and with different degrees of turbulence. The burner consists of a central circular duct to supply coal powder and primary air to the burner mouth (Figure 6.8). The arrangement is done at central circular duct to ensure very good homogenisation of the coal powder in the primary mixture under all operating conditions.

Figure 6.8  Coal burner.

Secondary air enters from windbox through secondary air port which ensures combustion air distribution along the circumference of the burner mouth. Secondary air is adjusted with the help of adjustable secondary air flaps in the burner in such a way so as to enable optimum mixing of the combustion air and the coal powder for stable combustion. Tertiary air enters from windbox over the secondary air port. The quantity of tertiary air is controlled in such a way so as to achieve an optimum excess air on the primary flame region in which the pulverised coal burns slowly and reduces NOx formation. Nowadays, low emission (low NOx) burners are used in power plants to burn pulverised coal to minimise NOx emission. Nitrogen oxide (NOx) emission in boiler is mostly due to oxidation of nitrogen atoms in the fuel itself. Advanced design burners reduce formation of nitrogen oxides by staging the addition of oxygen. Initially, it produces a fuel-rich regime. Additional oxygen is supplied at downstream of the flame core for complete combustion with minimum formation of nitrogen oxides. In a tangentially-fired boiler, four tall windboxes are arranged one at each corner of the furnace (Figure 6.9). Coal burners are located at different levels or elevations of the windboxes.

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Figure 6.9  Burner arrangement in a tangential-fired PC boiler.

Normally, the same elevations of coal burner at four corners are fed from a single coal mill. Coal burners are sandwiched between air nozzles or compartments. The fuel air mixture and combustion air streams from these burners are directed tangential to an imaginary circle at the centre of the furnace. This creates a turbulent vortex motion of the fuel, air and hot gases for better combustion efficiency. Auxiliary oil burner:  Auxiliary oil burners are used for

• Providing initial ignition energy to light up coal burner • Stabilising the flame at low boiler/burner loads • Safe start-up fuel and for controlled heat input during light off

Pulverised coal cannot be fired directly during start-up of the boiler. The furnace is required to be heated to a certain temperature first and then only, pulverised coal can be fed. Oil support is required to support the burning when combustion is not stable during low load operation. The capacity of the oil system is designed for 30% BMCR. LDO is normally selected as start-up fuel. Once steam is available, HFO is used with steam atomising. Each oil burner is having its independent igniter. Normally, auxiliary oil burners are arranged in between coal burners at different elevations.

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6.6.4  Ash Handling System Ash is collected from pulverised boiler as bottom ash and fly ash. A detailed discussion about ash handling system is provided in the subsequent chapter. A comparison of a 210 MW and 500 MW PC-fired boiler used for power generation is given in Table 6.1. Table 6.1  Comparison of 210 MW and 500 MW PC-fired Boiler Description

210 MW

500 MW

13868 10592 5049

18034 15289 14580

Furnace

Width (mm) Depth (mm) Volume (m3)

Coal Burner

Type Numbers Capacity kcal/hr

Tilting, wall 24 33.8  106

Tilting, corner 32 51.1  106

Oil Burner

Numbers Capacity

12 10  106

16 17.3  106

Coal Mill

Numbers Capacity Motor (kW)

6 36.9 T/H 340

8 72.1 600

Superheater Steam Flow (t/h) Superheater Steam Pressure (kg/cm2) Superheater Steam Temperature (°C) Reheater Steam Flow (t/h) Reheater Inlet Steam Pressure (kg/cm2) Reheater Outlet Steam Pressure (kg/cm2) Reheater Inlet Steam Temperature (°C) Reheater Outlet Steam Temperature (°C) Feedwater Tempertaure (°C) Coal Quantity (t/h)

627 155 540 565 36 35 337 540 245 110

1681 179 540 1430 45 43 343 540 255 330

6.7  FLUIDISED BED COMBUSTION (FBC) BOILER FBC is a developing technology for efficient and clean burning of coal and other solid fuel for steam generation. This type of boiler is widely used today. This boiler is suitable for combustion of low quality fuel. Fluidisation bed combustion is a method of burning solid fuel in which the fuel is continually fed into a hot fluidised bed of inert bed material. Inert fluidised bed is heated to the ignition temperatures of fuel and the fuel is supplied continuously into the bed. The fuel burns rapidly and bed attains a uniform temperature. Combustion takes place at about 850 °C to 950 °C. This lower combustion temperature is due to effective extraction of heat from the bed through in-bed heat transfer tubes and water-cooled, fin-welded membrane wall. As this temperature is much lower than ash fusion temperature, melting of ash and associated problems are avoided.

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Also, volume of fuel in the bed at any time is less. So, high ash content fuel can be used in this boiler. Small amount of dolomite or limestone is fed into the bed which minimises formation of sulpher dioxide gas (SO2). Another merit of this boiler is the minimum production of NOx in the boiler, as combustion temperature is less. FBC boiler is more accepted nowadays due to the following advantages:

• • • •

FBC boiler can burn fuel with higher combustion efficiency. Size of the boiler is smaller as compared to the conventional stoker-fired or pulverised boiler. FBC boiler can be operated efficiently with a variety of fuels. Coal can be fed either independently or in combination with other solid fuels into the same furnace. Even fuels like washery rejects, biomass solid waste can be burnt efficiently. • Inferior quality fuel can be used in this boiler.  The boilers can fire coals with ash contents as high as 62% and having calorific value as low as 2500 kcal/kg.  • Coal containing fines below 6 mm can be burnt efficiently in FBC boiler. • SOx formation can be minimised by addition of limestone or dolomite for high sulphur coals. Low combustion temperature eliminates NOx formation.

Mechanism of Fluidisation Fluidisation or suspension is a process in which small solid granular particles are suspended in a vertical rising current of air. When air is introduced through the bottom of a bed of finely divided solid granular particles, it moves upwards through the bed via the empty spaces between the particles. At low air velocity, the bed remains in a fixed state. When velocity increases, the bed gets expanded in volume, as the particles move away from each other. When velocity is increases further, it reaches a critical value at which the particles become suspended. At this critical value, the bed is said to be fluidised and it behaves as a fluid. Bed of granular particles is converted from a static solid-like state to a dynamic fluid-like state. By further increasing air velocity, bulk density of the bed continues to decrease and the bed material blows away. So, air velocity is maintained between minimum fluidisation velocity and particle entrainment velocity. Air velocity is around 1.5 m/s such that the bed particles do not leave bed and are carried out. This ensures stable operation of the bed and avoids particle entrainment in the gas stream. Higher air velocity of around 4 m/s is used in case of CFBC boiler where the bed is expanded to top of the furnace. Fixed bed, fluidised bed and expanded fluidising bed (circulating fluidised bed) are shown in Figure 6.10. There are different types of FBC boilers. Following two types of FBC boilers are widely used:

• Atmospheric fluidised bed combustion (AFBC) boiler • Circulating fluidised bed combustion (CFBC) boiler

6.7.1  Atmospheric Fluidised Bed Combustion (AFBC) Boiler Low velocity air is used for fluidisation of the bed in AFBC boiler. Air from FD fan is used for this purpose. This air is approximately 50%–60% of the total air. Balance air supplied by FD fan is used as secondary air. The bed of the boiler is divided into sections (Figure 6.11). Individual sections are called as compartments and have their own coal feeding and fluidising air supply arrangement.

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Figure 6.10  Mechanism of fluidisation (a) Fixed bed low-velocity air; (b) Fluidised bed air velocity 1.5 m/s and (c) Extended circulating fluidising bed air velocity 4 m/s.

Figure 6.11  Atmospheric fluidised bed combustion (AFBC) boiler.

AFBC boiler mainly comprises of the following systems:

• • • • •

Air distributor Fluidised bed Fuel feeding system In-bed heat transfer surface Ash handling system

Air Distributor FD fan supplies the required fluidisation air for the boiler. This Air is heated at air heater and is distributed to compartmentalised airbox (Figure 6.12). A part of combustion air is tapped

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Figure 6.12  Air distributor.

from air heater outlet and further pressurised by a PA fan for pneumatic under bed fuel feeding. The distributor plate is fitted with air nozzles to distribute fluidising air from airbox uniformly over the entire bed. The main function of air distributor is to introduce the fluidising air evenly throughout the bed cross section for keeping the solid particles in fluidised condition and prevent any defluidisation zone within the bed. Air is supplied from airbox which is placed just below the distributor plate. Air from FD fan is supplied to the airbox. Each compartment is having its own airbox and air isolation dampers. The air distributor which forms the furnace floor, is normally made from thick metal plate with a number of perforations in a definite geometric pattern. Air nozzles with bubble caps (Figure 6.13) are fixed to these perforations for uniform air distribution and to prevent solid particles from flowing back into the airbox. Air nozzles should have the following features: • Prevent back flowing of bed material to airbox at low load • Need minimum or no cleaning • Withstand high temperature • Minimum erosion • Distribute air uniformly • Create good turbulence

Figure 6.13

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Fluidised Bed Major portion of the bed volume contains inert bed material. Bed material is obtained from crushed refractory bricks or sieved ash. Specifications of bed material for AFBC boiler is given in Table 6.2. Table 6.2  Specifications of Bed Material for AFBC Boiler Particle Size Bulk Density Alumina Silica Fusion Temperature

1–3 mm 1000 kg/m3 45%–35% 55%–65% 1400 °C

Fluidisation of bed depends upon the bed height. A shallow bed offers a lower bed resistance and hence, a lower pressure drop and lower fan power consumption. In case of deep bed, the pressure drop is more and this increases the effective air velocity and the fan power too. Initial bed height is maintained upto 250 mm to 300 mm. Out of this bed height, around 100 mm bed does not participate in fluidisation. This layer is called as static bed layer. This static layer of bed material protects the distributor plate from high temperature of the furnace. 150 mm to 200 mm bed (above air nozzle level) is available for fluidisation. During operation 200 mm to 300 mm bed height is maintained (excluding 100 mm static bed height). During fluidisation, bed expands upto 1500 mm. Bed tubes are immersed in this expanded bed to maintain the required bed temperature. Following indirect method is adopted to measure the bed height: Measure pressure drop across DP plate without bed:  Maintain furnace pressure through ID fan. Measure pressure drop across DP plate of each compartment at various FD air flows when there is no bed material in the compartment and PA fan is not running. This pressure drop is equal to the difference of airbox pressure and furnace pressure. Measure pressure drop across DP plate and fluidised bed:  At fluidising condition, measure the pressure drop like previous procedure at a particular FD air flow when PA fan is not running. In this condition, pressure drop across DP plate and fluidising bed is equal to the difference of airbox pressure and furnace pressure. Operating bed height which is equal to the pressure drop across bed can be calculated as the difference of the above two pressure drops at a particular air flow. Let air flow be 200 mm (without bed and with bed) Airbox pressure without bed be 200 mmwc Airbox pressure with operating bed be 450 mmwc Furnace pressure at both the conditions be 5 mmwc Then, bed height = (450 + 5) – (200 + 5) = 250 mmwc or 250 mm (as bulk density of bed material is 1000 kg/m3). Total bed of larger size boiler is divided into compartments. Each compartment is having independent coal feeding system with its own airbox and air nozzles for fluidisation. Depending upon the load on the boiler, some compartments are taken out of service. This procedure is called

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compartment slumping. To maintain the temperature of the slumped compartment, fluidising air is charged to that compartment. This is called bed mixing. The procedures of compartment slumping, compartment mixing and activation are discussed here. Bed slumping:  Normally, load variation from 70% to 100% is done by adjusting fuel feeding. Beyond that, it is preferred to stop one compartment. This is called compartment or bed slumping. Normally, compartment at either end of the bed is slumped. Coal feeding to this compartment is reduced to minimum and the feeder is stopped. When bed temperature drops to 800 °C, fluidising air of this compartment is stopped. Small amount of primary air is to be continued to avoid back flowing and chocking of primary air (PA) line. Care should be taken for a slumped compartment for trouble-free operation. Such care involves the following steps:



• When a compartment is slumped for a longer period, bed height of the operating compartment reduces. The bed height becomes less as it spills to adjacent slumped compartment. It is better to periodically activate the slumped bed to get the correct bed height of an operating compartment. • When a compartment is slumped for longer duration, it is necessary to close the PA damper of the slumped compartment. Otherwise, it will lead to bed coil erosion, as the bed material is continuously thrown at the bed coil. • Air may leak to slumped compartment if the air damper is passing. There is a chance of clinker formation if the fuel spillage takes place to the slumped compartment from an active compartment. To avoid this situation, air vent valve may be provided at the compartment airbox to avoid pressurisation of the airbox of slumped compartment.

Mixing and activation of slumped compartment:  When load on the boiler increases, it is required to reactivate the slumped compartment to take into service. Temperature of the slumped compartment is at lower temperature. So, it is required to increase the bed temperature upto 600 °C before starting the fuel feed. For this, mixing of this cold bed with the adjacent active hot bed is required. Fluidising air of the adjacent active compartment is increased and accordingly, the fuel supply is increased to maintain the bed temperature at 900 °C. Fluidising air of the slumped compartment which is to be mixed is opened. Mixing of cold and hot bed takes place. Bed temperature of the active compartment starts decreasing and that of new compartment starts increasing. The fluidising air of new compartment is stopped (stopped mixing) when bed temperature of the active compartment decreases upto 750 °C. This process is repeated till the bed temperature of the new compartment reaches upto 600 °C. This process is called compartment mixing. For activation of hot (more than 600 °C) slumped compartment, PA line air is opened first. Then, the fluidising air is opened for fluidisation and finally, coal feeder is started if the bed temperature is more than 600 °C. Fuel Feeding System Crushed coal of size 6–8 mm is stored in the coal bunker nearer to the boiler. This coal is introduced into the fluidising bed as per the requirement through coal feeders. Underbed pneumatic feeding and overbed feeding methods are adopted in AFBC boiler.



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During starting, oil or gas burners are used to heat the bed material initially. In some cases, initial bed heating is done by burning the charcoal on the bed. Once the bed comes to ignition temperature of the fuel, fuel feeding is started. Underbed pneumatic feeding:  Fuel from the bunker is fed pneumatically into the bed through a rotary feeder and a mixing nozzle located below the bunker (Figure 6.14). Total furnace is divided into compartments. Each compartment of the furnace is having its own coal nozzles to feed the coal into that compartment and air nozzles for fluidisation of that compartment. Based on the capacity of the boiler, the number of compartments and the number of feed points are increased. Coal nozzles are placed at different locations of the compartment to supply coal uniformly into the bed. Each coal nozzle is having its own coal feeder and mixing nozzle.

Figure 6.14  (a) Arrangement of underbed pneumatic feeding and (b) Flow diagram of underbed pneumatic feeding.

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Depending upon the coal requirement, speed of the coal feeder is adjusted. Also, these feeders are interlocked with the bed temperature to cut off coal into the bed when bed temperature becomes high. Coal from the feeder is mixed with high pressure primary air at mixing nozzle and transported upto the coal nozzle (Figure 6.15). Coal is introduced at the bottom of the bed. Transportation of coal to the boiler furnace is done through primary air. The pipeline on which coal is transported is called as PA line. Isolation valve, cross and drain gates are provided on this line.

Figure 6.15  (a) Coal nozzle; (b) Cross nozzle and (c) Mixing nozzle.

Over-bed feeding:  Crushed coal from the coal bunker is conveyed to the spreader by a screw conveyor (Figure 6.16). The spreader distributes the coal over the furnace bed uniformly. This type of fuel feeding system accepts oversize fuel also and eliminates PA lines. Overbed feeding is mostly adopted in CFBC boilers.

Figure 6.16  Overbed feeding.

In-bed Heat Transfer Surface The temperature of fluidising bed is maintained at around 900 °C. The bed temperature is maintained by transferring the heat of bed to the feedwater quickly. For this, bed tubes are placed inside the fluidising bed in which the boiler water flows. These coils are placed over

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the bed at a height of around 500 mm. When bed is fluidised (expand condition), these tubes are immersed in the fluidised bed. It acts as an evaporator and cools down the bed. Due to the high erosive nature of bed material, the bed coil is prone to frequent failure. To minimise the erosion of the bed tube, studding is made on the coil (Figure 6.17). Also, studding improves the heat transfer surface. Sometimes, primary superheater is also placed inside the fluidised bed.

Figure 6.17  Studded in bed tube.

Ash Handling System Mainly two types of ash are collected in an AFBC boiler. These are as follows: Bottom ash or bed ash:  Normally, inferior quality coal is used in the AFBC boiler. Ash and shale percentage is more in this type of coal. After complete combustion of the fuel in the bed, larger size ash particles remain in the bed. Accumulation of this ash increases the bed height and affects the fluidisation. This ash is called as bed ash or bottom ash. Increase in pressure drop across the bed indicates the bed height. To maintain the bed height, bed ash overflow arrangement is provided so that excess bed ash overflows to a separate compartment where it is cooled and drained out. Also, bed is having an ash drain point located at the bottom of the bed. By opening drain gate, larger size ash particles are drained out which are removed latter. Drained material is at bed temperature. So, it is required to cool it before disposal. Fly ash:  The amount of fly ash generated in AFBC boiler is more due to the escape of particles. Fly ash carried away by the flue gas is removed at the following stages:

– – – –

Convection zone Bottom of air preheater Bottom of economiser Electrostatic precipitators (ESP)

Ash collected from the convection zone, bottom of air heater and the economiser is having larger size particles as compared to the fly ash collected at ESP. Through suitable ash transportation system, ash is sent to the disposal area.

6.7.2  Circulating Fluidised Bed (CFBC) Boiler In this fluidised bed principle, the bed particles are suspended in a stream of upwardly flowing air which enters from the bottom of the furnace through air distribution nozzles, same as in

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case of AFBC boiler. But high velocity air (4.5 m/s) is used in CFBC boiler for fluidisation of the bed. Hot primary air from PA fan is used for this. Balance combustion air is admitted to the furnace as secondary air obtained from the secondary air fan. Fluidised bed is extended throughout the furnace. So, some solid bed material along with some uncombusted fine fuel particle and ash is escaped from the bed and carried out with the flue gas. These solid particles are then collected by a solid separator (cyclone separator). In the cyclone, heavier particles are separated from the gas and circulated back into the furnace through a loop seal. Loop seal is considered as the heart of a circulating fluidised bed. This is an arrangement which feeds the solids captured by cyclone to the furnace but prevents direct flow of gas from high pressure furnace to the low pressure cyclone. Fine particles escaped with flue gas pass through the convection section and are collected at ESP. The particle circulation helps in efficient heat transfer to the furnace walls and increases the residence time. No heat transfer tubes are immersed inside the bed. Bed temperature is controlled by the rate of recycling of the fine material. CFBC requires huge mechanical cyclones to capture and recycle the solid particles. So, normally, CFBC boiler is taller. CFBC boiler is generally more economical than the AFBC boiler and its efficiency is more than 85%. There are some advantages in CFBC boiler as compared to the AFBC boiler. These are listed below:

• It is having a higher processing temperature because of high gas velocity through the system. • Lower combustion temperature can be achieved constantly which results in minimal NOx formation. • The combustion air is supplied at lower pressure. • The combustion efficiency is higher. • Turndown ratio is better. • Loss of ignition (LOI) in fly ash is very less. • Erosion of the heat transfer surface in the combustion chamber is reduced, since the surface is parallel to the flow.

Fuel Feeding System Normally, coal from the coal bunker is fed to the bed through a screw feeder by overbed feeding method at the front wall of the boiler. Fewer feeding points are required in case of CFBC boiler. This boiler is having turndown ratio upto 30%. Air bustle arrangement eliminates the back pressure and mechanical sealing system. Start-up/Auxiliary Burner Diesel or furnace oil is used as an auxiliary support fuel. During starting, overbed oil burner is used for the initial heating of bed material and during low load or partial load condition, this burner is used as support burner to maintain the steam temperature and pressure. Auxiliary support is required when load on the boiler drops below 30%. There are two methods to separate solid particles from the flue gas. Depending upon the location of the cyclone separator, CFBC boilers are classified as hot cyclone and cold cyclone boiler.

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Hot Cyclone CFBC In this boiler, flue gas along with ash particles and unburnt coal after leaving the water cooled furnace (combustor), first enters into cyclone before entering into the second pass of the boiler (Figure 6.18). Collection of solid particles takes place at higher temperature. So, this type of cyclone arrangement is called as hot cyclone. There are no heat transfer surfaces inside the boiler furnace. Sometimes, widely spaced wing wall superheater whose bottom portion is refractory lined, is placed in vertical orientation located at the upper furnace. Other heat transfer surfaces like primary superheater, final superheater, economiser and air preheater are placed in the second pass. The furnace, cyclone and cyclone leg are made of water-cooled wall.

Figure 6.18  Hot cyclone CFBC.

Particles collected at cyclone slides down to a loop seal where these are fluidised by air nozzles. This air is supplied by a loop seal blower. Cold Cyclone CFBC In this arrangement, flue gas after leaving free board along with ash particles first passes over the heat transfer surfaces like final superheater, primary superheater, evaporator and a part of economiser in the boiler and then enters into the cyclone for particle separation (Figure 6.19). Collection of solid particles takes place at a lower temperature. So, this type

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Figure 6.19  Cold cyclone CFBC.

of cyclone arrangement is called as cold cyclone. Remaining part of the economizer and the air preheater are placed after cyclone at second pass. Internal Recirculation CFBC (IR-CFBC) This is an advanced arrangement in CFBC boiler where cyclone separator which is prone to erosion, is eliminated. In this arrangement, particle separation is done by U-beam arrangement at the exit of the furnace on the flue gas path. U-beams are the staggered array of stainless steel channels. Solid suspended particles leaving the furnace along with flue gases are captured when they pass through U-Beam arrangement and internally, this material is recirculated to the furnace again (Figure 6.20).

6.8  SUPERCRITICAL BOILER As discussed earlier, the efficiency of Rankine cycle in a coal-fired power plant increases with the increase in pressure and temperature of the water steam cycle. Supercritical (SC) technology which is adopted worldwide is a matured technology for power generation with high efficiency and less emission. First supercritical boiler was commissioned during mid 1950s. The supercritical boiler design rapidly developed. Now, large boilers upto unit size of 1300 MW are in operation. In conventional subcritical coal-fired power plants, water is boiled below critical parameter to generate steam. Here, drum type boiler is used because the steam needs to be separated from water in the drum of the boiler before it is superheated and supplied to the turbine.

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Figure 6.20  U-beam.

Supercritical (SC) boiler generates steam at temperature and pressure above the critical point of water. Supercritical is a thermodynamic expression describing the state of a substance where there is no clear distinction between the liquid and the gaseous phase. Water reaches this state at 221 bar. This point is called as critical point. At critical point, the liquid and gas phases of water co-exist. There is no need to separate steam from the water in a drum. Once through boiler is, therefore, used in supercritical cycles. Generation of steam in a supercritical boiler is shown in Figure 6.21.

Figure 6.21  Steam generation in a supercritical boiler.

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The general arrangement of a supercritical boiler is the same as a conventional boiler except the arrangement of water and steam circuit (Figure 6.22). Drumless once through technology is used so that water enters at one point. Heat is added to convert this water into superheated steam at one go without circulation. Temperature of fluid goes on increasing continuously. In subcritical boiler, temperature of the fluid remains constant at saturation temperature till the completion of evaporation.

Figure 6.22  General arrangement of a supercritical boiler.

Conventional PC firing or CFBC technology is used for supercritical boilers. PC-fired boilers are used for higher capacity units. In PC-fired boiler, either wall-fired or tangential-fired methods are adopted. In CFBC boilers, it is operated like conventional CFBC boiler. Highest unit size supercritical boiler in operation with CFBC technology is around 460 MW. The main features of a supercritical boiler are discussed here.

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6.8.1  Furnace Design In a drum type subcritical boiler, large diameter tubes are used to minimise the flow resistance and to maintain the sufficient amount of water flow through the furnace wall tube by natural circulation. The most common type of boiling of water at water wall takes place at nucleate boiling stage. In nucleate boiling, steam bubbles are formed at the tube surface and then they break away and are carried into the feedwater stream. Such movement enhances heat transfer because the heat generated at the surface is directly carried into the feedwater. Steam and a liquid film are always maintained on the tube wall and overheating of tube does not occur. All the evaporator water wall tubes remain at saturation temperature corresponding to the operating pressure of the boiler. In an OTU supercritical boiler, there is no distinction between liquid and vapour phases and fluid temperature increases continuously. Due to higher heat flux, large bubbles are formed at the tube surface. This results departure from nucleate boiling (DNB) in which steam bubbles does not break away as in case of nucleate boiling (Figure 6.23). A channel of steam bubble is formed at the tube surface which insulates the feedwater from the hot tube surface. So, tube material temperature starts increasing and may lead to failure.

Figure 6.23  Departure from nucleate boiling (DNB).

Also, heat absorption is not same in all the tubes due to geometric tube position (corner versus center of a wall). So, there is a variation in the tube temperature. If this unbalance in temperature is not limited, high thermal stresses will develop and may lead to tube failure. The furnace design of a supercritical boiler should meet the following requirements to avoid the above problems:

• It should be able to take care of heat absorption variations from tube to tube so that the temperature difference between adjacent tubes is limited. • It should provide good tube cooling to avoid DNB and also, avoid dryout so that the peak tube metal temperature is minimised.

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Following are the two types of furnace design that are adopted in supercritical boiler for this:

• Spiral wall design • Vertical wall ribbed tubing design

Spiral Wall Design In conventional vertical wall design, wall tubes at the centre of the wall are exposed to high heat flux in comparison to the corner tubes. Fluid temperature at centrally located tube is more. This unequal temperature difference can cause severe stress on the tubes (Figure 6.24). To avoid this, spiral wall design is adopted.

Figure 6.24  Temperature profile of wall tubes (a) Vertical type water wall and (b) Spiral type water wall.

The most popular design of furnace of a once through supercritical steam boiler is spiral wound membrane wall design. This type of design has a number of technical advantages relating to the thermal performance and reliability of the boiler. The spiral wound tube design is a matured design. In this design, the lower portion of the furnace is arranged in a spiral configuration such that the fluid path wraps around the boiler as it travels up the furnace (Figure 6.25). This design is well established and is applied for any unit sizes. Number and size of the tubes are selected to provide sufficient cooling of the furnace over the entire load range. Every tube is a part of all four walls. So, the difference in length between the furnace tubes is minimised and the heat pickup by individual tube is approximately the same. The spiral water wall system does not require any flow adjusting devices to be installed at the furnace inlet. Upper portion of the furnace is made of vertical tubes. An intermediate transition header is used to make the furnace wall vertical at the upper furnace region. As the lower furnace wall tubes are at an angle, the tubes are not self-supporting. The supporting load is transmitted to the upper section of vertical tubes.

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Figure 6.25

Vertical Wall (Internal Ribbed Tube) Design Vertical wall design (Figure 6.26) is adopted as an alternative to the spiral wall designs. Conventional vertical tube wall design is adopted in this case. But the wall is made of internal ribbed tubes. This type of tube promotes turbulence and keeps the inside tube surface wet. This design minimises capital cost and reduces mechanical complexity.

Figure 6.26  Vertical wall design.

As compared to spiral wound furnace, vertical ribbed tube furnace has following advantages:

• • • •

Self-supporting tubes, hence, simple boiler support system Elimination of transition headers at spiral/vertical interface Simpler ash hopper tubing geometry Lower overall boiler pressure drop

6.8.2  Water and Steam Circuit The water and steam flow circuit of a supercritical boiler is shown in Figure 6.27.

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Figure 6.27  Water and steam flow circuit of a supercritical boiler.

Economiser Economizer is positioned at the lower, uncooled casing section of the parallel pass heat recovery area (HRA). Like conventional boiler, economiser is of plain tube, continuous loop, horizontal, drainable type. Air heater is placed downstream of the economiser. Evaporator After economiser, the feedwater passes the through the evaporator where entire water is converted into steam. The steam is slightly superheated when it exits furnace wall. An evaporator circuit consists of the following things:

• Furnace wall • Transition header • Vertical smooth bore tube wall

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Steam from the evaporator circuit is then passed through in-line steam/water separator which is a part of the start-up system. Here, water particles from steam are separated. Superheater Further heat is added to the steam obtained from evaporator at superheater to get the final superheated steam. A superheater circuit consists of the following things:

• • • • •

Furnace roof HRA enclosure (back pass wall) Primary superheater Platen superheater Final superheater

To control the temperature of main steam, spray water attemperators are positioned upstream of the furnace platen superheater and the final superheater. High pressure turbine bypass the valve is provided to bypass the superheated steam flow to the turbine. By opening this valve, superheated steam flows to the reheater. Reheater Reheat steam obtained from high pressure turbine is first heated at primary reheater placed at HRA. The steam then passes through final reheater to achieve the final reheat steam temperature. Spray water attemperator is provided for reheat steam temperature control. Low pressure turbine bypass valve is provided to bypass the reheat steam flow to the condenser. By opening this valve, reheat steam can be dumped into the condenser. High pressure and low pressure turbine bypass system helps to minimise the start-up times. Reheat steam temperature is controlled by multilouver dampers which control the gas flow through the parallel pass HRA.

6.8.3  Heat Recovery Area (HRA) Flue gas leaving the furnace enters parallel pass HRA located at the second pass of flue gas path. Casing of the HRA is steam-cooled. The modular type HRA includes a primary reheater and a primary superheater which are supported by steam-cooled hanger tubes. A smooth tube economiser is housed within an uncooled casing enclosure and is positioned at the bottom of the HRA. Air heater is placed downstream of the HRA.

6.8.4  Start-Up System During start-up, minimum fluid flow is to be maintained within the furnace wall (evaporator tubes) to protect the tubes from overheating. To achieve this minimum flow, a recirculation system is used. Through recirculation system, unevaporated water from the furnace is sent back to the economiser inlet. This arrangement also assists to reduce the start-up time. The recirculation system consists of a steam water separator and a recirculation pump.

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Steam Separator During start-up, the boiler is controlled similarly as a drum type unit by having in-line steam/ water separators downstream of the evaporator to separate the liquid and vapour phases. Water–steam mixture enters the vertical separators with tangentially attached inlet pipes. Steam outlet pipe is located at the top and the water outlet pipe is located at the bottom of the separator. The separated water is collected in a water collecting vessel. The collecting vessel is provided with water level to maintain the water level during start-up, low load and shutdown condition. To maintain the level of collecting vessel, extra water is drained out to the flash tank.

6.8.5  Materials used in Supercritical Boiler Suitable material selection of the supercritical boiler can make the boiler reliable to get a trouble-free operational life. As the boiler is operated at higher temperature, so proper care must be taken while selecting the tube material. The materials used in supercritical boilers are shown in Table 6.3. Table 6.3  Materials used in Supercritical Boilers Heating Surface

Material

Design Temperature

Economiser Water wall Furnace roof/ Back pass wall Primary reheater Final reheater Primary superheater Platen superheater Final superheater

SA 210 SA 213-T12/T23 SA 213-T23 SA 213- T12 SA213-T22/T91/ /TP347H/TP310H SA 213-T91 SA213-T92/TP347H/TP310H SA213-T92/TP347H/TP310H

375 515 510 540 680 550 640 650

The parameters of a 660 MW supercritical boiler are given in Table 6.4. Table 6.4  Parameters of a 660 MW Supercritical Boiler Description Furnace

Width (mm) Depth (mm) Height (m)

Super Heater Steam Flow (t/h) Super Heater Steam Pressure ( kg/cm2) Super Heater Steam Temperature (°C) Reheater Steam Flow (t/h) Reheater Inlet Steam Pressure (kg/cm2) Reheater Outlet Steam Pressure (kg/cm2) Reheater Inlet Steam Temperature (°C) Reheater Outlet Steam Temperature (°C) Feedwater Tempertaure (°C) Coal Quantity (t/h) Plant Heat Rate (kcal/kwh)

Values 20402 20072 68 2115.5 259 571 1715 48.88 47 328.6 569 292.6 323 1860

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6.9  BIOMASS-FIRED BOILER Huge quantity of agriculture waste is generated in our country. These wastes are not utilised properly. There is a lot of scope to generate significant amount of power by using this biomass as a fuel. Biomass-fired boiler is not much different from the conventional fossil fuel-fired boiler. Biomass-fired boiler uses conventional fossil fuel firing technology for steam generation. Following technologies are used normally:

• • • • •

Travelling grate firing Spreder stocker Suspension combustion (fuel burns in suspension like PC boiler) AFBC CFBC

Biomass is used as a direct fuel or a co-fuel. In direct biomass-fired boiler, only biomass is used as a fuel. The boiler has all the systems, as discussed earlier. Burning of biomass fuel takes place inside the furnace made of membrane type water wall. The boiler has air heater, economiser, evaporator and superheater arrangement like a conventional boiler. Fuel handling system is designed to supply fuel as per the burning technology or type of boiler. It is difficult to get a single biomass fuel throughout the year. So, multiple types of biomass fuel are used. Most of the ash is collected as fly ash at ESP or bag house. In case of co-firing boiler, certain percentage of biomass is used along with the coal. Suitable arrangement is made to blend biomass with coal before feeding into the boiler. Biomass can be used as a co-fuel in the existing coal-fired boilers also. In another co-firing method, biomass is injected separately into the furnace. Co-firing fluidised type boilers are preferred widely for biomass-based power generation. Any multiple type of biomass fuel depending upon availability can be used in this boiler.

EXERCISES 1. What is a boiler, as per Indian boiler Act–1923? 2. What are the main systems of a boiler? 3. What are the boiler mountings and accessories? 4. What is natural circulation? 5. When does the natural circulation in a boiler stop? 6. What is the difference between fire tube boiler and water tube boiler? 7. What is the difference between subcritical boiler and supercritical boiler? 8. How is load controlled in an oil-fired boiler? 9. Why is the atomisation of oil done? 10. Why is ash handling system not provided in oil and gas-fired boiler? 11. What is a package boiler?

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How is the grate of a boiler cooled? What is the function of a spreader? How is load adjusted in a spreader stoker-fired boiler? What are the advantages of coal pulverisation? What are the uses of primary, secondary and seal air in a pulversed boiler? What are the main pressure parts of a PC boiler? What are the main equipments used in coal feeding system of a PC boiler? How is the mill outlet temperature controlled? What is the size of pulverised coal in a PC boiler? What is the difference between volumetric feeder and gravimetric feeder? What is the function of a classifier? What is contact mill and what are its main types? How NOx formation is controlled in coal burner? What is a tangentially-fired boiler? Why are oil burners used in a PC boiler? What is the advantage of a FBC boiler? How does fluidisation take place and why is the bed so called? At what temperature does the coal burn in an AFBC boiler? What is the function of air distributor plate in a FBC boiler? Which air is used for fluidisation? Define airbox. What is the function of air nozzle? What is bed material? What is static bed layer? Mention its role. What do you understand by compartment? What is bed slumping and bed mixing? Why is the bed of slumped compartment activated periodically? Expalin the fuel feeding methods adopted in a FBC boiler. What is the function of primary air (PA) in pneumatic underbed feeding method? Mention the size of coal used in an AFBC boiler. What is the function of coal nozzle in an AFBC boiler? What is the function of in-bed tubes and why is studding done in these tubes? What is bottom ash or bed ash in a FBC boiler? How does it affect the boiler operation? Why is the bed drained periodically? What is the meaning of LOI in ash? What is circulating fluidised bed? What is the function of loop seal in a CFBC boiler? What is the difference between hot cyclone and cold cyclone?

12. 13. 14. 15. 16. 17. 18. 19. 20. 21. 22. 23. 24. 25. 26. 27. 28. 29. 30. 31. 32. 33. 34. 35. 36. 37. 38. 39. 40. 41. 42. 43. 44. 45. 46. 47. 48. 49.

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50. 51. 52. 53. 54. 55. 56.

What is a supercritical boiler? Why are supercritical boilers considered as once through type? Which two types of wall designs are adopted in a supercritical boiler? Why is spiral wall design required in a SC boiler? What is the function of intermediate header in spiral wall design? What is the function of steam separator in a SC boiler? What is a co-firing biomass boiler?

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Chapter

7

Fuel Handling System

7.1  INTRODUCTION Different types of fuels are used in different boilers for steam generation. Waste heat recovery boiler (WHRB) of some process plant and heat recovery steam generator (HRSG) of combined cycle power plant do not use fuel. Steam is generated in this case by utilising the heat of waste gas produced during some processes or by some other means. Indirectly, fuel is used at upstream of the boiler to produce this hot gas. Different fuels like solid fuels, liquid fuel and gaseous fuels are used in boiler. Handling of all these three types of fuel are discussed in this chapter.

7.2  HANDLING OF LIQUID FUELS Light diesel oil (LDO), high speed diesel (HSD), heavy fuel oil (HFO), furnace oil (FO) and low sulphur heavy stock (LSHS) are normally used as fuel in oil-fired Boilers. The handling procedures of different oils are different. In the subsequent sections, handling procedures of different liquid fuels are discussed.

7.2.1  Handling of LDO and HSD Some small boilers use LDO or HSD as fuel. These boilers are mostly package boilers having less generating capacity. Normally, less quantity of fuel is used in these boilers. Also, HSD is used as a starting fuel in some boilers. HSD is transported to the boiler site in tankers by road from the oil suppliers. This oil is unloaded into a storage tank (Figure 7.1). Oil is pumped directly into the boiler through a filter unit and a flow metre. Oil pressure in the pipeline is maintained with the help of a control valve provided at the return line. To take care of the overpressure, relief valve is provided in the line. In some cases, oil is pumped to a small tank called day tank. From the day tank, oil is used in the boiler. Depending upon the requirement of the boiler, oil flow is regulated through a regulating valve provided at an individual burner. Oil supply to the boiler is cut off by an isolated trip valve when it is required to stop the boiler or in case boiler trips. Bypass valve is provided across the flow metre and filter unit for their maintenance. 112

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113

Figure 7.1  HSD-fired boiler.

High pressure air is used to atomise HSD at the burner.

7.2.2  Handling of HFO, FO and LSHS Some package boilers and some medium-sized boilers use HFO, FO and LSHS as fuel. The handling method of this type of oil is different from the handling of HSD. These oils are very viscous. Oil is heated to make it less viscous so that it can flow easily in the pipeline. HFO, FO and LSHS are transported to the boiler site by road or rail. Special tankers are used for this purpose. Storage tank is jacketed with steam coils to keep the oil hot so that it can be pumped. The oil pipelines are heat-traced. Strainers and pumps are also heat traced. This prevents loss of heat and solidification of oil in any section of the pipe and the equipment. Heat tracer takes care of heat loss in the oil line. Steam tracer and electrical tracer run along with the oil pipeline. Traps are provided to remove condensate from the steam tracer line and oil heater. The entire oil pipeline is heat insulated. Suitable draining facility is provided to drain out the oil line for maintenance. If there is a day tank, then oil is pumped to the day tank once or twice a day. From the day tank, oil is pumped to the boiler. From the storage tank or day tank, oil is pumped by a fuel transfer pump. Before feeding the oil into the boiler, oil is heated and filtered. Normally, two heaters and two filter units are used with suitable online changeover valve. Heater oil pressure is maintained by regulating the return valve pressure control valve (PCV). This is a pneumatic operated control valve placed at the return line. When return valve is closed, heater pressure increases and by opening return valve, heater pressure decreases. Steam is used in the oil heater. To control the temperature of the oil, steam flow into the heater is controlled through a control valve. After heating, the oil is filtered in a filter. One heater and one filter are kept on service and other set is kept as standby. They can be changed online with suitable changeover arrangement. Fuel supply to the boiler can be stopped by oil trip valve (OTV). Any abnormality or trip condition of boiler closes this OTV. Oil recirculation valve (ORV) is used to recirculate the oil to keep oil pipeline in hot condition. This ORV is a three-way valve. When burners are in line, oil flow is from point 1 to point 2 as shown in Figure 7.2. When burners are not in line, oil flow is from point 1 to point 3. During this condition, oil circulates through the oil ring header.

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Figure 7.2  FO-fired boiler.

One oil control valve is provided at each burner to control the oil flow to that particular burner. During any abnormality in that particular burner this valve closes to stop oil flow to that burner. Manual isolating valve is provided for individual burner. One flow metre is provided at the oil line to measure oil flow into the boiler. In large boilers, there are multiple oil burners. Mostly steam is used for atomisation of the oil at burner. Suitable isolating valves are provided for each burner to isolate atomising steam.

7.3  HANDLING OF GASEOUS FUEL As discussed earlier, some natural gas obtained from petroleum wells and some byproduct gases like blast furnace gas and coke oven gas are used in the boiler as fuel. Naphtha produced in petroleum refinery is mostly used in the power boilers. Natural gas or naphtha is transported to the boiler site through pipeline. In this case, normally, boiler is placed nearer to the gas source. Gas storage tank is not like oil storage tank. Roof of the tank floats on the stored gas and sealing device is installed on the peripheral space between roof and shell plate to prevent any leakage. This type of tank is called as floating roof storage tank. The roof moves up and down according to the gas pressure with mechanical arrangement and constant pressure is maintained inside the gas storage tank. Like oil handling system, gas handling system has also a fuel trip valve and a fuel regulating valve. An orifice is provided to measure the gas flow. Blast furnace gas contains significant amount of dust. So, before using it in a boiler, this gas is cleaned at gas cleaning plant. In the process of gas cleaning, gas becomes moist

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(due to wet scrubbing process). So, before feeding this gas into boiler, suitable arrangement is done to trap this moisture. Sometimes, the entire gas produced by the blast furnace is used in the boiler. In some cases, the gas is stored in the storage tank and used in the boiler as per the requirement. Like blast furnace gas, coke oven gas is supplied to the boiler directly through a pipeline. A storage tank is provided to store the excess gas. Later on, this stored gas is used when load is high.

7.4  HANDLING OF SOLID FUEL: COAL HANDLING PLANT In India coal is classified into various grades depending upon the ash content. Based the design of the boiler, different grade coals are used in different boilers. The coal is handled in a coal handling plant. At coal handling plant, following activities are performed:

• • • • •

Receiving Storage Reclaiming Preparation or sizing Feeding

7.4.1  Coal Transportation and Storage Coal is mined from coal mines. This coal contains ash forming and sulphur bearing minerals, rocks, etc. After mining, this coal is cleaned and sized properly. This is done at coal beneficiary plant or coal washery. Bulk coal consumers have their own coal beneficiary plant preferably located at coal fields. A coal beneficiary plant or coal washery mainly contains crushers, screens, jigs, etc. In coal washery, rocks and other ash forming materials are separated from the coal due to density difference between them. Coal beneficiation ensures high quality coal to the plant. This beneficiary coal is transported to the plant through rail or road. Coal is transported through rail when consumption is more. Rail wagons are unloaded at the plant by wagon tippler and stacked in a suitable area having draining facility. For medium-sized plants, coal is transported by road through automatic hydraulic operated lift trucks. Coal is weighed at weigh bridge before unloading. Depending upon the coal requirement, availability of coal, company policy to stock inventory and the transportation facility available, coal stock is maintained at the plant. Normally, thirty days coal stock at plant is sufficient to run a boiler. When coal comes in contact with atmosphere, oxidation takes place. This is called weathering of coal. Also, sometimes, spontaneous burning of coal takes place due to this oxidation. So, normally coal is stored in heaps so that the interior of heap is not exposed to the atmosphere. Small plants normally store coal in a covered storage area. Fire hydrant and water sprinkler arrangements are done in a coal storage area.

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7.4.2  Coal Preparation From the storage area, coal is sent to the boiler as per the requirement. For reclaiming coal from the storage area reclaimer, crane, pay loader, etc. are used. Before feeding coal to the boiler, coal is prepared suitably. Coal is crushed on a crusher to proper size as per the requirement of the boiler. This crushed coal is fed to the vibrating screen for getting the required size coal. Magnetic separators are provided to separate magnetic materials from the coal. Then, this coal is weighed in weigh feeder and stored in a hopper called as storage bin for use in the boiler. The arrangement of a coal handling plant is shown in Figure 7.3.

Figure 7.3  Coal-preparation system.

Some common equipments used in a coal handling plant of a thermal power plant are discussed here. Conveyor Belt System Conveyor belt is used for feeding coal into the boiler. Numbers of belts are used for coal transportation from coal stock yard upto the boiler bunker. A conveyor belt is an endless rubberised flat belt moving between pulleys at either ends. It consists of various pulleys, idler arrangements and a suitable belt tensioning arrangement system. All these components are mounted on a suitable steel structure. The carrying troughed belt moves over the supporting idler sets. The belt is driven by one of the pulleys (usually the head pulley). Coal is fed to the conveyor at the tail end through a chute and is transported along the carrying side to the head end where it is discharged to a discharge chute.



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The main components of a belt system are conveyor belt, pulley and idler/roller. These are discussed below: • Conveyor belt:  This is the heart of a belt system and the costliest individual item of the conveying system. A standard rubber conveyor belt has a foundation of sufficient strength to withstand the driving tension and load of the material. The foundation is of cotton, nylon or steel cord which is bound together with a rubber matrix and completely covered with a layer of vulcanised rubber. Normally, nylon conveyor belt is used. • Pulley:  The conveyor belt moves between pulleys. The portion of the pulley in direct contact with the belt is called as drum. The drum is fabricated from rolled steel sheet or from hollow steel tubing. It has a specific face width and diameter depending upon the width of the belt and rating of the belt to be used. To improve the torque that can be transmitted through a drive pulley, it is required to improve the friction between conveyor belt and pulley. So, pulley drum surface is lagged or covered with rubberised material. This cover has a plain or grooved pattern. The rubber lagging is vulcanised to the pulley drum to ensure that it remains attached under adverse operating conditions. Different types of pulleys are used in a conveyor system. Different pulleys have different functions on the same conveyor, as discussed below: Drive pulley:  Drive pulley gives motion to the conveyor belt. Head pulley is connected to the drive motor through a reduction gearbox. Head pulley:  Head pulley is located at the head end where material is discharged. Snub pulley:  To avoid slipping, good contact between belt and drive pulley is required. To increase contact over the pulley, another pulley called snub pulley is used. Take-up pulley:  Uniform tension of the belt is to be maintained continuously. In most of the conveying systems, gravity-operated arrangement is used to adjust the tension continuously. At the return side, the belt passes through a set of bend pulley and take-up pulley. The take-up pulley is directly connected to some dead weight or some rope and pulley attachment, as shown in Figure 7.4.

Figure 7.4  General arrangement of conveyer system.

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• Idler:  Different types of idlers/rollers are used in a conveyor system. Their functions are different on the same conveyor, as discussed below. Troughing idler or carrier idler:  Troughing idlers are the set of rollers on the material carrying side of the conveyor and are the main load bearing units of the conveying system. There are two, three or five rollers in a set mounted in a frame. The rollers in the set are inclined upwards from the centre so as to raise the edges of the belt and give it a trough-like profile (Figure 7.5). The carrying capacity of a troughing belt is more than that of a flat belt. Trough shape helps in carrying the material effectively without any spillage. Spacing of carrier idler along the belt is decided to avoid sag in between the rollers.

Figure 7.5  Troughing idler set.

Return idler:  Return idlers are placed at the return side of the conveying system to carry the empty belt towards the tail pulley. The return rollers are horizontal straight rollers. The spacing of return rollers is more as compared to carrier rollers, as they have to only guide and support the empty belt. Impact idler:  Impact idlers are placed at the material feeding area to limit the impact force caused due to falling of material on the belt. These idlers support the belt at that area and protect the belt from damage. These rollers are covered with rubber rings of an adequate thickness. Belt steering idler:  This is also called as self-aligning troughing set. Sometimes, a lateral movement of the belt is caused. To adjust the belt position to the centre, self-aligning troughing set is fixed at the load carrying side of the belt. This idler set keeps the belt in centre position. The self-aligning troughing set is designed as a series of rollers arranged in a trough position similar to carrying idler set but is fixed on a ring which rotates automatically whenever the belt tracks off the conveyor centre. As the position is adjusted automatically, belt returns to the centre. Guide roller:  For various reasons, the conveyor belt tends to move to a side. In this case, vertical rollers called as guide rollers are used to guide the belt. But guide rollers do not eliminate the cause of belt tracking off. The impact, carrier and return idlers are spaced at different intervals dependant on the load on the belt. On the carrying side, mass of the belt and the load conveyed is more than the mass to be supported on the return side. So, the spacing of return idler is more as compared to the carrying idler.



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Safety and protection system of belt conveying:  Coal handling plant is generally semioutdoor or outdoor located and spread over a wide area. So, continuous manual supervision is not possible. Safety arrangements are, therefore, required to detect any abnormality and to initiate appropriate actions to avoid damage to the operating personnel as well as to the conveying system. Interlock arrangement is provided in a series of belts such that failure of any particular belt automatically stops the upstream belts and equipments. Following safety features are provided in a conveyor belt system: Pull cord switch:  Pull cord switch is a very important safety device of a conveyor belt. Pull cord switches are installed at one or both sides of the conveyor along with walking platform at an interval of 20 m–25 m. A pull wire rope runs along the length of the belt at a convenient height and is connected to the operating handle of each pull cord switch. In case of emergency, the operator can pull this wire rope to operate a pull cord switch and stop the conveyor belt. All the pull cord switches installed in a belt are electrically connected in a series. So, actuation of anyone of these pull cord switches stops that particular conveyor until the particular switch is manually reset. Belt sway switch:  Belt sway switch device detects the misalignment of the belt while running. Belt sway switches are installed at both side edges of the conveyor at intervals of about 40 m–50 m. A small clearance is kept between the operating handle of switch and the belt edge to allow normal running of the belt with acceptable swaying. If belt runs towards either side due to any reason, then the belt edge pushes the operating handle of the belt sway switch. It stops the conveyor or generates a warning signal to take a corrective action. The switch resets automatically when the belt position comes to normal. Hold back device:  Hold back device is installed in an inclined conveyor to prevent reverse movement of the belt. Normally, ratchet and pawl type hold back device is widely used. The pawl moves over the ratchet teeth when the belt runs in forward direction. When belt moves in reverse direction, the pawl engaged in the teeth of the ratchet wheel stops the movement. The ratchet wheel is fitted to the drive pulley shaft and the pawl spindle is fixed to the conveyor belt structure. Hold back clutches are also used to prevent the reverse movement of the belt. This device allows rotation in forward direction. But when the direction reverses, the inner and outer races are locked. Following are the two basic types of clutch type hold back: – Roller on inclined plane clutch – Sprag clutch Underspeed or zero speed detector:  Non-contact type proximity speed sensors are used to detect the speed of the conveyor belt. This sensor detects the rotation of a target which is attached to the shaft of a non-driving tail end pulley. When belt slips, then speed of this pulley reduces. This change in speed is detected by the speed sensor that stops the belt automatically. Zero speed switch is similar to the speed sensor which detects lack of speed or zero speed of the belt conveyor. When there is a breakage in the conveyor belt, then motion of the tail end pulley stops. The speed sensor which detects rotation of this pulley, does not detect any speed and stops the belt automatically.

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Belt damage detector:  Healthiness of the belt is monitored by the electromagnetic detectors. Closed-circuit sensor loops are embedded in the belt. These loops pass over the detectors along with the conveyor and output pulse is generated. This sensor loop is discontinued when the belt is damaged. When this discontinued loop passes over the detector, no pulse is generated and the belt stops automatically to minimise further damage and avoid costly repair and downtime. Magnetic separator:  Electromagnetic separator is suspended above the conveyor belt with the help of an overhead supporting structure. The coil of the electromagnet is charged through a rectifier to generate magnetic field and oil is used for the cooling of coil and core. When coal on the belt passes beneath the magnetic separator, it attracts the ferrous material, if present in the coal. It eliminates the possibility of damage of the downstream equipment like crusher and pulveriser. The collected ferrous material can be separated manually or automatically by a self cleaning arrangement. Self-cleaning magnet has a cleaning or sweeper belt continuously driven around the magnet face driven by a geared motor. This cleaning belt moves the collected magnetic material to the side away from the conveyor belt. When this magnetic material moves away from the magnetic field area, then due to its gravity and inertia, it falls to a collecting bin beneath the magnetic separator. Burden depth (material depth) of the conveyor belt depends upon the belt speed, width, capacity and bulk density of the material. Burden depth determines the suspension height of the magnet and consequently, the effective magnetic field strength at the belt surface. Larger tramp material and deeper burden depth require larger capacity magnetic separator. At specified suspension height, field strength of 1000 G at the centre of belt width in hot running condition is normally kept. Metal detector:  Magnet attracts only ferrous metal and is not 100% effective. For full protection of the system, metal detector is used in combination with the magnetic separator to ensure that any metal under the coal bed that may escape from magnetic separator does not pass through the metal detector. Metal detector is a sensitive instrument used to detect the presence of ferrous and non-ferrous metals. It stops the conveyor to ensure that no metal components damage the downstream equipments. It is required to remove the metal manually. Bucket Elevator Bucket elevator is used to convey materials vertically rather than horizontally. The elevator has a series of buckets attached to an endless loop of belt or chain. Belt is driven by pulleys and chain is driven by sprockets. Belt or chain travels continuously around the head pulley/ sprocket and tail pulley/sprocket. Head pulley/sprocket is driven by a motor and a speed reduction gearbox. Buckets are loaded at the inlet point located at the bottom of the elevator. The loaded buckets travel up over the head pulley/sprocket where they are emptied into the discharge throat and return back down to continue the cycle. The main parts of a bucket elevator are as follows:

• Bucket • Moving belt or chain • Motor and speed reduction gearbox

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• • • •

121

Pulley/sprocket Boot housing with adjustable tensioner Material loading, discharge chutes Casing

Following safety features are provided in a bucket elevator:

• Zero speed detector • Off-track detector • Hold back Normally, elevators are available in following two types:



• Belt bucket elevators using belt as lifting element • Chain bucket elevators using chain as lifting element (single strand or double strand). Depending upon the method of discharge, bucket elevators are classified as follows:



• • • •

Centrifugal discharge type Continuous discharge type Positive discharge type Internal discharge type

Of these four types, following two types of bucket elevator are widely used: • Centrifugal discharge bucket elevator:  Centrifugal discharge bucket elevator is most commonly used for coal handling in power plants. The buckets are mounted at wide intervals on a chain or belt. It operates at high speed. At head end, it throws the materials out of the buckets into the discharge throats by centrifugal force. • Continuous discharge bucket elevator:  This elevator has buckets mounted continuously on chain or belt. Continuous buckets are used leaving minimum clearance between the buckets. The material filled in the bucket is discharged at the inverted front of the proceeding bucket while passing around the head pulley or sprocket. The bucket then guides that material into the discharge throat. Generally, the capacity of an elevator is determined by multiplying the individual carrying capacity of a bucket by the number of buckets per metre of the belt/chain and the belt/chain travel per minute (metre per minute). If the bucket capacity is 0.2 t and there are 4 buckets per metre and the belt moves 2 metre per minute, then Capacity of elevator = 0.2  4  2 = 1.6 t/min or 96 t/min Coal Feeder A coal feeder is an equipment used in a coal handling plant to control or regulate the rate of coal flow from a bin or hopper.  The feeder is used in conjunction with conveyors, crushers and vibrating screens. There are many types of coal feeders used in a power plant. These are discussed below:

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• Vibrating feeder:  Vibratory feeder is used widely to control coal feeding in a power plant. A vibrating feeder consists of a tray which vibrates either by an electromagnet or by an electric motor. It spreads the material evenly along the tray which results in smooth discharge. The rate of discharge can be adjusted by varying the vibration amplitude. Electromagnetic type feeder operates by applying the pulsating current. When this current passes through the stator coil, it creates interrupted pulls on the armature which is connected to the tray. In motor operated feeder, motor rotates two eccentric shafts to produce a linear power which forces the feeder to vibrate. • Apron feeder:  Apron feeder is mostly used to handle bulky material. The apron is a conveyor made up of a series of steel pans. The apron is moved by steel chains rotating around the sprockets. One of the sprockets is connected to the driving motor. The rate of discharge is controlled by adjusting the height of the gate or the speed of the conveyor. • Belt feeder:  Belt feeder is used when material is having fine contents. A belt feeder is simply a short conveyor belt. Like apron feeder, the rate of discharge is controlled by adjusting the speed of the conveyor. • Rotary vane feeder:  Rotary vane feeder has motor driven rotor having a number of plates bolted to its periphery thereby forming a number of pockets. During rotation, each pocket is loaded with coal at the top and discharged at the bottom by gravity. The rate of discharge is adjusted by adjusting the speed of the feeder. • Screw feeder:  Screw feeder is used to feed coal into the furnace in an overfeed FBC boiler. Material is fed at one end of the feeder. A rotating screw within a casing moves material to the discharge end. The rate of discharge is controlled by adjusting the speed of the feeder. Coal Crusher Coal obtained from coal mines is not sized as per the requirement of the boiler. Bigger size coal cannot be used in a boiler. So, it is required to size the coal properly before feeding it into the boiler. Reduction of coal size is done at crusher. Sometimes, it is required to reduce the size of coal lumps before final crushing. For this, combination of primary and secondary crushers are used. Different types of coal crushers are used in coal handling plant. Some of the main type coal crushers are discussed below: • Jaw crusher:  Jaw crusher has a moving and fixed jaw arrangement (Figure 7.6). The moving jaw makes reciprocating motion by an eccentric shaft connected to the motor through belt and pulley arrangement. The angle between moving jaw and fixed jaw increases when moving jaw moves up and decreases when moving jaw moves down. The coal entering the crushing cavity, consisting of fixed jaw and moving jaw, is crushed. The products after crushing are discharged from the outlet of jaw crusher. • Hammer crusher:  Rotor of hammer crusher rotates at high speed in the crushing cavity of the crusher. Hammers are attached to the rotor (Figure 7.7). Coal enters the crusher from the feed opening and is impacted with the high speed rotor. The bottom of the rotor is equipped with sieve plate. Smaller size coal is discharged through sieve plate. Bigger size material retained over the sieve plate is stroked and grinded again by hammer and discharged from the crusher finally.

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Figure 7.6  Jaw crusher.

123

Figure 7.7  Hammer crusher.

• Impact crusher:  Impact crusher uses impact energy to crush the coal. The impact crusher is suitable for secondary crushing. The rotor of the impact crusher revolves by a motor. Revolving blow bar or plate hammer mounted on the rotor creates high speed impact on the material and throws it to the impact plate fixed at the other end of the crushing cavity (Figure 7.8). By this, impact coal is crushed. The uncrushed material returns to the blow bar to undergo the above process till the material is crushed and passes between the blow bar and the grinding plate. The material having size smaller than the gap between grinding plate and blow bar is discharged at the bottom of the crusher. By adjusting the gap between the impact plate and grinding plate with blow bars or plate hammer of the crusher, the size of the products can be adjusted.

Figure 7.8  Impact crusher.

• Roll crusher:  Roll crusher has two  rotating  cylindrical rollers which rotates towards the gap between them (Figure 7.9). The rollers have teeth or raised forms on its face. The falling

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Figure 7.9  Roll crusher.

material is drawn into the gap between the rollers by their rotating motion. The two rollers force the material between their rotating surfaces into the gap area and crush the material by compressive forces of the rotating rolls. This crusher is mostly used for primary crushing. The gap between the two rollers can be adjusted to change the size of the final product. Screen Crushed coal from crusher is screened to segregate the oversize and required size coal. Screen is used for this. Screening surface is having many apertures or holes with uniform dimensions. Normally, screening surface is made of steel wire woven cloth. A drive motor vibrates the screening surface. Crushed coal is fed into the top deck of the vibrating screen and passes through the surface of screen; undersize materials pass through and oversize materials retain. According to the aperture size of the screen, product size is obtained. Different factors affect the efficiency and performance of a screen. Some of the main factors are listed below:

• • • • • • •

Particle size Feed rate Screen angle Particle shape Screening area Vibration Moisture content

There are different types of screen depending upon the way the deck is vibrated. Some common types of screen used in coal handling plant are discussed below: • Vibrating screen:  Unbalance weight motors are mostly used to obtain vibration in vibrating screen. Unbalanced or eccentric discs are attached to a rotating shaft. Due to this eccentric weight, vibration is produced. Depending upon the motion of the screen, they are classified as linear or circular motion screens. The amplitude of the vibration depends on the weight and eccentricity of the mass attached to the shaft and speed of the motor. The vibration produced throws the material forward and upon the screening surface. The particles smaller than the screen aperture size are screened out when they fall.

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High frequency vibrating screen has a fixed frame and the drive mechanism vibrates only the screen cloth. The vibration of screen is achieved by unbalanced discs attached on the shaft of the vibrating motor. These vibrator arrangements are mounted above the screening surface and are connected by rods directly to it. • Resonance screen:  In normal vibrating screen, screen vibrates in accordance with the frequency of the applied vibrating force. But, in case of resonance vibrating screen, the vibration frequency is same as the natural frequency of the screen frame. Like other screen, resonance screen is a horizontal screen having a screen frame with a natural frequency. The vibrating energy is obtained by an unbalanced motor or disc. When frequency of the applied vibrating energy coincides with the natural frequency of the screen frame, the amplitude of vibration is maximum and it is called resonance. Various vibrating methods are adopted in resonance screen. • Flip-flow screen:  In flip flop or flip flow screen, the screening surface is made of flexible polyurethane mats having specific aperture size. During screening process, these flexible mats are individually stretched and relaxed cyclically. So, adhesive bonds within the materials and between the material and screen mats break or loosen. Coal with high moisture content can be screened by this screen.

7.4.3  Coal Pulverisation For pulverised coal-fired boilers, coal is fed to the pulveriser units from the coal storage bin. Pulverised system is classified as follows:

• Central system • Individual system In individual system, each burner is connected with its own pulveriser.

Individual System This system is divided into two types—closed drying system and open drying system. Close drying system:  As shown in Figure 7.10, coal from the storage bin is fed to the pulveriser mill through a coal feeder. Depending upon the boiler load, feeding rate to the mill is adjusted. Hot primary air is given to the mill to dry the coal and to carry pulverised coal in the feeding pipe upto the burner.

Figure 7.10  Individual close drying pulverising system.

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Open drying system:  In this system, high temperature flue gas taped from economiser outlet (before air heater) is used to dry the coal and carry the coal dust upto cyclone separator (Figure 7.11). Coal dust is separated from this flue gas at cyclone separator. The separated coal dust is collected and stored in an intermediate bin.

Figure 7.11  Individual open drying pulverising system with intermediate bin.

After cyclone, flue gas passes through a dust collector where the remaining coal dust is trapped. The coal dust-free gas is then sent to flue gas path (after air heater). The fuel stored in the intermediate bin is transported to the burner with the help of hot air supplied by the FD fan. This air acts as primary air. It is clear from the above discussion that in the closed drying system, primary air is used for drying, carrying and support burning. But, in case of open drying system, coal is dried with help of flue gas. Carrying and burning is done by primary air. In open drying system, coal is dried with high temperature gas, so the quality of fuel improves. But, in this case, some coal dust passes through the dust collector to the atmosphere. Central System In this system, all the equipments used in the individual system are used. But the capacity of these equipments is higher, as one system is used for all the burners. The coal dust after cyclone (as discussed in open dried system) is stored in a central bin. From this bin, fuel is supplied to individual burners with the help of primary air. In this case each burner does not have a separate pulveriser mill. So, the capacity of the mill and other related equipments is more and the operate at an optimum level. Detailed discussion about pulveriser is already made in the previous chapter.

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7.5  HANDLING OF OTHER SOLID FUELS Some solid fuels other than coal are used as a fuel in the boiler. Nowadays, we can find a lot of biomass and municipality solid waste-fired boilers. Biomass consists of organic residues from plants and animals which are obtained from agriculture and processing of agricultural and forestry crops. These are used as a fuel in the boiler. In India, following types of biomass are used normally as a fuel in the boiler for power generation:

• • • • • • • • • •

Wood chips Sawdust Rice husk Rice straw Corn straw Wheat straw Groundnut shell Soya shell Bagasse Cotton stalks

Biomass is available as loose or as briquettes. Briquetting is a process in which biomass is compressed to form blocks of different shapes for easy transportation, storage and use. These materials are transported to the plant through trucks or tractor and are stored in a storage area. In sugar plants, bagasse is used as a fuel in the boiler for steam generation. Bagasse is the fibrous residue of the cane stalk left after crushing and extraction of juice. It consists of fibres, water and relatively small quantities of soluble solids (mostly sugar). The average composition of bagasse is given below:

Fibre Moisture Soluble solids

48% 50% 2%

Net calorific value (CV) of bagasse = 18 309 – 31.1 S – 207.3 M – 196.1 A (expressed in kilojoule per kilogramme)

where S = soluble solids percentage M = moisture percentage A = ash percentage

Bulk density of bagasse is around 150 kg/m3. It is fed to the boiler through suitable means. Normally, a scraper type drag chain conveyor is used to discharge bagasse into multiple discharge points of the boiler. All the bagasse produced may not be used in the boiler. Also, for continuous operation of the boiler, it is required to be stored for future off season, as sugar cane is crushed seasonally. Same drag chain is used to store the bagasse at the storage area. During requirement, the stored bagasse can be reclaimed and fed to the boiler with help of bagasse return carrier. Bagasse feeders are used to feed the required amount of bagasse to the boiler. For easy storage of bagasse, balling is done. It is pressed into blocks called bales.

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These bales are prepared by baling press. Nowadays, bagasse is used along with coal in the fluidised boiler for the generation of power in most of the sugar plants. Municipal solid waste (MSW) typically consists of household waste, light commercial and industrial wastes. Incoming trucks deposit the refuse into pits where crane mixes these refuse and removes any bulky or large non-combustible items. The refuse storage area is maintained at lower pressure than that of the atmosphere in order to prevent any odour. Crane feeds the refuse to the combustor charging hopper to feed it into the boiler. The waste is sized properly as per the requirement before feeding into the boiler.

EXERCISES 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13.

14. 15. 16. 17.

What is day tank? Name the pipeline at which the oil pressure control valve is placed. How is HFO heated? Why is tracer provided in HFO line? How is the pressure of HFO controlled? What are the main components of a conveyor belt system? What are the functions of snub pulley and take-up pulley? What is troughing idler? What are the main safety and protection features provided in the belt system? Which safety device is used to stop the conveyor belt from any location along the belt during emergency? What are the functions of magnetic separator and metal detector? What are the main safety features provided in a bucket elevator? What is difference between centrifugal discharge elevator and continuous discharge elevator? What are the types of coal feeder used in a coal handling plant? What are the main types of coal crusher used in a coal handling plant? Mention the factors affect that performance of screen. How does flip flow screen work?

Chapter

8

Air Path

8.1  INTRODUCTION Oxygen is required for the combustion of fuel. Oxygen is obtained from the atmospheric air. As discussed earlier, certain theoretical quantity of air is required to burn a fixed quantity of fuel (schoichiometric quantity). If more air is supplied to the boiler, then heat loss takes place. Also, less air leads to incomplete combustion of fuel. So it is an important task for an engineer to decide the exact quantity of air so as to optimise the heat loss and the complete combustion of fuel. Air used for burning of fuel in the boiler furnace is heated prior to its supply into the boiler. This preheated air is supplied to the boiler as primary and secondary air. In most cases, forced draught (FD) fan is used to supply air into the boiler (Figure 8.1). In some boilers, primary air (PA) fan and secondary air (SA) fan are also used. Induced draught (ID) fan is used to evacuate the hot flue gas from the boiler.

Figure 8.1  Boiler air path.

All the related topics of air path are discussed in this chapter one by one.

8.2  BASICS OF FAN Fan is a critical equipment used in a power plant. It is used to produce air flow. Different types of fans like ID, FD, PA, SA, Seal air fan, etc. are used in a boiler. Fans may be classified as centrifugal fans or axial flow fans. 129

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Centrifugal Fan In centrifugal fan, air flows through an inlet duct to the centre or eye of the impeller which forces it radially outward into the volute or spiral casing from which it flows to a discharge duct. The air changes its direction while entering and leaving the fan. A centrifugal fan is suitable for smaller flow rate and a large pressure rise. Centrifugal fans are available in following types (Figure 8.2):

• Radial • Forward curved • Backward curved

Figure 8.2  Different types of centrifugal fans (a) Forward curved; (b) Backward curve and (c) Radial.

Radial fan is simple in design. This fan is suitable for high static pressure (upto 1400 mmwc) application and can handle dusty air at high temperature. Forward curved fan is used to handle clean air at lower temperature. It is suitable for large volume of air with low pressure. Backward inclined fan is more efficient than a forward curved fan. Axial Flow Fan Axial flow fan has runner and guide vanes in a cylindrical housing. Air passes through the runner without changing its direction while entering and leaving. In general, an axial flow fan is suitable for larger flow rate with relatively small pressure. Axial fans are available in following types:

• Tube axial • Vane axial • Propeller

8.2.1  Affinity Laws Fan exhibits following characteristics called as affinity laws:

• Flow is linearly proportional to the fan speed.

or

Q1 N1 = Q2 N 2

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• Pressure changes with the square of the ratio of speeds. P1 N12 = P2 N 22

or

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• Power consumption changes with the cube of the ratio of speeds. kW1 N13 = kW2 N 23

or

where, Q is the flow, P is the pressure, N is the speed and kW is the power consumption.

Efficiency of fan = Volume (m3 /s) ¥

Total pressure (mmwc) 102 ¥ Shaft input power (kW)

8.2.2  Fan Curve Fan curve is a characteristic curve of fan that shows a relation between the fan static pressure and the air flow rate (Figure 8.3). Fan curve changes with the change in fan speed, impeller diameter or blade pitch.

Figure 8.3  Fan curve and system resistance curve.

8.2.3  System Resistance Curves The system resistance is the sum of all pressure losses in the duct, elbows, dampers, valves and any other device that resists air flow. System resistance curve graphically represents how a system reacts to a given air flow (refer Figure 8.3). This curve changes with the change in system resistance. It is required to control the air flow of fans. The following flow control methods are normally adopted in a power plant.

• Speed control (variable frequency drives) • Damper control method

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Guide vane control method Variable speed (scoop tube) hydraulic coupling Fan blade pitch control method (only for axial flow fans) Pulley size changing method Parallel operation

Speed Control (Variable Frequency Drives) In this method, speed of the fan is adjusted by a variable frequency drive (VFD). By adjusting the frequency through VFD, speed of the induction motor and hence, the fan air flow can be adjusted. As shown in Figure 8.4, to increase the air flow from QA to QB, the speed of the fan is increased from NA to NB. The resistance curve remains the same. Only the fan curve changes.

Figure 8.4  Speed control method.

This type of control is very efficient. Variable frequency drive is an energy efficient method of air flow control. A lot of electrical power can be saved in this method. Also, the regulation is very smooth. Air flow can be adjusted to a very close limit. Damper Control In this method, fan speed remains constant throughout the operation. The resistance of the system is varied by adjusting the damper position. To increase the air flow, resistance of the system is decreased by opening the damper. So, the resistance curve in this case changes. As shown in Figure 8.5, to increase the air flow from QA to QB the resistance curve is to be lowered from curve RA to curve RB. The damper is operated pneumatically, hydraulically or electrically. The power cylinder of the damper in case of pneumatic or hydraulic operated damper requires special attention. Guide Vane Control The fan operates at constant speed and the flow is controlled by varying the pitch of the adjustable inlet vanes at the fan inlet.

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Figure 8.5  Damper control method.

Variable Speed (Scoop Tube) Hydraulic Coupling The position of the scoop of hydraulic coupling is adjusted to adjust the power transmission from driving motor to the fan. Accordingly, the fan speed and hence, the air flow changes. Details about variable speed hydraulic coupling is discussed in Chapter 9 (Feedwater path). Fan Blade Pitch Control Sometimes, axial flow fans with variable pitch blades are used to control the air flow. Pitch of the blades can be hydraulically or pneumatically controlled. Variable pitch blades modify the fan curve. Pulley Size Changing Air flow can be changed by changing the fan speed. If the fan is driven by a V-belt arrangement, then the fan speed can be increased or decreased by changing the size of the drive pulley or driven pulley. Parallel Operation Air flow can be controlled by parallel operation of fans. During low load, only one fan can be used and during high load, additional fan can be put in operation. Fans, blowers and compressors are used for gas flow. So, sometimes, confusion arises that how to differentiate them. They are differentiated by the pressure developed. As per American Society of Mechanical Engineers (ASME), the ratio of the discharge pressure to the suction pressure is used for defining the fans, blowers and compressors.

• Fans • Blowers • Compressors

upto 1.11 1.11 to 1.20 more than 1.20

8.3  FD FAN FD fan is used to supply combustion air to the boiler. Prime mover of the fan is normally

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an electrical motor having fixed or variable speed. Dampers are provided at the suction and discharge side of the duct. During starting of fan, the motor takes high current. To limit the loading of fan, suction and discharge side dampers are kept closed. Fresh air from the atmosphere is supplied to the boiler through FD fan. As the fan handles cold air, so the fan size is smaller as compared to ID fan which handle the hot flue gas. In a boiler where both ID and FD fans are used (balanced draft), ID fan is started first before FD fan. Some boilers have two FD and two ID fans. This type of boiler is called as multipass boiler. Depending upon the load condition, both the fans share load. Condition of the fan is to be regularly monitored to ensure continuous trouble free operation. Damper is provided at both suction and discharge side of the fan. These dampers are operated pneumatically, hydraulically or electrically. Wire mesh is provided at the suction side of the fan to restrict entry of large size particles to the fan. Discharge of fan is connected to the boiler with an air duct. Following steps are followed while starting a FD fan:

• • • • • • • • • • •

Check no maintenance job is going on. Ensure power supply is available. Check lubrication in the bearings are available. Ensure suction and discharge dampers are closed. Check smooth operation of the dampers from control room. Check the condition of suction side air mesh. Ensure inspection doors at the air duct are closed. Put the fan in sharing or independent mode. Start the fan and check current, sound and vibration. Open the discharge damper fully. Open the suction damper as per the requirement.

8.3.1  FD Fan Air Flow Control Depending upon the load variation in the Boiler, fuel supply and hence, the air for combustion is controlled. So, it is always required to adjust the air flow in a boiler depending upon the load. Air flow is controlled by adopting earlier discussed methods. Following two methods are widely used to control the air flow:

• Speed control • Damper control

In both the cases, air flow controller is put in automode so that as per the requirement speed of the fan or the damper position can be adjusted automatically.

8.4  AIR HEATER (OR AIR PREHEATER) Earlier it is told that the air supplied for combustion in a boiler is supplied by FD fan and is preheated at air heater before supplying to the boiler combustion chamber.

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Air preheating is helpful in the following ways:

• • • • • •

Improves combustion Increases thermal efficiency Decreases fuel consumption Increases steam generation capacity Stabilises fuel ignition Greater load flexibility

Also, hot air is used for coal drying and conveying in a pulverised boiler. Air is preheated in an equipment called air heater or air preheater which is placed at the exit end of the flue gas path after economiser. There are two types of air preheater. These are as follows:

• Regenerative air preheater • Recuperative air preheater

Regenerative Air Preheater (RAPH) Rotating plate type regenerative air preheater (RAPH) is used in large capacity boiler due to its compactness. It captures the heat of exhaust flue gas by passing it over the heat absorbing metallic elements and then, dissipates this heat to the combustion air. Heat absorbing elements are installed within a casing that is divided into two (bisector), three (trisector) or four (quadsector) sectors. The elements placed in the sector housings are renewable. Rotor of the air heater is rotated at slow speed by a motor. Elements alternately come in contact with hot flue gas and cold inlet air (from FD fan). These heat transfer elements pick up heat from the hot flue gas and dissipate it to the cold air. Whole air preheater casing is supported on the boiler supporting structure and connected to the flue gas duct through expansion joints. The vertical rotor is supported on thrust bearings at the lower end. Sealing arrangement is done to avoid leakage of flue gas or air between the sectors or between the duct and the casing while in rotation. To avoid uneven expansion and contraction, it is required to start the rotation of RAPH before starting of the boiler and keep it rotating for some time after the boiler is stopped. Trisector RAPH (Figure 8.6) is commonly used in a pulverised boiler. Here, a single heat exchanger is used to heat both primary air (which dries and transports coal from coal mill to  furnace) and secondary air (which is used at furnace for combustion).

Figure 8.6  Trisector regenerative air preheater.

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Recuperative Air Preheater Recuperative air preheater is generally called static air preheater. This is a shell and tube type heat exchanger. The flue gas flows inside the tubes and air flows at the shell side. Due to very low heat transfer co-efficient between the flue gas and air, the heat transfer surface of the air heater is large. A very simple air heater is shown in Figure 8.7. This is a single flow type air heater. To get an optimal air velocity, baffles are placed. In some cases split flow type air heater is used. Here, air is distributed into two or more separate flows. Airbox is required where there is a change in the direction of air flow. Cold air from the FD fan enters to the air heater at the exhaust end of the flue gas and leaves at the inlet end of the flue gas (cross flow). The air flow path is partitioned to get an optimal air velocity. Flue gas flows in single flow or split flow scheme depending upon the boiler capacity.

Figure 8.7  Recuperative or static air preheater.

The air gets heated and the flue gas gets cooled gradually. There is always some difference in the temperature between air and flue gas at the inlet and exhaust end of the air heater. This difference is called as temperature gradient. Due to more moisture content in flue gas as compared to air, the gradient is more at the exhaust end than the gradient at the gas inlet end (Figure 8.8).

Figure 8.8  Temperature gradient in air heater.

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137

Heat transfer is given by a equation which is as follows:

Q = UA(DT)m

where U = overall heat transfer coefficient A = heat transfer area (DT)m = log mean temperature difference Flue gas temperature towards the outlet of air heater is less, so there is a chance of corrosion there. The dew point of sulphuric acid is around 140 °C. The exact dew point is calculated as per Verhoof equation. As per this equation, the dew point of sulphuric acid depends upon the partial pressure of SO3 gas and H2O (water vapours) present in the flue gas. SO3 gas (which is formed due to the combustion of sulphur present in the fuel) reacts with moisture in the flue gas and forms sulphuric acid. So, mostly the gas outlet end of the air heater is corroded. During low load this temperature is very less. So, chance of acid formation is more in this condition. To avoid this situation, sometimes, steam coil preheater is used.

8.4.1  Steam Air Heater As discussed earlier, the flue gas temperature at the exit end of air heater is low, as cold air enters this end. This end is prone to severe corrosion due to sulphuric acid dew point. So, it is required to heat the air to some extent before entering it into the air heater. Steam coil air preheater (SCAPH) is the best solution in this case. In this method, air is preheated by low temperature steam. Combination of steam air heater and air heater is called as combined air heating. Low temperature corrosion at the air heater can be avoided in this arrangement. In steam heater, steam at around 120 °C to 150 °C is used. Steam flows in the coil and air passes over these coils and gets heated (Figure 8.9). The steam after cooling is condensed. This condensate is collected and reused in the boiler. The steam used here is normally of low pressure and is obtained from the turbine bleed or process waste.

Figure 8.9  Steam air heater.

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8.5  Primary Air and Secondary Air Oxygen is required for combustion and it is obtained from atmospheric air. Total air supplied to the boiler combustion chamber is divided into two parts. The first part is called as primary air. Primary air supports the flame and takes part in the initial combustion process. The second part is called as secondary air. This air is admitted into the furnace to create turbulence and ensure complete combustion of the fuel (Figure 8.10).

Figure 8.10  Primary and secondary air.

In case of pulverised coal-fired boiler, primary air is used to carry the pulverised coal into the furnace. In FBC boiler, primary air is required for fluidisation and to carry the fuel and secondary air is supplied over the bed for combustion. In case of oil and gas-fired boilers, primary air supports the flame and secondary air is used for complete combustion of fuel. In stoker and grate-fired boilers, primary air is supplied below the fuel bed.

8.6 Excess Air It was discussed earlier that to burn certain amount of fuel, some theoretical air is required. It is given by

4.35[(8/3 C + 8H2 + S) – O2] kg

This is the theoretical air required. But, in practice, some more air or extra air is supplied to ensure complete combustion of the fuel. If more air is supplied, then there will be a cooling effect and the efficiency will decrease. Also, if less air is supplied, then complete combustion will not take place. Combustible substances will escape from the stack. Again, there will be a loss in efficiency. So, it is required to adjust the air supply in such a way that complete combustion will take place without much extra or excess air. Excess air supplied can be measured by an oxygen analyser that measures the oxygen percentage in the flue gas. It should be monitored online for better control. Excess air monitoring is done for efficient use of fuel. Sometimes, CO2 and CO present in the flue gas is measured. The flue gas should contain CO2, not CO.

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It is to be kept in mind that excess air and excess oxygen are not same. Air has roughly 21% oxygen by volume. So, 100% excess air is approximately equal to 10.5% oxygen remaining at the boiler exhaust stack. Excess air percentage can be calculated as

Excess air percentage = Oxygen percentage in flue gas 



For 4% oxygen, excess air percentage = 4 ¥

100 (21 - Oxygen percentage)

100 = 23.5% (21 - 4)

Excess air requirement of different boiler is not same. This is mentioned in Table 8.1. Table 8.1  Excess Air Requirements of Different Boilers Type of Boiler Gas-fired Oil-fired Pulverised coal-fired Stoker-fired

Excess Air

Oxygen Percentage (by volume)

5%–10% 10%–15% 15%–20% 20%–30%

1% –2% 2% –3% 3% –3.5% 3.5%–5%

EXERCISES What is the stoichiometric air fuel ratio? Why is the size of FD fan smaller as compared to an ID fan? What are the two main types of fan? What are the affinity laws of a fan? Define fan curve. When does it change? What is system resistance curve? What happens to it when the fan damper is closed? Why is speed control method preferred over damper control method? Which speed control methods are adopted to control the flow of a fan? What is the difference between a fan, blower and a compressor? Which fan is started first—ID or FD? What is balanced draft? What is a multipass boiler and what is its merit? What are the merits of preheating of combustion air? What are the two types of air preheater? Where is the regenerative type air heater used? Why is the rotation of a regenerative type air heater started before starting of a boiler and continued for some time after the boiler is stopped? 17. Why is the heat transfer surface of a air heater so large?

1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16.

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18. Why is the temperature gradient at gas exhaust end higher than the temperature gradient at gas inlet end in an air heater? 19. What is acid dew point? How is it related with Verhoof equation? 20. What is the use of a steam air heater? 21. What do you understand by primary and secondary air? 22. Why is excess air avoidable in a boiler? 23. What is the relation of excess oxygen and excess air?

Chapter

9

Feedwater Path

9.1  INTRODUCTION Heat produced by combustion of fuel in a boiler is transferred to the feedwater and steam is generated. So, feedwater is the medium to receive heat. Heat transfer takes place from the hot flue gas to the feedwater. If it is a water tube boiler, flue gas moves outside the boiler tube in which feedwater flows. In case of smoke tube boiler, hot gas flows inside the tube which is surrounded by feedwater. To extract heat from the flue gas, feedwater flows continuously in the boiler. As steam is taken out from the boiler continuously, so it is required to pump feedwater continuously into the boiler. In this chapter, it is discussed how feedwater circulates in a boiler. All the related topics pertaining to feedwater path are discussed in this chapter. In Figure 9.1, a standard feedwater path is shown. Mostly, it is common for all type of boilers.

Figure 9.1  Normal feedwater path of a boiler.

9.2  DEAERATOR As discussed in the previous chapter, boiler feedwater is free from suspended solids, minerals and dissolved gases. Mostly, DM water is used in a boiler as feedwater. In case of steam turbine power plant, the steam used to drive turbine is condensed in a condenser and then, this condensate is used again as feedwater. So, the feedwater path is a closed loop path. Only some make-up is required to make up the blowdown and leakage losses. Feedwater used in the boiler should be free from any dissolved gases and oxygen. Deaerator is used for this. 141

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The main function of a deaerator is to deaerate or remove dissolved gases (degasification) from the feedwater. Also, it serves the purpose of a storage tank from where feedwater is pumped into the boiler. It is the place where feedwater is preheated before entering into the boiler. To preheat the feedwater, low pressure steam is utilised. LP dosing is also done here for removing dissolved oxygen from the water. There are many types of deaerator. Commonly used, direct contact (mixing) tray type deaerator is discussed here.

9.2.1  Tray Type, Direct Contact Deaerator In this type of deaerator, water enters from the top. Water is distributed through a set of nozzles, as shown in the Figure 9.2. Water falls into the bottom storage tank from the deaerator column through the perforated trays and small droplets are formed. Low pressure steam is supplied to the steam distributor. This steam moves up in the deaerator column and comes in contact with droplets of the feedwater. Feed water is heated upto the boiling point corresponding to the deaerator pressure. Due to the formation of small water droplets, the contact surface exposed to steam increases which results in complete removal of the dissolved gases.

Figure 9.2  Tray type direct contact deaerator.

By heating the water, dissolving capacity of gases in the water decreases. So, dissolved gases are removed from the water easily. These removed gases along with some non-condensing vapour present in the steam, is vented to the atmosphere through a vent. The vent is fitted with an orifice and a bypass valve. The deaerated water is collected in a tank called as storage tank. If still there is some dissolved gas which is not removed at the deaerator column,

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143

then it is removed here due to large surface area of the heated water. Initially, when feedwater is at normal temperature, heating steam is used to heat the water. Level gauge is fitted in the deaerator to indicate the storage tank level. Level is maintained through a level control valve and deaerator pressure is maintained through a pressure control valve by controlling the flow of steam to the deaerator. One safety valve is provided to take care of accidental overpressure. For maintenance of the deaerator, it is required to drain out water from the storage tank. A drain with suitable isolating valve is provided for this. To facilitate thermal expansion of the deaerator, one end of the storage tank is fixed through suitable fixing arrangement. When boiler feed pump is in operation, low pressure is created at suction end of the pump. There is a chance of steaming of feedwater, as water is at higher temperature. This is called as cavitation. If pressure at suction side of the feed pump falls below saturated pressure, this situation may arise. To avoid this situation, deaerator is placed at a higher level. If the deaerator pressure is 3 kg/cm2 and the deaerator is placed at an elevation of 20 m, then the feed pump suction pressure will be approximately 5 kg/cm2.

9.3  BASICS OF PUMP Before discussing about the boiler feed pump, some basics of pumps are discussed here for easy understanding of the reader. In a power plant, pumps are used to transfer fluid. Different types of pumps are used for different applications. Pumps are mainly classified into following two types:

• Centrifugal pump • Positive displacement pump

9.3.1  Centrifugal Pump Centrifugal pump is the most common type of pump used in a power plant. In a centrifugal pump, energy of a prime mover is utilsed to convert into velocity or kinetic energy and then, into pressure energy of a fluid. Fluid enters through inlet port to eye or centre of the rotating impeller. The rotating impeller throws the fluid tangentially due to centrifugal force. The energy created by the centrifugal force is the kinetic energy which is proportional to the velocity at the edge or tip of the impeller. Velocity at tip of impeller increases when impeller speed or impeller size is increased. At stationary volute or diffuser, the fluid is decelerated and its velocity is converted to pressure according to Bernoulli’s principle. When fluid leaves the eye of the impeller, a low pressure area is created and more fluid flows into the inlet. Main Components of a Centrifugal Pump The main components of a centrifugal pump are given below: • Impeller:  Impeller is the rotating part. It is fitted to the drive shaft that rotates inside the pump casing. The impeller is designed to impart a whirling or motion to the liquid in the pump.

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Impellers are classified in different ways as per their design. – Radial flow – Axial flow – Mixed flow – Single suction – Double suction – Open type [no shrouds to enclose the vanes (Figure 9.3)] – Closed type [shrouds enclosing the vanes (Figure 9.3)]

Figure 9.3  (a) Open type impeller and (b) Close type impeller.

• Stages:  The number of impellers determines the number of stages of the pump. – Single stage pump has just one impeller and is used for low pressure service. – Multistage pump has more impellers mounted in series for high pressure service. • Shaft:  The main purpose of the shaft is to support the impeller and other rotating parts and transmit power of the prime mover. The shaft should be strong enough to transmit the power without deflection. • Shaft sleeve:  Renewable shaft sleeve is used to protect the shaft from erosion, corrosion and wear at the seal chambers, internal bearings, etc. When required, the sleeve is only changed without changing the pump shaft. • Coupling:  Coupling is used to connect driving motor shaft with pump shaft. Couplings are available in following two groups: – Rigid coupling – Flexible coupling Flexible couplings can compensate axial and radial mismatch between both shafts to some extent. Rigid couplings are used in applications where there is no possibility of any misalignment. Different types of couplings are discussed in Chapter 21. • Casing:  Pump casing creates resistance to the fluid and decelerates it. Here, velocity of fluid is converted into pressure. Pump casing is available in following two types: – Volute casing – Circular or diffuser casing

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A volute is a curved funnel whose size increases towards the discharge end. As the size of the volute increases, velocity of fluid reduces and the output pressure increases. A volute casing pump builds higher head. Single volute and double volute type casing are used (Figure 9.4).

Figure 9.4  (a) Single volute type casing and (b) Double volute type casing.

Circular casing has stationary diffuser vanes around the impeller which convert velocity energy into pressure energy (Figure 9.5). This type of pump is generally used for higher capacity.

Figure 9.5  Circular or diffuser casing.

Casings are either solid or split type. Solid casing is made in one piece while split casing is made in two or more parts fastened together. The casing is either horizontally (axially) split or vertically (radially) split. Suction and discharge nozzles are the integral parts of the casing. According to the position of suction and discharge nozzles, the pumps are classified as follows: – End suction and top discharge – Top suction and top discharge – Side suction and side discharge • Wear ring:  Impeller of the pump has to rotate freely within the pump casing. So, a small clearance is kept between them. Leakage from high pressure or discharge side of the pump to the low pressure or suction side through this clearance should be minimum for efficient

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performance of the pump. Wear takes place at this clearance area due to erosion caused by liquid and clearance increases. When clearance between them becomes more, water leakage increases and the pump efficiency decreases. To avoid the replacement of costly impeller and casing, wear ring is provided. Wear ring is replaceable which is attached to the impeller or the pump casing to allow a small running clearance between the impeller and the pump casing without causing wear of the actual impeller or pump casing material. This wear ring is replaced when the clearance increases. • Gland:  Gland seals arrest leakage where the shaft passes through the casing. Either mechanical seal or gland packing is used for this sealing. The space between the shaft and casing is called chamber. This chamber is called as seal chamber if mechanical seal is used in the pump. The chamber is called as stuffing box if gland packing is used. Shaft sleeve is used at this glad area to avoid wear of the pump shaft. Gland packing or the mechanical seal is properly fit to the shaft sleeve. Seal flush, quench, cooling, drain and vent connection ports are provided at the gland. • Bearing housing:  The bearing housing encloses bearing that keeps the shaft in correct position. Oil reservoir for lubrication, oiler and cooling jacket are provided in the bearing housing. • Cavitation:  When impeller rotates, it creates low pressure area at suction side of the pump. If the pressure at that area falls below the saturation pressure of the fluid corresponding to the fluid temperature, then the fluid flashes to vapour. This process of formation of vapour bubbles in a pump is called as cavitation. Cavitation creates small bubbles on the leading edge of the impeller vane. During cavitation, discharge pressure and the flow rate fluctuate. It causes pump vibration which may damage pump bearings, wear ring and seals. Cavitation can easily be detected from the abnormal noise in the pump. • Net positive suction head:  To avoid cavitation in centrifugal pump, the pressure of the fluid at suction side of the pump should remain above the saturation pressure. The term net positive suction head (NPSH) is used to determine if the pressure is sufficient to avoid cavitation or not. The term net positive suction head  required (NPSHR) is known as the minimum suction head required by the pump to avoid cavitation. Net positive suction head available (NPSHA) is given as the difference between the actual suction pressure and the saturation pressure of the fluid. To avoid cavitation, net positive suction head available (NPSHA) should be more than the net positive suction head required (NPSHR).  Suction pressure of the pump is the sum of the absolute pressure at the surface of the fluid in the tank plus the pressure due to the elevation difference between the surface of the fluid and the centre of the pump. Some pressure drops due to friction in the suction pipeline. NPSHA for different suction conditions are discussed below where the symbols have following meaning:

LS, LH = Suction lift/head (in metre) Pb = Barometric pressure (in metre absolute) P = Pressure of Fluid tank (in metre absolute) VP = Vapour pressure of the fluid at pumping temperature hf = Friction loss in suction line (in metre)

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– Fluid tank open to atmosphere with suction lift:  It is shown in Figure 9.6.

NPSHA = Pb – (VP + LS + hf)

Figure 9.6  Fluid tank open to atmosphere with suction lift.

– Fluid tank open to atmosphere with positive suction:  It is shown in Figure 9.7.

NPSHA = Pb + LH – (VP + hf)

Figure 9.7  Fluid tank open to atmosphere with positive suction.

– Pressurised fluid tank with suction lift:  It is shown in Figure 9.8.

NPSHA = P – (VP + LS + hf)

Figure 9.8  Pressurised fluid tank with suction lift.

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– Pressurised fluid tank with positive suction:  It is shown in Figure 9.9.

NPSHA = P + LH – (VP + hf)

Figure 9.9  Pressurised fluid tank with positive suction.

Centrifugal Pump Characteristic Curves The pump curve describes the relation between flow rate and head developed by the pump (Figure 9.10). When flow rate is more, head of the pump decreases. The pump curve moves upward with the increasing impeller diameter or speed of the pump. Head and flow rate increase. Shutoff head is the head produced when the pump operates with fluid but discharge valve is closed. This is the maximum head that is developed by a particular centrifugal pump. Pump run out is the maximum flow  that  is obtained from a centrifugal pump without damaging the pump.

Figure 9.10  Pump curve.

System Curve This is the curve which indicates the resistance to flow or loss of head (Figure 9.11). Throttling valve and reducing the pipe size increase head loss and move the system curve upward. The operating point is where the system curve and the actual pump curve intersect. In practice, characteristic curve shows flow, total dynamic head, brake horsepower, efficiency and net positive suction head as shown in Figure 9.12. The effect of change in pump speed or impeller diameter upon flow, head developed and power consumed can be calculated. The pump affinity laws show the effect of changing speed or diameter of the impeller of a pump on the flow rate, head and power consumption.

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Figure 9.11  System curve. Figure 9.12 Typical system and pump performance curves.



•

Q2 N 2  Q1 N1

or



•

H 2 N 22  H1 N12

or



•

P2 N 23  P1 N13

or

D2 D1 D22

D12 D23

D13

where, Q is flow, N is speed, D is the diameter of impeller, H is the head developed and P is the power consumption. Pump hydraulic power (kW) is given by Q  (Hd – Hs)  r  g/1000 where Q = flow (in cubic metre per second) Hd – Hs = total head (in metre) r = density of fluid (in kilogramme per cubic mitre) g = 9.81 m/s2 Multistage Centrifugal Pumps High pressure is developed in a single centrifugal pump by the multistaging of the impeller. Multiple impellers are fixed on a common shaft within the same pump casing. Internal channel of the pump casing is so arranged that the discharge of one impeller becomes suction of another impeller. A pump stage consists of one impeller and its associated components.

9.3.2  Positive Displacement Pump The positive displacement pump operates by alternatively filling a cavity and then, displacing a given volume of fluid in each cycle. The positive displacement pump delivers a constant volume of fluid, irrespective of any discharge pressure or head. So, this type of pump is called as constant flow pump. It is used for high pressure (HP) and low pressure (LP) chemical dosing.

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A relief or safety valve on the discharge side of the positive displacement pump is installed internally or externally to protect the pump and pipeline from overpressure. The positive displacement pump can be classified as follows: 

• Reciprocating pumps (piston, plunger and diaphragm) • Rotary pumps (gear, lobe, screw, vane)

9.4  Boiler Feed pump A boiler feed pump is a critical equipment used in a boiler house which supplies deaerated and LP dosed feedwater to the boiler. This pump has to pump feedwater into the boiler drum against the boiler drum pressure. So, discharge pressure of this pump is higher than the boiler drum pressure. Normally, feed pump is a multistage pump driven by electrical motor or turbine. In a large boiler, where steam generation capacity is more, more feedwater is required to be pumped. In this case, turbo feed pump is preferred. Also, turbo feed pump is having another merit. During non-availability of power, turbo feed pump can pump feedwater into the boiler, by utilizing steam of the boiler. So, starvation can be avoided. During the starting of a boiler, motor driven feed pump is started and after steam generation at the boiler, feed pump is switched over to the turbo driven one. Feed pumps are kept in hot standby. In case of failure of one pump, standby pump starts automatically. Non availability of water in a running boiler creates an unsafe condition. In this condition, there is no water to cool the tubes, so its temperature increases severely and it may deform, rupture or explosion may take place. So, in case, boiler feed pumps are not available, boiler is to be stopped immediately. Suction pipe of the boiler feed pump is connected to the deaerator storage tank through an isolation valve and a strainer (Figure 9.13). The suction strainer restricts entry of foreign material

Figure 9.13  Boiler feed pump.

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151

into the pump. To monitor the chocking condition of the strainer, differential pressure across the strainer is monitored. When differential pressure (DP) is more, it indicates the strainer is chocked. Two mechanical seals are provided at both ends of the pump to avoid leakage from the shaft end. These mechanical seals are cooled with the help of external cooling water directly or indirectly. As the boiler feed pump pumps hot deaerated water, so its shaft also becomes hot. Cooling water is required to cool the bearings of the pump. The discharge line of the pump has a pneumatic or motor operated control valve. A non-return valve (NRV) is provided to restrict back flow of feedwater. When there is no pressure in the discharge line, the pump is started with the discharge valve in closed position. A disc is fitted to the discharge end of the shaft of pump which is acted on by the discharge pressure of the water to counter axial force of the impeller. This is called balance disc. The liquid leaking from the balance disc is sent back the deaerator through balancing pipeline. Multistage pump cannot be operated at zero discharge (when discharge valve is closed). Some minimum flow is required to avoid the damage of the pump. To ensure minimum flow of boiler feed pump at any operating condition, automatic recirculation valve (ARC) is provided. When feed pump flow becomes less than the required minimum flow, ARC opens and the water discharged is recirculated to the deaerator through minimum circulation pipeline. For trouble-free, reliable operation of the feed pump, pump vibration, bearing temperature, pump casing temperature and pressure are checked regularly. Boiler feed pump is a critical equipment of any boiler. So, proper care is to be taken during starting and normal operation of the pump. Following steps may be followed during starting of the pump:

• • • • • • • • • • •

Ensure power is available to the feed pump. Check availability of cooling water for gland cooling and bearing cooling. Ensure the suction valve is in open condition and discharge valve in closed position. Keep balancing line and minimum circulation line valve in open condition. Check suction pressure of the pump. Check bearing lubricating oil level. Start the feed pump and observe any abnormal sound or vibration. Check bearing and pump casing temperature. If everything is found normal, open the discharge valve slowly. After discharge valve is fully opened, start taking feedwater into the boiler. Put the standby pump in hot standby.

9.5  BOILER DRUM LEVEL CONTROL In a boiler, feedwater is evaporated continuously and the steam generated is taken out. So it is required to pump that much water into the boiler to keep water level in the boiler within the safe limit. With the help of boiler feed pump, this level is maintained in a steam drum. In this drum, both steam and water exist. Some boilers are having one drum and some have two drums (bidrum boilers). In bi-drum boilers, one is steam drum and other one is called mud drum (Figure 9.14). Mud drum is placed at the bottom portion of the boiler. Evaporator tubes are connected between these two drums.

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Figure 9.14  (a) Single drum boiler and (b) Bidrum boiler.

Once through boilers do not have steam or mud drum. So, drum level control is not required in these boilers. To maintain drum level in the drum type boiler, drum level controller is used. This controller controls the flow of feedwater to the boiler by a feed control valve. There are three types of level controllers. These are as follows:

• Single element controller • Two-element controller • Three-element controller

When steam is taken out from the boiler, drum level of the boiler drops. Automatically, signal is given to the feed control valve to allow that much water so that the previous level can be maintained. Feed control valve receives signal from the level controller. The control valve is normally pneumatic operated. The functions of different level controllers are discussed one by one here. Single Element Level Controller In single element level controller (Figure 9.15), only drum level is measured. When drum level is less than the desired level, then control valve opens and allows feedwater to the boiler.

Figure 9.15  Single element level controller.

This type of controller is used in small boilers where load fluctuation is less.

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Level of the drum is disturbed for some other reasons also. If the drum pressure decreases due to sudden steam drawl, then water swells and level becomes high. When drum pressure increases due to sudden load throw, then shrinking takes place and drum level becomes low. Single element controller is unable to compensate these effects, as it only operates depending upon the drum level. Two-Element Level Controller In this type of controller (Figure 9.16), the swelling and shrinking effect of boiler drum is taken care. Pressure of the drum varies according to the steam flow. If load increases, then the steam flow increases and the drum pressure drops. In two-element controller, this effect is compensated by measuring the steam flow along with the drum level.

Figure 9.16  Two-element level controller.

Steam flow gives an incorrect feedback if it is not compensated suitably according to the steam pressure and temperature. Flow of steam has a direct relationship with pressure and temperature. So, in most of the cases, measurement of steam flow is compensated by the pressure and temperature. This type of controller is used in medium size boilers with moderate load variation. Three-Element Level Controller Three-element level controller (Figure 9.17) is used widely. This controller can take care of any type of boiler and any type of load variation. Normally, in this case, the feedwater flow and steam flow are pressure and temperature compensated.

Figure 9.17  Three-element level controller.

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In two-element controller, controller does not consider how much feedwater is entering into the boiler. So, the controller action is not smooth. An ideal controller should take into account how much feedwater is flowing to the boiler so that further corrective actions can be initiated. The boiler feedwater from feed pump is used for the final steam temperature control (attemperation). Sometimes, this flow is also considered in three-element controller for smooth functioning.

9.5.1  Drum Level Control in Larger Capacity Boiler In larger capacity boiler, feed pump motor is coupled with a pump through a hydraulic coupling with variable scoop tube arrangement for variable speed and effective drum level control. This arrangement provides stepless speed variation of the pump with a fixed speed electrical motor. Scoop tube arrangement provides advantages like no-load starting of motor, controlled starting torque, stepless speed variation and load limiting in a very wide range for the safety of motor and pump. In this coupling, the transmission of power from the drive motor to the boiler feed pump takes place with the help of fluid (generally oil). No direct mechanical connection is there between the motor and the pump shafts. The coupling consists of a radial pump impeller mounted on the motor shaft and a radial flow reaction turbine runner mounted on the pump shaft. Both the impeller and runner are identical in shape and they together form a casing which is completely enclosed and filled with oil. When motor shaft is rotated, the oil starts moving from the inner radius to the outer radius of the pump impeller. This oil enters the runner of the pump shaft. The oil while flowing through the runner, transfers its energy to the blade of the runner and the pump shaft rotates. The oil from the runner then flows back into the pump impeller and continuous circulation takes place. The position of a scoop tube regulates oil flow in the circuit. By adjusting the scoop tube position, oil flow in the working circuit and hence, the torque transmission capacity of the coupling varies. The position of a sliding scoop tube is adjusted automatically through suitable actuator and can also be adjusted manually. Following two methods are adopted for the operation of scoop to control the drum level:

• Differential pressure (DP) mode • Three-element mode

Opening and closing of feed control valve is done as per three-element drum level controller to maintain the drum level. DP is the difference between the pump discharge pressure and the boiler pressure and is measured across the feed control valve. At constant speed pump, discharge pressure falls as the feedwater flow increases. To take care of this problem, scoop is operated in DP mode (Figure 9.18). The scoop is adjusted automatically to adjust the pump speed to regulate the pump discharge pressure around 7 kg/cm2–10 kg/cm2 above the boiler drum pressure. Due to throttling operation of feed control valve, energy loss is more in this mode of operation. This mode of operation is normally adopted in case of emergency or fluctuating load conditions. In case of three-element mode, feed control valve is kept wide open and scoop is adjusted automatically by three-element controller to adjust the pump speed and maintain the drum level (Figure 9.19).

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155

Figure 9.18  Scoop operation in differential pressure.

Figure 9.19  Scoop operation in three-element mode.

9.6  FEED CONTROL STATION We to know that feedwater from the boiler feed pump is sent to the boiler through a feed control valve. Normally, there are two control valves. One is for lower load and another is for higher load. One manual bypass valve is also provided for emergency. In some boilers, both the control valves are capable for 100% load. Anyone is selected for the operation and another is kept as standby. Control valves are provided with two manual isolation valves at both sides for maintenance flexibility. The area where these valves are located is named as feed control station (Figure 9.20). Mostly, this section is kept nearer to the boiler.

Figure 9.20  Feed control station.

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9.7  ECONOMISER Economiser is used to utilise the fuel economically or make the boiler economical. Hot exhaust flue gas from the boiler which would have gone to the atmosphere, is used to increase the efficiency of the boiler. This is a heat exchanger in which flue gas flows in a shell arranged with water tubes. Heat of flue gas is utilised to increase the temperature of water so as to increase sensible heat of water. It is found that by decreasing the exhaust flue gas temperature by 16 °C, boiler efficiency increases by 1%. Also by increasing the feedwater temperature by 6 °C, boiler efficiency increases by 1%. With the help of an economiser, exhaust flue gas temperature can be decreased and feedwater temperature can be increased. After economiser, hot flue gas enters into the air heater. The temperature drop is permissible to such an extent so that the flue gas temperature does not come down below the dew point. It would be more uneconomical if we would design to drop the flue gas temperature without economiser at the boiler itself for the generation of steam. In an economiser, the heat transfer is more effective due to high temperature difference between the feedwater and the hot gas. The economiser heating surface is around 25% to 40% of the boiler heating surface. As the sensible heat of water increases with the help of an economiser, so steam generation can be made quicker. Normally, feedwater temperature is increased close to saturation temperature corresponding to the boiler drum. The difference between the flue gas outlet and the feedwater inlet temperature is around 40 °C–50 °C. There is a significant pressure drop at economiser. Inlet pressure of the feedwater at an economiser is more than that of the outlet of the economiser due to pressure drop. So, the feed pump should be capable to overcome this pressure drop to supply water into the boiler drum. Normally, small size tubes are used for an economiser. Sometimes, finned tubes are used to increase the effective heating surface. There are two types of economiser. They are as follows:

• Boiling or steaming type • Non-boiling or non-steaming type

In a non-boiling type economiser, feedwater temperature is less than the saturation temperature corresponding to the economiser pressure. Whereas, in case of a steaming economiser, feedwater temperature is more than the saturated temperature corresponding to the economiser pressure. As shown in the Figure 9.21, an economiser consists of a series of tubes connected between the two headers. Flue gas passes over these tubes and heat transfer takes place. One vent is

Figure 9.21  Economiser.

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157

provided at the outlet header of the economiser for air venting during initial filling. Inlet header is connected to the feed control valve and the outlet header is connected to the steam drum. In an economiser, low temperature corrosion takes place, particularly at the cold end. It is to be ensured during operation that the cold end temperature does not drop below the acid dew point (140 °C).

9.8  EVAPORATOR Feedwater from the economiser enters into the boiler drum. Water temperature is still less than the saturated temperature. Some more heat is to be added to it for steam formation. This heat is added at the evaporator and steam is formed there. Evaporator tubes are mostly placed at radiation and convection zone of the boiler. Feedwater circulates in these tubes naturally due to the difference in the density of hot and cold water. Water from the drum comes down to the bottom distributor through down comer tube (Figure 9.22). From this bottom distributor, water is distributed to the raiser tubes, normally placed at the furnace wall (water wall) or front portion of the bank tubes at the convective zone. Here, water gains heat and moves upward to the drum. In this course, steam is formed and collected at the drum.

Figure 9.22  Arrangement of evaporator tubes.

In single drum boilers, down comers are connected to the bottom distributor header and distributed to the raisers and the water wall tubes. In case of bidrum boilers, both drums are connected through a bank of down comer and raiser tubes. Also, from the lower drum, water is distributed to the water wall. As discussed earlier, density difference between the cold and hot water is the driving force for the natural circulation in the evaporator tubes. Thermal head created, circulates water in the boiler (Figure 9.23). Other than the density difference, this thermal head depends upon the resistance of the tube and boiler pressure also.

Figure 9.23 Head created in natural circulation.

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Net driving head of circulation in a boiler is given by F = H(PC – PH)



where H = height of the water level in the boiler drum PC = density of water PH = density of steam water mixture. This driving force has to overcome the resistance of down comer and the raiser tubes. The driving force depends upon the boiler pressure. When pressure increases, density of steam water mixture increases (Figure 9.24). At critical pressure, density of water is equal to the density of steam water mixture. So, net driving head becomes zero and the natural circulation stops. At that condition, forced circulation is required.

Figure 9.24  Driving head.

Steam generation at evaporator tubes is not constant always. Depending upon the boiler load (heat input) and circulation ratio, it varies always. Circulation ratio is the ratio between weight of the water entering the down comer to the weight of steam leaving the circuit.

9.8.1  Water Wall As the name suggests, in a water wall, water tubes are arranged around the boiler furnace. These tubes are placed in such a way so that they form a gas tight wall. In the furnace openings (manholes, burner ports), these tubes are arranged suitably. There are different types of water walls depending upon the type of the tube arrangement. These are as follows:

• • • •

Bare tube Finned tube Welded or rectangular finned tube Bare tube with intertubular space filled with building up material

Nowadays, factory fabricated membrane panels are widely used. Fins are welded in between tubes to form a wall-like structure called as membrane panel (Figure 9.25). At the bottom portion of the furnace, water wall is bent to make an ash collection hopper. The water wall is terminated to the lower and upper header.

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Figure 9.25  Water wall (memberance panel).

Water wall is insulated by insulating material at the atmosphere end to minimise the radiation loss. Sometimes, refractory-faced water wall is used as shown in Figure 9.26.

Figure 9.26  Refractory-faced water wall.

In once through boiler, there is no drum. Natural circulation of water does not take place. In this boiler, water walls are arranged around the boiler furnace. For uniform heating, tubes are sectionalised. These tubes are either arranged horizontally or vertically. Feedwater from the boiler feed pump enters the boiler directly. It circulates through so many parallel paths. Total steaming process takes place in these tubes and the steam is collected at a header and is taken out.

9.8.2  Boiling Principle Steam is produced due to the boiling of water. So, it is very important to know actually how water boils in a boiler tube. Heat is added to the boiler water which flows inside the boiler tube. When water is heated in a boiler tube, it starts boiling. Boiling is the vaporisation process that takes place when a liquid is heated to its boiling point corresponding to the vessel pressure. Boiling occurs in three stages inside the tube, as mentioned below:

• Nucleate boiling • Transition boiling • Film boiling

Nucleate Boiling Nucleate boiling is a local boiling (at tube wall liquid interface) which takes place when the wall temperature of the tube is more than the saturated fluid temperature. Nucleate boiling is characterised by the formation of steam bubbles on the tube wall. Steam bubbles are formed

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at liquid–solid interface when the wall temperature rises above the saturation temperature but the liquid temperature is still below the saturation temperature. The bubbles grow until they reach some critical size. At this point, they separate from the wall and are carried into the main liquid stream. The bubbles collapse there because the temperature of liquid is not same as the tube where the bubbles were formed. The heat of bubbles is transferred to the liquid. So, heat of tube wall is carried directly into the fluid stream. The number of nucleation area increases with the increase in wall temperature. Two different flow regimes are noticed in the nucleate boiling. In first case, bubbles formed at nucleation areas are separated from the surface. Due to this separation, fluid comes in contact with the tube wall and convective heat transfer coefficient increases. In this regime, most of the heat transfer is through direct transfer from the surface to the liquid in motion and not through the steam bubbles formed at nucleation areas. In the second case, more nucleation sites are observed. More bubbles of larger size are formed. These bubbles come closer and merge to form slugs of vapour. These two flow regimes of nucleate boiling are shown in Figure 9.27.

Figure 9.27  Wall to water temperature difference.

Transition Boiling Transition boiling is a stage in between nucleate and film boiling having features of both of these stages. In this stage, the liquid periodically comes in contact with the tube wall, creating a large amount of steam vapour and forcing the liquid away from the surface, creating an unstable vapour film or blanket. Then, this film collapses and the liquid comes in contact with the tube wall again. Film Boiling If the tube wall temperature is significantly higher than the water, then more bubbles are created and film boiling takes place. Bubble formed  does not carry away to the liquid.

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The bubbles grow in size and group  together.  Small area of the tube wall surface is covered with a film of steam vapour. This is known as  partial film boiling. In this stage of boiling process, the wall surface is totally covered by a film of steam vapour and the liquid does not come in contact with the wall. This thin layer of vapour which has low thermal conductivity, insulates the surface. So, the temperature of the tube increases dramatically. This   situation continues until the affected surface is covered by a stable blanket of steam, preventing contact between the heat transfer surface and the liquid in the centre of the flow channel. The condition after the formation of stable steam blanket is known as  film boiling.

9.9  BLOWDOWN Due to the continuous evaporation of boiler water, salt concentration in the boiler water increases. Also, due to phosphate treatment, some non-adherent sludge is formed. So, total dissolved solids (TDS) level of the boiler water increases. To adjust this total dissolved solid level, some quantity of boiler water is removed from the boiler and the same quantity of fresh water is added. By doing so, concentration of non-desirable dissolved salts is maintained. This process is called blowdown process and the water drained out is called blowdown. Blowdown quantity in a boiler is calculated by the following formula: Percentage blowdown 

TDS fw TDSblr  TDS fw

 100

where TDSfw = TDS level of feedwater and TDSblr = permissible TDS level of boiler water EXAMPLE 9.1  Permissible limit of the boiler water TDS of a 250 t/hr boiler operating at 120 kg/cm2 is 70 mg/L. If the TDS of boiler feedwater is 5 mg/L, then calculate (i) percentage blowdown and (ii) Blowdown quantity. Solution

 5  (i) Percentage blowdown =   100  7.7%  70  5 



 Percentage blowdown  (ii) Blowdown quantity     Evaporation quantity  100  7.7    250  1000  100   19250 kg/hr

Blowdown may be continuous or intermittent. In continuous blowdown, some quantity of boiler water is continuously taken out from the boiler drum and continuous fresh water make up is given. In this method, the salt concentration is maintained constant as shown in Figure 9.28.

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Figure 9.28  TDS level in case of continuous blowdown.

In case of intermittent blowdown, blowdown is given from the bottom mud drum to remove the settled sludge. Boiler water salt concentration is monitored regularly. Blowdown is given for a short duration when concentration level goes beyond a predetermined value. And blowdown is stopped at a recommended lower concentration level. The concentration level varies between higher and lower limit, as shown in Figure 9.29.

Figure 9.29  TDS level variation in case of intermittent blowdown.

Due to blowdown, some loss of energy takes place, as the blowdown water contains significant amount of sensible heat. The loss is significant when blowdown quantity is more. Suitable arrangement is made to utilise the sensible heat of this blowdown water. Blowdown water is collected from the boiler drum through a header placed just below the normal water level of the steam drum. Water is drained through a flash tank. In flash tank, the pressure of water drops significantly. As the water contains a lot of sensible heat corresponding to the drum pressure, so flash steam is produced. This steam can be utilised suitably. Normally, this steam is used in the deaerator for feedwater heating. Before draining out the blowdown water, heat can be removed from this water by placing a heat exchanger (Figure 9.30).

9.10  GAUGE GLASS Gauge glass is a glass tube or a pair of flat glass plates fitted to the boiler drum to provide a visual indication of the water level of a boiler drum. Through this device, water level and general condition of the water in a boiler is determined. This glass is manufactured from highly chemical and corrosion resistant low expansion borosilicate glass. This glass is well known for its clarity and mechanical strength. The gauge glass may be flat type or reflex type (prismatic glass). It is easier to observe water level in a boiler in flat gauge glass design. Reflex gauge has a single vision slot in which light can enter the gauge chamber to determine the liquid level. One side of the glass is prism-shaped.

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Figure 9.30  Blowdown system.

The gauge glass conforms to internationally recognize standards. Arrangement is made to avoid danger due to the breakage of glass and causing hazard. The glass is fitted in a heavy metallic body. In case, the glass breaks, a safety ball closes water and steamside port due to the sudden flow of fluid. This arrangement is shown in the Figure 9.31. Gauge glass needs to be kept clean to ensure that water level indicated in the gauge glass accurately represents the water level of the boiler, as gauge glass is the only means to visually verify the water level in the boiler. Glass should be regularly checked for any signs of clouding, scratching, erosion or corrosion. Any blockage in either waterside or steamside of the gauge glass may show false level. So, it should be flushed regularly in order to keep the glass and piping connections clean and free of sludge or sediment. For this, the gauge glass is to be flushed as per the following procedure:

• Close the water cock and open the drain cock for some time. • Close the drain cock and open the water cock.

Water should return to its normal working level quickly. If this does not happen, then there is a blockage in the waterside.

• Close the steam cock and open the drain cock for some time. • Close the drain cock and open the steam cock.

If the water does not return to its normal working level quickly, then there is blockage in the steamside. For the initial line up of gauge glass, following procedure is to be followed:

• Check steam cock, water cock and drain cock are in closed position. • Open the drain cock.

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Figure 9.31  (a) Gauge glass arrangement and (b) Gauge glass internals.



• • • •

Crack open the steam cock. Wait for some time till the gauge glass is heated slowly. Crack open the water cock. Close the drain cock. Open the steam cock and water cock fully.

It is difficult to distinguish between a completely full and completely empty gauge glass. In this situation, following procedure may be helpful. For this, a little practice is required.

• Hold a pencil against the far side of the sight glass at an angle of approximately 45°. If the image of the pencil viewed through the glass appears to run across the glass and changes little with the change in angle of the pencil, the glass is full [Figure 9.32(a)]. However, if the image viewed through the glass runs up and down the glass at a sharper angle than the actual angle of the pencil, the tube is empty [Figure 9.32(b)].

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165

• Practice this difference with normal water level before an emergency by viewing through the sight glass above and below the water line.

Figure 9.32  Physical verification of (a) Full glass and (b) Emplty glass.

9.11  HYDRASTEP Hydreastep is an electronic type drum level indicator and level switch. It comprises of the following units:

• • • •

Electronic unit Water column Electrodes and electrode cables Local and remote display

Multiple probes are fitted to a water column to measure the resistances of steam and the water. The resistances of steam and water are different. The water column is attached to the boiler drum through steam and water connection piping like gauge glass. Each probe is connected with separate cable to an electronic unit. In the electronic unit, the signal obtained by the probes are discriminated whether the resistance is less (representing water) or more (representing steam). In the display unit, clear indication of water level is shown as per the exact water level in the boiler drum. The number of probes and the spacing between them can be chosen to cover the required sight range. Generally, 8 to 32 probe models are available. Some relay outputs are available in hydrastep which can be used to generate a trip or alarm signal. Each relay can be set to operate at any predetermined water level. Other than the main display unit, some remote display units can be installed for control room indication or at other places in the plant. Also, 4 mA–20 mA output proportional to the drum level is obtained to connect to the DCS system.

9.12  WATERSIDE SCALING AND CORROSION Scaling and corrosion are two undesired phenomena in a boiler. Boiler tube life is shortened due to this. These are discussed in detail here.

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9.12.1  Scaling Highly pure feedwater also contains very small amount of dissolved salts and impurities in it. Due to continuous evaporation of boiler water, concentration of these salts increases. The retrograde solubility (inversely proportional to temperature) characteristic of some salts decreases with the increasing temperature and concentration. These dissolved salts separate from the water when the boiler water is heated and stick to the waterside of the boiler tube, resulting into scale formation. The main disadvantage of this deposited scale is that it reduces heat transfer which leads to overheating of tubes and loss of efficiency. Improper treatment of feedwater or boiler water and some operational practices are responsible for scale formation. Some of these reasons are discussed below:

• Precipitation of insoluble salts in boiler water forms hard scale on the inside surface of the tube if allowed adhering to it. • Inadequate removal of suspended solids from the boiler water by blowdown results in more solids concentration. When this high concentrated water comes in contact with the tube wall, possibility of scale formation increases. • A thin film of boiler water immediately adjacent to the heating surface, becomes more concentrated than the boiler water. This is responsible for scale formation in that area. • Accumulation of iron and copper oxides (from corrosion byproducts) not only forms deposits but also acts as a binder for other suspended solids in the boiler water. • Condenser tube leakage contaminates condensate with hard cooling water which can lead to boiler scale formation. • Localised high heat flux due to improper burner alignment can cause hot spots and overheating of tubes, leading to increased concentration of boiler water impurities in that area which ultimately results in scale formation. • When boiler is operated above its rated capacity, it may cause high metal temperature which can result scale. At low load condition, water circulation reduces which affects cleanliness and cooling of the hot tube surfaces.

Scaling takes place mainly due to the presence of calcium and magnesium salts (carbonates or sulphate) which are less soluble. Also, high concentration of silica in boiler is responsible for the scale formation. The most common scale in boilers is due to carbonate deposits. Carbonate scale is usually granular and sometimes, very porous.  A carbonate scale can be easily identified by dropping it in a solution of hydrochloric acid. Bubbles of carbon dioxide are formed from the scale. Sulphate scale is harder and denser. Silica scales resemble porcelain. This scale is very brittle, in soluble in acid and dissolves slowly in alkali. Some of the common constituents responsible for the formation of deposition and scaling are given below:

• • • •

Calcium (Ca) Magnesium (Mg) Phosphate (PO–3 4) –2 Sulphate (SO4 )

Feedwater Path 





• • • •

167

Bicarbonate (HCO–3 ) Silicate (SiO–44 ) Carbonate (CO–2 3) Iron (Fe)

Effects of Scale Formation



• Thermal conductivity of scale is similar to the insulating brick. Scale acts as an insulating layer and prevents heat transfer from the tube to the circulating water. Due to inadequate cooling, boiler tube metal temperature increases and results in softening, bulging or even fracturing of the boiler tubes. • Scale in boiler tube reduces circulation through tubes and affects cleaning effect, causing further scale formation. • Boiler scale can cause plugging or partial obstruction of circulating tubes in a boiler which causes starvation and overheating of the tubes.  • Scale deposit may not be sufficient to cause tube failure but its insulating effect reduces boiler efficiency and energy wastage due to carryover of excessive heat from the boiler with the flue gas. • Deposits may also lead to differential corrosion cells under their surfaces, causing localised corrosion or pitting. If this corrosion is severe, boiler metal may become thinned and weakened leading to tube failure.

Scale formation inside the boiler tube affects the heat transfer and reduces the boiler efficiency. Regular cleaning of tube internal surface is required to remove the scale from the tube. Periodically, acid cleaning of pressure parts removes deposited scale from the boiler and increases the boiler efficiency. Boiler Descaling by Acid Cleaning For the removal of scale from the boiler, acid cleaning method is adopted. Following two methods of acid cleaning are used for descaling of the boiler:

• Circulation method • Fill and soak method

In circulation method, acid at low concentration is circulated inside the boiler. A sample of the scale deposit is analysed to select the most suitable acid for descaling. Following acids are used for descaling of the boiler tube:

• • • • • • • •

Hydrochloric acid Phosphoric acid Hydrofluoric acid Nitric acid Sulphuric acid Citric acid Oxalic acid Sulphamic acid

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Normally, hydrochloric acid solution of 5%–10% (pH 2–3) is preferred widely. Deposits like iron oxide, calcium and magnesium salts, carbonates and phosphates can be easily removed by hydrochloric acid. Following cleaning aids are also added to the acid for effective cleaning: • Corrosion inhibitor:  Corrosion inhibitor is added to prevent acid attack to the base metal but allows the acid to remove unwanted corrosion and scale deposit. • Wetting agents, emulsifiers, Surfactants or detergents:  It increases spreading and penetrating properties of the liquid by lowering its surface tension and allows the liquid to spread more easily across any solid surface. • Dissolution accelerators:  It accelerates scale removal during acid cleaning. Procedure of circulation method acid cleaning:  The procedure of acid cleaning by circulation method is given below:

• The boiler should be in depressurised condition. • Make temporary arrangement to disconnect non-drainable superheater to avoid entry of chemical into it. Isolate boiler feedwater pump, feed control valve and gauge glass. Remove safety valves from the drum and close the flange. • Connect a temporary drain pipe at flange of one safety valve and bring it to the acid mixing tank. • Connect a temporary pipeline from the bottom blowdown header to the discharge of the acid recirculation pump, as shown in Figure 9.33.

Figure 9.33  Acid circulation arrangement for descaling.



• Install a non-return valve on the discharge of circulating pump to avoid the back flow of acid in case the pump fails.

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169

• Fill up water in mixing tank and start the pump. Add water until the boiler is full and water starts to return to the mixing tank. • The mixing tank should only be half full to avoid overflow. • Add acid and all other additives to the mixing tank. • When acid reacts with scale, its strength drops. Monitor acid strength of the return solution. When acid level drops, add more acid to the mixing tank. • The procedure is stopped when the acid strength remains constant. This indicates that no more scale removal is taking place. • Drain out acid solution from the boiler and mixing tank. Neutralise this before draining to the nearest drain. • Take fresh water in the mixing tank and circulate to flush the tube internal thoroughly. • Add some alkaline solution (ammonia, sodium hydroxide or hydrazine) with water to neutralise any residual acid. • Once neutralised, drain and inspect the boiler. If necessary, flush with high pressure water jet to remove any loose sludge. • Return the boiler to normal operating condition by disconnecting the temporary arrangement. Replace all gaskets, open main steam stop valve and other valves which are closed during acid circulation. • If the boiler is not taken into service after acid cleaning, then the boiler must be passivated using passivation agents like sodium phosphate, hydrazine or nitrites. • Give manual blowdown more often for next 2–3 days to remove any loose scale that might have lodged at the bottom of the boiler.

In fill and soak method, boiler pressure parts are filled with inhibited acid solution and are allowed to soak for  an estimated  time. After some period, the acid solution is drained out and flushed. Neutralisiton is done by adding some alkaline solution. It is not possible to obtain an accurate representative sample of the cleaning solution during soaking period. So, this method is not adopted in larger boilers.

9.12.2  Corrosion Boiler tube is made of carbon steel and alloy steel. Most significant contributors to the boiler waterside corrosion are dissolved oxygen, acid or caustic in water and high temperature. If any of them are uncontrolled, severe pitting, gouging and embrittling of the tube metal can occur which can ultimately lead to failure. The following reaction takes place for corrosion in a boiler: 3Fe  4H 2 O  Fe3O 4  Iron

Water/steam

Magnetite

4H 2 Hydrogen gas

Corrosion compounds are divided roughly into two types—red iron oxide (Fe2O3) or hematite and black magnetic oxide (Fe3O4) or magnetite. Red oxide (hematite) is formed under oxidising conditions. Black oxide (magnetite) is formed under reducing conditions that typically exist in an operating boiler.

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The magnetite layer prevents further corrosion. So, in a new boiler, this layer is desirable. Weakening or damaging of this protective layer may lead to further corrosion of the boiler tube. Proper internal boiler water treatment can repair this layer. Some Important Causes of Corrosion • Dissolved oxygen:  Dissolved oxygen is removed at the deaerator. When deaeration is not proper, dissolved oxygen enters the boiler and corrosion takes place in the form of severe deep pits, mostly at the water level in the steam drum. This can be identified during inspection. • Acidic attack:  If boiler water pH drops significantly below 8.5, a phenomenon called waterside thinning can occur. Mostly, the stressed area is prone to this attack. • Caustic embrittlement:  Caustic embrittlement (intergranular corrosion) in boiler is a form of stress corrosion cracking. It is caused due to high concentration of caustic alkalinity and stressed conditions. Caustic embrittlement attacks the grain boundaries within the crystalline structure of the metal. Caustic does not attack the crystals themselves but rather travels between the crystals.

9.13  PRIMING, FOAMING AND CARRYOVER Priming Priming means carryover of water particle in the steam which lowers the energy efficiency of the steam and leads to scale formation at superheater and in the turbine blade. Priming may be caused due to the following reasons:

• • • • •

High water level Foaming of feedwater Sudden fluctuation in steam demand High impurities concentration in the boiler water Improper construction of the boiler

High water level is the common cause of priming. To avoid priming, high water level, excessive boiler load and sudden load change should be avoided. Carryover During carryover, contaminant leaves a boiler steam drum with the steam. It can be in solid, liquid or gaseous form. It is undesirable in a boiler. Some of the effects of carryover are mentioned below:

• • • •

Deposition in regulating and controlling valves Deposition in superheater Deposition in servomotor control valves and turbine blade Process contamination

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171

Carryover is due to the incomplete separation of steam from the steam–water mixture in the boiler drum. Steam separation units are placed inside the boiler drum. Defects on these separation units may lead to carryover. Foaming of boiler water is also responsible for carryover. Boiler design, type of mechanical steam separating equipment, load fluctuation, boiler drum level, amount of space available for steam separation from the steam–water mixture are some of the causes of carryover. Foaming Foaming is the formation of unbroken bubbles on the surface of the boiler water inside the boiler drum. The bubbles may be in  thin layer with few bubbles overlying each other or it may build up throughout the steam space. When these bubbles burst, moisture is entrained with the steam. Some of the causes of foaming are given below:

• • • •

High dissolved solid concentrations in the boiler water High suspended solid concentration High alkalinity concentration Oil and organic contaminants in the boiler water

EXERCISES

1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19.

What is the function of a deaerator? How is dissolved gas removed in a deaerator? What is the function of wear ring in a pump? What is cavitation? What is the difference between NPSHA and NPSHR of a pump? What are the affinity laws of a pump? What condition is indicated by differential pressure across the boiler feed pump strainer? Why is a balancing disc provided at the boiler feed pump? What is the function of ARC in a feed pump? What are the three types of drum level controller? What is three-element level controller? How is the drum level controlled in variable speed fluid coupling (scoop tube)? What is feed control station? Which factors affect natural circulation in a boiler? What is circulation ratio in a drum type boiler? What is water wall? What is nucleate boiling? What is the purpose of blowdown? What is difference between IBD and CBD?

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20. What arrangement is made to take care of emergency due to breakage of glass of gauge glass? 21. How can the blockage in waterside and steamside be tested in gauge glass? 22. What is the principle of operation of hydrastep? 23. What are the causes of corrosion in a boiler? 24. What is scale? How does it affect the performance of a boiler? 25. What are the two methods of acid cleaning in a boiler? 26. Which acid is used for acid cleaning of a boiler? 27. On what factor (s) does the selection of a suitable acid for cleaning depend? 28. What is the pH of acid solution that is maintained during cleaning process? 29. Why are cleaning aids used for acid cleaning? 30. What is the use of corrosion inhibiter? 31. What parameter is to be monitored to check the cleaning process? 32. When can the cleaning process be stopped? 33. Why is neutralisation required? 34. Which chemical is used for neutralisation? 35. What is priming? How does carryover take place due to this? 36. Why does foaming take place?

Chapter

10

Steam Path

10.1  INTRODUCTION In Chapter 9, it has been discussed how steam is formed. In a boiler, feedwater is circulated in evaporator tubes. Latent heat is absorbed by the water and steam is formed. This steam is collected at the upper portion of the boiler drum. This steam is still at saturated temperature. Water particles present in this steam can cause impurity carryover. Before taking steam out for further use, it should be dry and free from the impurities. For this, suitable mechanical arrangements are done inside the boiler drum. Superheated steam is used in most of the cases. To obtain superheated steam, further heat is added to the saturated steam. This is done at another set of tubes called superheater. To control the outlet temperature of the superheated steam, suitable arrangement is done.

10.2  STEAM DRUM In Chapter 9, it has been discussed that in drum type boiler, boiler water is circulated in the evaporator tubes for steam formation. Water from the drum comes down through downcomer tubes and gets distributed into the evaporator tubes. Heat is added at the evaporator tubes and steam is formed. This steam is collected at steam drum (Figure 10.1). Steam drum is a cylindrical-shaped container. It is located at the top of the boiler. It runs lengthwise and provides space for steam and water. Two manholes are provided at both ends for internal inspection during shutdown. Both water and steam exist at saturated temperature in the steam drum. Downcomer tubes and raiser tubes are connected to the drum. Steam coming from the raiser tubes may not be completely dry. It may contain water particles which may carry over the impurities present in boiler water. So, separation of steam and water particles is required. For this, drum contains various separation and purification internals. Steam drum also acts as steam and water storage tank. Drum contains water at saturated temperature. So a lot of latent heat is stored in water which helps during load fluctuation. Drum receives feedwater from the economiser. Steam is taken out and feedwater is added here. A blowdown header is provided in the drum to collect blowdown water for controlling impurity level of feedwater. HP dosing is also done at the boiler drum. One air vent with isolation valve is provided in the drum to release air during start-up. During starting when boiler water is heated, it swells. The air from the drum space is released gradually. When drum pressure becomes 2 kg/cm2, this vent is closed. This vent is opened during shutdown at 2 kg/cm2. 173

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Figure 10.1  Steam drum internals.

From the above discussions, it is clear that drum is a critical part of the boiler (except drumless once through boiler). A drum performs lot of functions that are summarised below:

• • • • • • • •

Supply water to the evaporator tubes and receive steam from the raiser tubes. Store water and steam. Take out dry saturated steam and add feedwater. Maintain the boiler water level. Separate steam and purify it through steam separators and purification parts. Give blowdown from the surface of the water. Add HP dosing chemical. Take care of load fluctuation, as alot of latent heat is stored in the boiler water.



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175

10.2.1  Drum Internals As told earlier, drum contains some internal fittings for steam separation and purification. Also, an arrangement is made inside the drum to distribute the feedwater and dosing chemical inside the drum. Details about the drum internals are discussed here. Feedwater Distributor This is a header connected to the feedwater pipeline from the economiser. This header runs lengthwise in a drum. This is perforated so that the water can be distributed evenly throughout the drum. This header is fixed to the drum through suitable fasteners (U-rod, etc.). Surface Blowdown Header This is a header connected to the drum blowdown pipe. Blowdown is given to maintain the impurity level of the boiler water. This header is normally placed just below the working water level of the drum. This header is also perforated so that the blowdown water can be collected evenly from the drum. Chemical Dosing Header As discussed earlier, phosphate dosing is done at the boiler drum. The pipeline from dosing pump is connected to a header fitted inside the drum. It also runs throughout the length of the drum and is perforated so that the chemical can be evenly distributed in the drum. Steam Separators and Purifiers Different methods of steam separation are used in the boiler drum. Among them, following methods are commonly used: By changing the direction of flow:  In this method, the steam direction is changed many times intentionally before leaving the drum. The heavy water particles cannot change direction so quickly as compared to the dry steam. So, they fall back in the shape of water droplets. By using baffles:  Steam and water mixture is allowed to impact on baffle plates placed in the moist steam path. Heavier water particles loose its kinetic energy and fall back. Only dry steam enters into the steam space. Cyclone separator:  In this method, separation of moisture and steam is done with the help of centrifugal force. Steam and water mixture is passed through a cyclone separator. The cyclone creates spinning action on the steam. Due to centrifugal action, heavier water particles are thrown away and collides at the cyclone wall and falls down. Steam scrubber:  Steam is allowed to pass through closely-spaced screens. Dry steam can easily pass through these screens and the water particles carried by steam are collected and fallen back by the gravity. Some boilers may have a number of screens called primary screen and secondary screens. These screens are called demister pad also. In some large boilers where the purity of steam is highly desired, another method of steam purification is employed. It is called as steam washing. In this method, the separated steam

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is rinsed with fresh clean feedwater. Dissolved silica and other contaminated impurities are washed away. The separated and purified dry saturated steam is taken out from the boiler drum. In most of the cases, this saturated steam is further heated to get superheated steam. Heat is added in a set of tubes called superheater. The temperature of saturated steam increases at superheater. The temperature difference between superheated steam and saturated steam is called as degree of super heat. The formation and properties of superheated steam are already discussed in Chapter 4. The advantages of superheated steam are discussed below:

• As superheated steam contains more heat, so it can do more work than the saturated steam at same pressure. • High temperature of superheated steam makes it higher thermal efficient. • There is a sufficient margin for the expansion in turbine before it cools down and becomes wet. • Superheated steam does not contain water particles (moisture). So, it is less erosive and corrosive than the wet steam.

10.3  SUPERHEATER Superheater is a set of tubes (Figure 10.2). Normally, a number of parallel tubes are connected between the two headers to minimise the pressure drop. One header is connected to the steam drum to receive saturated steam and another is connected to the outgoing pipe through main steam stop valve (MSSV).

Figure 10.2  Superheater.

Sometimes, superheater tubes are arranged vertically and sometimes horizontally. Condensate cannot be drained out completely from vertical superheater when boiler is in shut off condition. This type of superheater is called as non-drainable superheater [Figure 10.3(a)]. Proper care is required to be taken in this case during starting of the boiler. Vent of this superheater is to be opened during start-up so that the condensate can evaporate. Horizontal superheaters are arranged horizontally. Sufficient sloping is made so that the condensate formed at the superheater tube can be drained out completely. This type of superheater is called as drainable superheater [Figure 10.3(b)].

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177

Figure 10.3  (a) Non-drainable vertical superheater and (b) Drainable superheater.

The area of superheater heat transfer surface may be calculated as follows: A

M s (Ho  Hi ) T T   gi T  Tso  go  si   U 2 2 

where Ms = mass flow rate of steam Ho = enthalpy of outlet steam Hi = enthalpy of inlet steam Tgi = gas inlet temperature Tgo = gas outlet temperature Tsi, Tso = steam inlet and outlet temperature U = overall heat transfer coefficient between steam and gas. It changes with the change in gas flow rate. The superheater is subjected to high temperature. So, special alloy steel is used here. Alloy steel is high heat and corrosion resistant. The tube is alloyed with chromium, molybdenum, nickel, titanium, and niobium. Materials and standards of different grade superheater tubes are discussed later. Superheater is placed at the flue gas path at various zones to gain the heat from hot flue gas. Depending upon the mode of heat transfer, superheaters are classified as follows:

• Convective superheater • Radiant superheater • Platen superheater

Convective Superheater This superheater is placed at the convection zone of the boiler. Heat transfer takes place here mostly by the convective method. Radiant Superheater This type of superheater is located at the radiation zone of the boiler. Superheater tubes are exposed to the flame of furnace. Heat transfer is done mainly by the radiation method in this case.

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Platen Superheater This type of superheater is placed in such a location so that heat transfer can take place through the radiation and convection method. The superheater is located normally above the boiler furnace and starting of convection zone.

10.3.1  Outlet Temperature at Various Loads for Different Types of Superheaters Radiant superheater is placed at the radiation zone. It absorbs radiation heat. So, during low load period when steam flow through superheater tube is less, the outlet temperature remains high. As the load increases, more steam flows in the superheater tube, so the temperature of the steam falls down, as shown in Figure 10.4.

Figure 10.4  Outlet temperature at various loads for different types of superheaters.

In case of convective superheater, heat transfer to the steam takes place through convection method. This type of superheater is placed at the flue gas path. During low load, the volume of flue gas is less, as less fuel is fired in the boiler. So, the outlet temperature of superheated steam is less. When load increases, more fuel is fired in the boiler. So, the volume of flue gas increases. Hence, the outlet temperature of the steam also increases, as shown in Figure 10.4. But, in case of combined superheater, temperature is maintained constant at any load (Figure 10.4). So, this type of superheater is preferred in most of the cases.

10.4  METHODS OF SUPERHEATER TEMPERATURE CONTROL It is required to maintain the outlet superheated steam temperature within limit. The temperature is not allowed to fall below and raise more than a certain value. This range is very close when steam is used to drive a turbine. It is essential to maintain the temperature within limit to minimise thermal stress. When steam demand decreases suddenly, flow in superheater reduces and the temperature of steam increases. Like this, when flow increases in superheater due to sudden load demand, steam temperature decreases. To maintain the outlet steam temperature, some control is required. Various methods are adopted to control the outlet steam temperature. Some of these methods are discussed here.

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179

10.4.1  Gas Bypass Method In this method, flue gas path is bypassed with the help of a damper so that some quantity of flue gas does not flow through the superheater. During low load when steam flow is less in the superheater, by pass damper is kept open. Some quantity of flue gas is by passed. As less volume of hot flue gas flows through the superheater, the temperature of steam can be maintained constant during low load condition. During higher load, damper is closed and the entire flue gas is allowed to flow through the superheater. According to the desired temperature at certain load, the damper is set at a certain position (Figure 10.5).

Figure 10.5  Temperature control by gas bypass method.

The damper has to operate at a high temperature and erosive environment. So, high temperature corrosion, erosion and fatigue may take place. Draft loss in flue gas path is not always constant in this case. When damper is in closed condition, flue gas flows through the superheater. So, the draft loss is more in this condition. When the damper is in open condition, flue gas path is bypassed and the draft loss in this case is less.

10.4.2  Excess Air Control Method Air supply to the furnace can be increased or decreased to increase or decrease the superheated steam temperature. When it is required to increase the steam temperature, more air is supplied to the furnace than the normal requirement. Due to this excess air, heat absorption at furnace water wall decreases. So, the total heat contents in flue gas increase. More heat transfer takes place at superheater tube and the steam temperature increases. To decrease the steam temperature, air is reduced. So heat absorption at water wall increases. Heat contents in the flue gas decrease and the heat transfer to the superheater decreases as well. This type of control is mostly used where convective superheater is used.

10.4.3  Tilting/Adjustable Burner Control Method In this method, burner position is adjusted to control the superheated steam temperature.

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In this method, the burners are designed in such a way so that it can be tilted upward or downward. When burner is tilted downward, water walls receive more heat. So, less heat is available in the flue gas entering the superheater zone and the temperature of superheated steam reduces. When the burner is tilted upward, less heat is absorbed by water walls and more heat is absorbed by superheater. So, the steam temperature increases. Depending upon the requirement, burner may be tilted upward or downward (Figure 10.6).

Figure 10.6  Titling burner arrangement.

In some boilers, burners are placed at different elevations (tires) of the furnace. During low load when furnace exit temperature is less, upper tire burners are taken into service. So, the flue gas temperature at furnace exit (superheater inlet) and the steam temperature increase. During higher load, lower tire burners are taken into service along with upper tire burners (Figure 10.7) so that the furnace exit temperature is maintained constant.

Figure 10.7  Multitier burner arrangement.

Both the above control methods are very effective to control the superheated steam temperature.

10.4.4  Separately-Fired Superheater Method In this method, there are two furnaces. The radiant superheater is placed in another furnace and the convective superheater is placed in between the common flue gas path of both, i.e.,

Steam Path 



181

main boiler furnace and superheater furnace (Figure 10.8). The superheated steam temperature can be controlled by adjusting the firing rate of both the furnaces.

Figure 10.8  Separately-fired superheater.

10.4.5  Flue Gas Recirculation Method To control the steam temperature, the flue gas exhausted from the economizer is circulated back to the boiler furnace with the help of a fan. This gas acts as an excess air method of control, as discussed earlier. If more gas is recirculated, heat absorption at water wall decreases and the superheated steam temperature increases.

10.4.6  Coil Immersion in Boiler Drum In this method, some part of the superheated steam is passed through a coil immersed in the boiler drum. A bypass valve is provided to control the flow of steam to the drum (Figure 10.9).

Figure 10.9  Coil immersed in boiler drum.

When the temperature of steam is high, bypass control valve is closed. So, more steam is passed through the coil immersed in the boiler drum and the temperature of steam is controlled. When the temperature of steam decreases, bypass control valve is opened. Most of the steam passes in the bypass line and the temperature increases.

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10.4.7  Desuperheating or Attemperation Method Attemperation is a commonly used method to control the superheated steam temperature. In this method, cold condensate (normally boiler feedwater) is sprayed directly to the superheated steam. Sometimes, superheated steam is cooled in a heat exchanger where the steam flows in coil and feedwater flows in the shell. Both these methods are very effective. The superheater is divided into two sections called primary superheater and secondary superheater. Attemperator is placed between primary and secondary superheaters. So, temperature control can be done very effectively. Also, the chances of moisture in steam are eliminated, as after attemperator the steam passes through secondary superheater. The two methods of temperature control, i.e., spray type attemperator and surface type attemperator are briefly discussed below: Spray Type Attemperator In this case, feedwater from the boiler feed pump is sprayed directly to the steam coming out from the primary superheater through a nozzle. Here, the temperature of steam reduces. This steam then passes through the secondary superheater. If outlet temperature of secondary superheater is high then the control valve allows more spray water through nozzle to reduce temperature (Figure 10.10). The temperature control valve is put in automode so that the spray water quantity can be adjusted automatically.

Figure 10.10  Arrangement of spray type attemperator.

In spray type attemperator, the spray nozzle is fitted to the steam header with suitable pipe connection (Figure 10.11). Feedwater is connected to this pipe. A metallic protective jacket

Figure 10.11  Spray type attemperator.

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183

is provided at the header and the length of this jacket is around 4 m to 5 m. Feedwater is sprayed to the steam with the help of a nozzle. The spray water evaporates completely at the end of the jacket. So, hot main steam header does not come in contact with this water and thermal shock is avoided. Sometimes when purity of steam is important, then in that condition, feedwater cannot be sprayed directly because when it mixes with steam, chances of steam contamination are emerged. In this case, instead of direct feedwater spray, saturated steam from boiler is condensed and this condensate is used for spray. This method minimises the steam contamination. Surface Type Attemperator In this system, feedwater is not mixed with superheated steam. Temperature of steam is controlled by varying the feedwater flow in a heat exchanger. Feedwater flows in the shell of exchanger and the superheated steam flows inside the tube. When it is required to increase the temperature of steam, feedwater is bypassed with help of a control valve. When it is required to decrease the steam temperature, more water is allowed to flow through the heat exchanger by closing the control valve (Figure 10.12).

Figure 10.12  Arrangement of surface type attemperator.

The main advantage of this system is that the feedwater does not mix with steam, so the purity of steam is maintained. The temperature variation at superheater is shown in Figure 10.13.

Figure 10.13  Steam temperature variation in superheater and attemperator.

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10.5  START-UP VENT This is a vent provided at superheater outlet header of the boiler (Figure 10.14). This vent is open to the atmosphere.

Figure 10.14  Start-up vent.

During starting of the boiler when no steam is taken out from the boiler, this vent valve is kept open to allow some steam to flow through the superheater tube. Otherwise, in the absence of steam flow, superheater tube may be overheated and may fail. Once the steam is taken out from the boiler, start-up vent is closed gradually. In vertical superheater tubes, steam is condensed when the boiler is stopped and collected at lower U-portion of the tube (Figure 10.15). This condensate cannot be drained out. So, during starting, start-up vent is kept open so that this condensate can evaporate and vented out.

Figure 10.15  Non-drainable vertical superheater.

As this vent is used during starting, so it is called start-up vent. Sometimes, during sudden load cut off, boiler drum pressure increases and drum level becomes low. At that time, this vent may be opened to bring back the pressure and level of the drum to normal.

10.6  SAFETY VALVE Steam is generated in the boiler under pressure. This pressure is very high in case of power boilers. If the pressure of boiler suddenly increases a beyond a desired level for any reason, then severe accident may take place and create disaster. For the safety of man and machine, this overpressure is to be avoided. A device is required to be fitted which can avoid overpressure and

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to avoid any mishapn. For this, a safety valve must be installed which releases some volume of steam to the atmosphere when a predetermined maximum pressure is reached. The safety valve can be defined as a valve which discharges certain amount of fluid when a predetermined safe pressure is exceeded automatically without assistance of any outside energy other than that of the fluid itself and which is designed to reclose and prevent further flow of fluid after normal pressure condition is restored. There are different types of safety valve which are as follows:

• Spring loaded safety valve • Leaver safety valve • Dead weight safety valve

Of these three safety valve, spring-loaded safety valve (Figure 10.16) is commonly used in a boiler. In spring-loaded safety valve, the disc is lifted to discharge some steam. Steam pressure has to lift the disc against the spring compression. When compression force of the spring is more than the acting force of steam on disc, then the valve remains in closed position. When acting force becomes more than the spring force, then the disc lifts and steam escapes to the atmosphere through a discharge pipe. To reduce noise, a silencer is used. The discharge pipe should be straight as far as possible with minimum bends.

Figure 10.16  Spring-loaded safety valve.

The lifting force of the disc F = P  A where A = area of the disc (pd 2/4) P = pressure of the steam

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When F is more than Fs, then the disc lifts. By adjusting the spring pressure, the lifting pressure can be adjusted.

10.6.1  Basic Operation of Safety Valve As discussed earlier, when steam pressure rises above the set pressure (preset spring force), the disc of the safety valve starts lifting. This lifting pressure has to overcome the compressive force of spring (Figure 10.17). So, some margin of overpressure is required so that the disc can be lifted completely. This increased pressure is called overpressure.

Figure 10.17  Spring force and operating force.

Once the lift is initiated, it is required to open the disc rapidly. This is done by a shroud, skirt or hood provided around the disc (Figure 10.18). As the disc lifts, larger area of the shroud is exposed to the steam. The lifting force increases as the area increases. So, the disc opens rapidly.

Figure 10.18  Basic principle of operation of safety valve.

Some quantity of steam is vented out and the pressure of the system is normalised. But after normalisation, the disc does not close immediately. As the larger area (shroud) is still exposed to the steam, so it requires the pressure to drop further than the set pressure (Figure 10.19). The pressure at which the disc is closed completely is called reset pressure. The difference between set pressure and this resetting pressure is called blowdown. The set pressure can be adjusted by adjusting the spring tension. There are two adjustable rings for adjusting the overpressure and blowdown. They are locked with pins after adjustment. A hand lever is provided in the safety valve to lift the valve manually to ensure the valve is operational. One bolt (test gag) is provided at the top of the valve body to restrict the movement

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187

Figure 10.19  Relationship between pressure and lift.

of valve spindle. Gagging is done to prevent the valve operation during hydraulic test. During normal operation of the boiler, this gag bolt is to be removed, otherwise the safety valve will not operate during overpressure. In a boiler, more than two safety valves are provided in the steam drum depending upon the capacity of the boiler. Set pressures of these valves are different. Besides these valves, upto three safety valves are provided at superheater outlet depending upon the capacity of the boiler. Set pressure of the superheater safety valve is kept lower than that of the drum safety valve. During overpressure, superheater safety valve should be lifted first. If the drum safety valve will open first, steam will be escaped from the drum causing starvation of superheater tube. Safety valve is also provided at the inlet and outlet of a reheater. Sum of the releasing capacity of all the safety valves installed in a boiler drum and a superheater should be more than the boiler evaporation capacity.

10.7  STEAM VENT SILENCER The main function of a vent silencer is to release large quantities of steam from high pressure to the atmosphere and reduce high levels of noise generated. A silencer is made of acoustic cylinder enclosed with a robust steel casing with one end as dished end or flat end. The steam enters through the diffuser and passes through the annular space between the acoustic packing where the sound energy is absorbed. A weather cowl is provided for protection from rain. A silencer should have minimum pressure drop. Silencers are used at following vents/discharge lines:

• • • •

Boiler drum safety valves discharge Superheater safety valve discharge Start-up vent discharge Deaerator safety valve discharge

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EXERCISES

What are the main functions of steam drum? Why is an air vent provided at the steam drum? What are the main drum internals? What arrangement is made in drum for steam separation and purification? What is demister pad and why is it used? What is the difference between drainable superheater and non-drainable superheater? How are convective, radiant and platen superheaters classified? What are the main methods to control superheated steam temperature? What is attemperation? What is the use of start-up vent? What is a safety valve and how does it operate? What are the different types of safety valves? Define set pressure, overpressure, reset pressure and blowdown of a safety valve. Why is the reset pressure lesser than the set pressure? Why is gagging done? Why is the set pressure of a superheater safety valve lesser than that of the drum safety valve? 17. What is the function of a vent silencer? 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16.

Chapter

11

Flue Gas Path

11.1  INTRODUCTION Combustion of fuel takes place in the furnace. The combustion product (flue gas) passes in the boiler in a predetermined path so that heat energy can be removed from the hot flue gas before it is escaped to the atmosphere. In this path, heat exchangers like superheater, evaporator, economiser and air heater are placed (Figure 11.1).

Figure 11.1  Predetermined path for combustion product.

Depending upon the location of this path, a boiler can be divided into three zones, i.e., (i) radiation zone, (ii) radiation and convection zone and (iii) convection zone. Depending upon the boiler size and type of the fuel used, above heat exchangers are placed in various zones. The furnace temperature depends upon the type of the fuel used. The exit temperature of the flue gas is maintained such that the cold end corrosion due to the condensation at the later stage (normally air heater) can be avoided. These heat exchangers produce resistance to the flow of flue gas. Proper draft in the boiler is maintained to overcome this resistance. In a boiler, the draft is created through ID fan. In most of the power boilers, balanced draft is created with the help of ID and FD fans. 189

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Flue gas velocity of the boiler depends upon the type of fuel used and the ash contents in flue gas. When the ash contents in flue gas are more, flue gas velocity is kept low to avoid erosion of tubes. Flue gas contains some undesirable gases and solid particulates. These must be controlled properly, as these gases pollute atmosphere. Finally, the flue gas escapes to the atmosphere through a long height chimney. All the above points are discussed step by step in the subsequent sections.

11.2  FURNACE In boiler furnace, chemical energy of the fuel is released and converted into heat energy. Burning of fuel takes place here. Fuel and air is supplied to the furnace. As discussed earlier, for combustion, following three things are required:

• Fuel • Oxygen (air) • Three Ts (time, temperature, turbulence)

We have discussed about the supply of fuel and oxygen (air) in fuel handling system and air path respectively. Here, we will discuss about three Ts. In furnace, temperature is achieved due to burning of fuel. Initially, during the starting of a boiler, this temperature is achieved by burning some auxiliary fuel like diesel, wood, charcoal, etc. When furnace temperature becomes more than the ignition temperature of the main fuel, fuel is supplied continuously to the furnace. Fuel continues to burn and furnace temperature is maintained. Sufficient time is required for complete combustion of fuel. Gas, oil and pulverised coal require less time for burning, as the exposed surface of fuel particle is more. Grate-fired boiler requires more time for the combustion of fuel. In this case, speed of grate decides the retention time of fuel inside the furnace. For proper mixing of fuel and air, turbulence is required. Turbulence is created by proper burner design and by adjusting the secondary air vanes. Heat release in the furnace varies depending upon the size of the boiler and quantity of the fuel used. In large power boilers, a lot of heat energy is released in the furnace. The rate of heat released in the furnace may be expressed as units of heat energy released per unit volume in unit time (kcal/m3hr). Sometimes, heat power of furnace is measured in kw. It is given as

P=QH

where P = heat released (in kilowatts) Q = fuel consumption in (kilogramme per second) H = calorific value of fuel in (kilojoule per kilogramme) As huge amount of heat is released in the boiler furnace, it is required to cool down the furnace so that overheating of the other heat exchangers in convection zone can be avoided. Furnace exit flue gas mostly comes in contact with the superheater first. So, the flue gas

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temperature is required to be lowered in this zone. In a pulverised boiler, chances of slagging of superheater tube is more. Slagging is the phenomenon of deposition of molten ash over heating surface of the tube. If flue gas temperature is more than the fusion temperature of ash which moves with flue gas, then ash is fused and deposited on the tube where the temperature drops. Flue gas can be cooled upto the required level if major portion of the heat released can be absorbed inside the furnace by suitable means for producing steam. To reduce the furnace temperature, boiler furnace wall is made of water tubes. Water tubes are welded through fins or the gap between the tubes is filled with suitable material to form a water wall. Membrane panels are also used for water wall. This water wall not only effectively cools the furnace but also provides air tight rigid wall for the furnace. It withstands severe condition of the furnace atmosphere. As discussed earlier, water wall absorbs mostly radiation energy of combustion and hence, the combustion product is cooled down and convective zone tubes are saved. To limit the motion of water wall against the furnace pressure, a structural member called Buckstay is placed against the furnace wall at different elevations. Buckstay allows thermal expansion of water wall. Expansion markers are provided at suitable location to check thermal expansion. In a solid fuel-fired boiler, bottom of the furnace is designed in such a way so that the ash can be removed. Furnace bottom wall of gas and oil-fired boilers are closed, as ash removal is not required. Depending upon the ash condition, the furnace bottom may be called as dry bottom or wet bottom. These are discussed in ash handling system in detail. In an AFBC boiler, bed tubes are placed inside the bed so that heat can be removed quickly. The furnace has proper opening for feeding fuel to the bed and an arrangement to supply secondary air. Fluidising air obtained from FD fan helps in the fluidisation of bed. A pulverised coal-fired boilers has a suitable opening for burner fitting and the water wall is arranged accordingly (Figure 11.2). Secondary air is admitted to the furnace for creating turbulence in the furnace and complete combustion of fuel.

Figure 11.2  Burner opening in water wall.

Burners are arranged at different heights of front water wall. In low capacity boilers, burners are fitted in single tier, as shown in Figure 11.3(a). In large boilers, burners are also fitted at rear and side water walls. In tangential arrangement, burners are fitted at corners of the wall, as shown in Figure 11.4. These boilers have high heat generating capacity.

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Figure 11.3  Burner arrangement (a) Single-tier arrangement and (b) Two-tire arrangment.

Figure 11.4  Tangential arrangement.

In some cases, burners are also fitted at bottom and roof of the furnace. Standby burners of the running boiler are charged with primary air to avoid overheating of the burner. Each burner is having its own flame sensor (photocell). If the flame of that particular burner extinguishes, fuel is cut off automatically and flame failure alarm is displayed to attract an operator’s attention. To light up oil burner, lancer type high energy spark rod is used. This ignites the oil and then retracts back. Spark is produced with the help of a high voltage electric pulse. Vision glasses are provided in the furnace to observe the flame condition. Small openings with suitable locking arrangement (inspection window) are also provided to check the furnace condition. During boiler shutdown, it is required to enter the inside furnace for inspection and maintenance. So, manholes are provided in the furnace wall. Openings for soot blowers are also provided in the furnace. Water wall tubes are bent at above opening areas. Suitable refractory is applied in these openings for sealing purpose. Furnace bottom hopper is also provided with refractory. In some boilers, refractory bricks are used. When bricks cannot be used, castable refractory is used. The outer side of the furnace wall is insulated properly to avoid heat loss (radiation loss).

11.2.1  Furnace Dimension Normally, the furnace depth b is the distance between front and rear wall (Figuree 11.5). It depends upon the type of fuel used. It is selected suitably so that the flame tip does not touch the water wall. If flame tip touches the water wall, then it overheats the tube and the tube may fail. This phenomenon is called flame impingement.

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Figure 11.5  Furnace depth.

Furnace width a depends upon the capacity of the boiler. If more burners are arranged, then the width is more (Figure 11.6).

Figure 11.6  Furnace width.

Furnace height depends upon the number of tires in which burners are arranged (Figure 11.7). It is also decided according to the furnace exit flue gas temperature requirement. More the height of furnace, more is the furnace absorption and less is the furnace exit flue gas temperature.

Figure 11.7  Furnace height.

In case of oil-fired boilers, emissivity of flame is more. So, heat absorption by water wall is more. Hence, in this case, furnace volume is less as compared to the coal-fired boilers.

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11.3  DIFFERENT ZONES OF FLUE GAS PATH It has been discussed earlier that the boiler is divided into various zones according to the mode of heat transfer. These are as follows (Figure 11.8):

Figure 11.8  Different zones in a boiler.



• Radiation zone • Radiation and convection zone • Convection zone

–  Convection zone 1 –  Convection zone 2 Different heat transfer elements (superheater, evaporator, economiser, etc.) are placed in different zones. Radiation Zone In radiation zone, burning of fuel takes place. This is the furnace zone of a boiler. Huge amount of heat energy is released during burning of fuel. This heat is transferred to the cold water walls surrounding the furnace. Due to high emissivity of flame and high temperature difference, heat is transferred in this zone mostly by the radiation method. Due to this heat transfer, combustion product cools down. The flue gas moves upward in the furnace. Furnace exit flue gas temperature should be less than the ash fusion temperature. Otherwise, molten ash will be deposited on the tubes. Radiation and Convection Zone In this zone, heat transfer takes place by both radiation and convection methods. This zone is partially exposed to the radiation of the flame in the furnace and partially located at the flue gas flow path. Flue gas from the furnace enters this zone first. The temperature of the flue gas in this zone is still high. Normally, a superheater is placed in this zone.

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Convection Zone • Convection zone 1:  In this zone, the total heat is transferred by convection mode. Normally, a superheater or reheater is placed in this zone. The temperature of this zone should be less than the ash fusion temperature to avoid slag deposition on the tubes. • Convection zone 2:  This zone is a low temperature zone. Temperature of the flue gas is reduced due to heat transfer to the superheater and reheater. Evaporator bank tubes, economiser and air heater are placed in this zone. For better heat transfer, Baffles are provided in this zone to control the flow of flue gas. These baffles change the direction of the flue gas. So, heat is evenly distributed. They also increase residual time of the flue gas in a boiler to make the heat transfer efficient. Baffles also deposit fly ash in an easy accessible area from where it can be removed easily. The baffles are made of refractory or metals which can withstand high temperature. But sometimes, this may crack and lead to the short circuit of flue gas path. Heat distribution may be disturbed. The boiler exit gas temperature may go high and the boiler efficiency may come down. During inspection of a boiler, condition of these baffles is required to be checked.

11.4  REFRACTORY AND INSULATION Refractory is a heat resistant material used in a boiler to protect the boiler structure which is exposed to high temperature. It also protects this exposed surface from chemical attack and mechanical damage. In a boiler, refractories are used at furnace, doors, inspection holes, burner openings, cyclone, hoppers, soot blower openings, etc. To minimise the heat loss from the boiler’s outer surface to the surrounding atmosphere, insulation is required. This is to be noted that refractory and insulation are used for different purposes.

11.4.1  Refractory Refractory is a material which is not deformed or damaged when exposed to high temperature. Refractory material can withstand abrasive or corrosive actions of solids, liquids or gases at high temperature. Refractories are inorganic, non-metallic, porous and heterogeneous materials composed of thermally stable mineral aggregates, a binder phase and additives. The principal raw materials used in the production of refractories are oxides of silicon, aluminum, magnesium, calcium and zirconium as well as some non-oxide refractories like carbides, nitrides, borides, silicates and graphite. A refractory material should:

• • • • •

Withstand Withstand Withstand Withstand Withstand

high temperature sudden changes of temperature action of molten slag, hot gases, etc. load at service condition abrasive force

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• Conserve heat • Have low coefficient of thermal expansion • Not contaminate the material with which it comes into contact

Refractory materials are available in shaped (brick) and unshaped or monolithic (castable, mortar) form. Depending upon the chemical composition, refractories are classified as follows:

• Acidic refractories • Basic refractories • Neutral refractories

Acidic Refractories These are used in areas where slag or hot gas is acidic. These are stable to acids but attacked by alkali. Silica (SiO2) and aluminosilicate belongs to this group. Basic Refractories These refractories are stable to alkaline or basic slag and hot flue gas but reacts with acids. Magnesia, dolomite and chrome-magnesia belong to this group. Neutral Refractories These refractories are chemically stable to both acids and bases and are used in areas where slag and hot gas are either acidic or basic. Alumina (Al2O3), chrome, silicon carbide, zirconia and carbon belong to this group. Some of the desired properties of refractory material are discussed below: • Porosity:  This is the property of refractory which determines the strength and thermal conductivity. More porous means less strength and less thermal conductivity. Porosity is a measure of open pores into which liquid can penetrate. This is an important property when refractory is used and it comes in contact with the molten slag. • Refractoriness or fusion point:  Refractoriness is the temperature above which the refractory fuses. This temperature should be more than the service temperature. • Spalling:  This is the property of the refractory to withstand thermal shock due to rapid heating and cooling. • Pyrometric cone equivalent (PCE):  The temperature at which a refractory deforms under its own weight is known as its softening temperature which is indicated by pyrometric cone equivalent (PCE). The refractoriness or fusion point is measured by this. • Bulk density:  This may be defined as the material present in a given volume.

Bulk density = Total weight/Total volume

Following points are considered while selecting a suitable refractory material for a boiler:

• Working temperature • Extent of abrasion and impact

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• • • •

197

Permissible weight Stress due to temperature gradient and temperature fluctuation Chemical compatibility to the environment Cost consideration

Normally, refractory bricks are used in furnace bottom hoppers and castable refractories are used in different zones of a boiler where the material is subjected to vibration as well as abrasion by the flue gas. Different furnace zones operate at different temperatures. The correct selection of refractory materials for various zones is important. Also, refractory is required to be applied on various locations with different shapes like furnace wall, burner opening, cyclone, etc. Shaped (brick) and unshaped (castables, mortar) refractories are used for this. Castable is also known as monolithic refractories which can be shaped in situ. Details about refractory brick and castable are discussed below: Refractory Brick Mostly, fire clay brick is used at the furnace of a boiler. It consists of hydrated aluminum silicate. The fire clay brick is available in following four standard classes:

• • • •

Super duty (40%–44% alumina, 49%–53% silica) High duty (35%–40% alumina, 50%–60% silica) Medium duty (26%–36% alumina, 60%–70% silica) Low duty (23%–33% alumina, 60%–70% silica)

Grade of refractory increases with the increase in alumina percentage. Other than the fire clay brick, following refractories are also available:

• High alumina brick with 50%, 60%, 70% and 80% alumina contents. • Silica brick (or Dinas) of various grades containing quality rocks with higher silica percentage. • Magnesite refractory containing at least 85% magnesium oxide. • Chromite refractories.

Mortar Mortar is a finely ground refractory material which becomes plastic when mixed with water. Mortar is used to bond the brickwork into solid unit to provide cushion between the slightly irregular surfaces of the brick and fill up the spaces created by a deformed shell to make the wall gastight. Castable The castable is a monolithic refractory. In castable, cementing material and unshaped refractory aggregates are used. The cementing material is mostly alumina cement. Normal Portland cement is based on lime–silica mineral phase, whereas in alumina cement, the reactive phase is lime– alumina compounds. Higher alumina contents in cement can be used for higher temperature application.

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When alumina cement and refractory aggregates are mixed with water, a concrete like material called castable is formed. The refractory aggregates comprise of buxite, grog of fire clay, sillimanite, alumina or chromites, etc. Castable is required to be mixed with right quantity water and used within 15–30 minutes. Castable may be cast by pouring or gunning method. Exothermic chemical reaction between alumina cement and water raises the temperature and the casting sets. The main advantages of castable refractory are given below:

• • • • • •

The eliminates joints which is an inherent weakness. It can be applied faster. Special skill is not required for its application. There is an ease for its transportation and handling. It is easy to repair. There is a considerable scope to reduce inventory and eliminate special shapes.

11.4.2  Insulating Material A thermal insulator is a poor conductor of heat having a low thermal conductivity and used to reduce heat losses. Insulation is made by providing a layer of material having high porosity with low thermal conductivity between the boiler’s inside hot surface and the external surface to keep the temperature of the external surface low. Insulating materials consist of minute pores filled with air which have a very low thermal conductivity. Thermal conductivity of insulating brick is much lesser than that of a fire clay refractory brick. Composite wall with certain thickness of refractory brick and insulation brick is used at boiler furnace to minimise the heat loss. Different types of insulating materials are used for the insulation of boiler. Mineral wool and fibre glass or glass wool insulation with support wire mesh netting and aluminum cladding is used normally to insulate the outer surface of a boiler and hot air or gas ducts. Steel wire mesh is used to provide strength to the insulation and aluminum cladding is provided for mechanical protection and water proofing. Following insulating materials are mostly used in a boiler:

• • • • • • •

Insulation brick Insulating castable Ceramic fibre Calcium silicate Glass mineral wool Rock mineral wool Ceramic coating

Excessive heat affects all insulation materials. So, a suitable insulating material is selected depending upon the temperature which it has to withstand. The insulation can be classified into three groups according to the temperature ranges for which they are used. • Low temperature insulation (upto 90 °C):  This type of insulation is used for refrigerators, cold and hot water systems, storage tanks, etc. The commonly used materials are 85% magnesia, mineral fibres, polyurethane, expanded polystyrene, etc.

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• Medium temperature insulation (90 °C–325 °C):  This type of insulation is used for steam lines, flue ducts etc. The commonly used materials are 85% magnesia, asbestos, calcium silicate and mineral fibres, etc. • High temperature insulation (> 325 °C):  The commonly used materials are asbestos, calcium silicate, mineral fibres, fire clay or silica-based insulation and ceramic fibre. Insulation materials are also classified into organic and inorganic types. Inorganic insulation is based on siliceous/aluminous/calcium materials in fibrous, granular or powdered forms like mineral wool, calcium silicate, etc.

11.5  ID FAN ID fan takes out the combustion product from the furnace and exits it to the atmosphere. It is called as induced draft fan. The air supplied by FD fan is used for combustion. After combustion of fuel, combustion product (hot flue gas with dust particles) is to be evacuated continuously from the furnace during continuous combustion process. This flue gas passes through different zones due to the suction of ID fan. Heat of flue gas is transferred to different heat transfer elements. Finally, the gas at low temperature is escaped to the atmosphere through chimney. ID fan is placed between the air heater and the chimney (Figure 11.9). The flue gas temperature at the suction end of an ID fan is normally kept above the sulphuric acid due point.

Figure 11.9  ID fan.

The specific volume of flue gas is more at higher temperature. So, an ID fan handles more volume of gas as compared to a FD fan. Also, the flue gas contains dust particles. So, the size of ID fan is normally higher than that of a FD fan. Its capacity is approximately 1.5 times higher than that of a FD fan. If the flue gas is free from dust particles (due to upstream dust separators), then the size of fan reduces. An ID fan handles the hot flue gas. Heat is transferred to the fan blade, shaft and then to the bearing. So, cooling water is used to cool down the bearing continuously in a bigger size fan. Like FD fan, ID fan also contains multilouver dampers to control flue gas flow (draft). During starting of the fan, these dampers are kept closed. After starting, these dampers are opened to get the desired negative pressure in the furnace. Following methods are adopted to control the flow of an ID fan:

• Variable speed hydraulic coupling (scoop) • Damper control

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• Variable frequency drive (VFD) • Two-speed electric motor • Variable pitch blades (axial fan)

Some boilers (large boilers) have two ID fans. The flue gas duct is divided into two parallel passes (Figure 11.10). Each pass has one ID fan which can handle 50% flue gas. When both the fans are having 50% capacity, then at partial load (less than 50%), one fan may be taken in line and at higher load, both the fans may be used.

Figure 11.10  Two-pass arrangement.

An ID fan is a critical equipment of a boiler. So, proper inspection and monitoring is required during service. To monitor the condition of a fan, vibration and temperature measurement provision is essential. Alarming system is also provided to warn before these values go beyond a preset value. Also, for safety, tripping interlock is provided to trip the fan in case vibration and temperature become more. ID fan speed/damper control is put in autocontrol mode during normal operation of the boiler so that the draft of the furnace can be maintained automatically.

11.6  DRAFT In a boiler, combustion takes place inside the furnace continuously. For this, continuous supply of fuel and air (oxygen) is required. To supply air continuously to the furnace, combustion products are to be exhausted from the furnace continuously. If there is pressure difference between the combustion product within the boiler furnace and the outside cold air of the atmosphere, then only the combustion products can be exhausted to the atmosphere and fresh air can enter into the furnace for combustion. This pressure difference between the furnace combustion products and the outside cold air is called draft. Draft is required to

• Supply the required quantity of fresh air (oxygen) to the boiler for proper combustion • Evacuate the combustion products from the combustion chamber • Exhaust the combustion products to the atmosphere

As discussed earlier, before the hot combustion products or flue gas escapes to the atmosphere, its heat is utilised at various heat exchangers like superheater, evaporator, economiser and air heater. When flue gas flows through these heat exchangers, pressure of the flue gas drops due to resistance. This is called draft loss. Also, there is a draft loss in the flue gas ducts and the fuel bed resistance. Besides all these draft losses, the flue gas should be discharged to the

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atmosphere with some velocity which should be more than the air velocity at that height where the flue gas is to be discharged. So, the minimum draft required is the sum of all the above. The draft is normally expressed in millimetre of water column (mmwc). There are various methods to obtain draft like natural draft and artificial or mechanical draft. These are discussed here one by one.

11.6.1  Natural Draft Natural draft is created by chimney. Draft is produced due to the difference in the densities of hot flue gas and cold outside atmospheric air. The draft produced in this case is given as

D = H(Da – Df)

where D = draft H = height of chimney Da = density of cold atmospheric air Df = density of hot flue gas To increase draft in this case, either chimney height is to be increased or the density of flue gas is to be decreased. As we know the density of gas varies with temperature, so the flue gas exit temperature is to be kept high to decrease its density. Outside air density is more when atmospheric temperature is less. So, draft is more in this condition. Like this, when atmospheric air temperature is more, the draft is less. It is clear now that the draft varies with the outside atmospheric condition in case of natural draft. For large boilers, natural draft method is not utilised for draft control. Chimney is used to avoid the concentration of combustion product at ground level. This is discharged at a height so that it can be diluted in the atmosphere easily.

11.6.2  Artificial Draft (Mechanical Draft) Natural draft is not efficient for higher capacity boilers. In this case, height of chimney is required to be increased significantly which is uneconomical. Also, in this case, draft is dependent on the atmospheric climate condition and it is difficult to control the draft as per the requirement. So, another type of draft control is required which can eliminate the above problem. This is achieved by some artificial means. Fans are used in this case. Mechanical draft is very economical and efficient. This is used widely because of the following reasons:

• • • • •

This is very efficient. Draft is independent of the climatic condition. Flue gas exit temperature is less, so the system efficiency increases. Draft can be controlled suitably as per the requirement. The rate of combustion is very high, as the supply of air and the evacuation of flue gas is faster. • More draft can be produced.

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Though mechanical draft is mostly used, still chimney cannot be eliminated, as it is required to exhaust the flue gas at a higher level to avoid concentration of dangerous combustion products at ground level. Following are the three types of mechanical drafts.

• Forced draft • Induced draft • Balanced draft

Forced Draft In forced draft, a mechanical fan called forced draft fan is placed before the furnace. This fan supplies air to the boiler furnace which is at higher pressure than that of the atmosphere. This high pressure air is used for combustion and the flue gas is exhausted with pressure. Furnace pressure is more than the atmospheric pressure in this case. So, the furnace flame inspection door cannot be opened, as the flame tries to come out due to high pressure inside the furnace. In this case, the pressure of air and flue gas is positive throughout its path. In small package boilers, this system may be used. But, in case of large boilers, this is not suitable. Induced Draft Induced draft uses a mechanical fan called induced draft fan. This fan is normally placed just before the chimney (Figure 11.11).

Figure 11.11  Induced draft.

This fan soaks the combustion product from the furnace. So, negative pressure is developed inside the furnace. Due to this negative pressure, fresh air enters the furnace. The pressure throughout the path upto the discharge of ID fan is negative. This fan discharges flue gas at higher pressure to the atmosphere through chimney. As the furnace pressure is negative, the

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inspection door can be opened easily as the flame does not come out rather the outside air enters the furnace. Balanced Draft Both FD and ID fans are used in balanced draft (Figure 11.12). Air is supplied to the furnace with pressure through FD fan. This air helps in combustion. ID fan evacuates the combustion product from the furnace. Draft is adjusted in such a way so that the air is supplied to the furnace at positive pressure, whereas the furnace pressure is maintained slightly negative (below atmospheric pressure).

Figure 11.12  Balanced draft.

This system is mostly used in large boilers. As this system is having two fans to supply air and evacuate flue gas, so it is efficient for the combustion of any type of fuel. The load variation can be performed smoothly.

11.7  FLUE GAS CONSTITUENTS In a boiler furnace, fuel burns with the help of air supplied by the FD fan. After combustion of fuel, combustion products are produced. This combustion product (or flue gas) consists of various types of gases and particulates. Some objectionable gases are also present in the flue gas. These are to be reduced as much as possible before escaping to the atmosphere.

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The constituents of flue gas along with the method of control and its impact upon the system efficiency are discussed here.

11.7.1  Carbon Dioxide (CO2) Fuel (containing carbon) is burnt in the boiler. As discussed earlier, carbon when burns in sufficient amount of air, produces carbon dioxide and heat.

C + O2  CO2 + 8137 kcal/kg

The flue gas should contain maximum carbon dioxide. More carbon dioxide percentage indicates that the fuel particle is completely burn. 10%–13% carbon dioxide is present in the flue gas of a coal-fired boiler.

11.7.2  Carbon Monoxide (CO) If burning of fuel takes place with insufficient air (oxygen), then carbon monoxide is formed.

C + 1/2 O2  CO + 2452 kcal/kg

Carbon monoxide gas is not desirable in flue gas. Presence of carbon monoxide in flue gas indicates incomplete combustion. As combustion is not complete, so the boiler efficiency goes down. It is always desirable that no carbon monoxide is escaped from the boiler. 200 ppm– 1000 ppm carbon monoxide is found in the flue gas.

11.7.3  Oxygen (O2) For the burning of fuel, oxygen is required. As discussed earlier, there is a theoretical requirement of oxygen for a particular quantity of fuel. The theoretical fuel to air ratio is called stoichiometric ratio. Each molecule of the fuel inside the furnace should have adequate oxygen supply for complete combustion. Some extra air is supplied to the furnace to ensure complete combustion. When air supplied is less than the theoretical requirement, then the mixture is said to be fuelrich. When air is more than the theoretical requirement, then the mixture is said to be air-rich. Figure 11.13 shows the desired level of oxygen for highest efficiency.

Figure 11.13  Air and fuel mixture.

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Measurement of oxygen in the flue gas indicates the zone at which the boiler is operating. If the oxygen in flue gas is more, that means the boiler is operating at higher excess air region. Higher excess air means more air is supplied to the furnace which does not take part in combustion. But temperature of this air increases upto the flue gas temperature and it escapes to the atmosphere. This excess air is responsible for the drop in efficiency. So, the boiler is expected to run in the highest efficient operating region, as shown in Figure 11.13. Depending upon the type of fuel used and furnace design, excess air is selected. It is normally 10%–20% excess air or 2%–4% oxygen. The measurement of flue gas constituents are expressed either in parts per million (ppm) or in percentage. The larger values like CO2 and O2 are expressed as percentage and the smaller values are expressed in parts per million (ppm). The conversion of parts per million (ppm) to percentage is given in Table 11.1. Table 11.1  Conversion of Parts Per Million into Percentage Parts per million (ppm) 1000000 100000 10000 1000 100 10 1

Percentage (%) 100 10 1 0.1 0.01 0.001 0.0001

11.7.4  Nitrogen Oxide (NOx) For the combustion of fuel, oxygen is required. Air is used to meet the requirement of oxygen. Atmospheric air composition (by volume) is given below: Nitrogen 78% Oxygen 21% Argon 0.9% Carbon dioxide 0.03% Other minor gases (Water vapours, hydrogen, ozone, methane, carbon monoxide, helium, neon, krypton, xenon) Balance So, it is understood that to get 21% oxygen, we are handling 78% of nitrogen for combustion. This large volume of nitrogen gas is oxidised at higher temperature and forms nitrogen oxides (NOx) like NO, NO2, etc. or simply, NOx. Also, nitrogen present in the fuel contributes in the formation of NOx. This nitrogen oxide is highly objectionable. When it reacts with atmospheric moisture, it forms droplets of nitric acid which contribute in acid rain. NO2 reacts in atmosphere to form ozone (O3). This ozone is tropospheric ozone which is present in ambient air that we breathe. This is harmful to human being. Only stratospheric ozone in the upper atmosphere protects us from ultraviolet radiation coming from sun.

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In a thermal power boiler, a lot of NOx is produced. So, it is required to control this. The emission standard for NOx is set by the pollution control authority of a country. To control NOx, various control steps are taken. These are post combustion control methods and combustion control technique. In combustion control technique, care is taken to control NOx formation. In post combustion control method, NOx contents in flue gas are reduced by some means. Both these methods are discussed below: Combustion Control Technique In this method, proper care is taken so that NOx formation can be reduced. NOx is formed due to high temperature of furnace and high residual time of air inside the furnace. Proper designing of boiler furnace, proper setting of burner, reducing the peak temperature in the combustion zone, minimising residual time of air in peak temperature zone, controlling heat release rate and flue gas recirculation (FGR) can control NOx formation. Low NOx burners are used for controlling NOx formation. Also, by reducing oxygen concentration at the combustion zone, NOx formation can be minimised. It is preferred to adopt the above methods to reduce NOx formation than to adopt some additional methods to control the emission after formation. Post Combustion Control Method In this method, additional means are applied to control NOx emission, once it is formed. This method is also called as flue gas de-nitrification. Some NOx reducing agent is injected into the boiler exhaust gas which reacts with NOx and forms less harmful product. There are two type of post combustion control method: • Selective catalytic reduction method (SCR):  NOx reducing agent, mostly ammonia is injected into the flue gas. This flue gas is then passed through a catalyst bed, as shown in Figure 11.14. In the presence of this catalyst, NOx reacts with ammonia (NH3).

6NO + 4NH3  5N2 + 6H2O 6NO2 + 8NH3  7N2 + 12H2O

Normally, the catalyst is vanadium oxide or titanium oxide. Honey comb, pipe or plate type catalysts are used. In this method, upto 90% NOx reduction can be achieved. Injection of ammonia is normally done in between economiser and air heater.

Figure 11.14  Selective catalyst reduction.

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• Selective non-catalytic reduction method (SNCR):  In this case, NOx reducing agent (such as ammonia and urea) is injected into the flue gas. Catalyst is not used in this case. Ammonia and urea are injected at higher temperature.

11.7.5  Sulphur Oxide (SOx) Most of the fuel used in boiler contains sulphur. This sulphur when burns, sulphur oxides (SOx) is formed. S + O2  SO2 + 2181 kcal Sulphur dioxide (SO2) is highly objectionable in the flue gas. Power plants are the major NOx and SOx producers. Strict norms have been adopted throughout the world to control these gases. In coal, sulphur is present in different forms, i.e., chemically bound with coal and unbound (pyrites). Pyrites present in coal can be removed from coal to some extent by coal washing and cleaning. But, the chemically bound sulphur cannot be removed from the coal. It has to take part in burning process. So, it is preferred to use low sulphur fuel to avoid SOx formation. To limit SOx emission, flue gas desulphurisation (FGD) method is adopted. Like flue gas denitrification, in this method also, some SOx absorption material like lime is used. These absorption materials are mixed with water and this mixed water is sprayed on flue gas from the top of a reaction tank (Figure 11.15).

Figure 11.15  Flue gas desulphurisation.

When lime or limestone mixed water comes in contact with SO2, gypsum is formed. This gypsum is collected from reaction tank and the water can be recycled again.

11.7.6  Water Vapours Flue gas contains water vapours due to the presence of moisture in fuel and due to burning of hydrogen present in the fuel.

11.7.7  Volatile Organic Compounds (VOC) In case of liquid fuel, volatile organic compounds (VOC) may present on boiler flue gas due to evaporation or leakage of fuel. Escape of VOC reduces the efficiency of a boiler.

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11.7.8  Particulates Flue gas contains small particles of dust, soot and fumes known as suspended particulate matter (SPM). ESP and other dust collecting systems reduce particulates in the flue gas. Efficiency of this dust collecting equipment minimises the concentration of particulates in the flue gas. Nowadays, stringent environmental regulations are applicable for power plants. Maximum permissible limit of suspended particulate matter (SPM) is 50 mg/Nm3 after ESP. Very fine particulate matter of size less than 10 microns (PM10) is known as respirable suspended particulate matter (RSPM). It is very harmful as it goes inside human body with respiration. Its maximum permissible limit is 100 µg/m3.

11.7.9  Heavy Metal Toxics The power plants emit mercury into the atmosphere. This mercury is emitted in three chemical forms. These are as follows:

• Elemental form • Oxidised form • Absorbed to particulates

Among them, the elemental form of mercury remains in atmosphere for a longer period. It can travel several miles before being settled. Other two forms are having shorter life in atmosphere, hence they settle down in an area nearer to the plant. Mercury emission is an alarming condition nowadays for power plants. There are some methods to control the emission. Dry powdered activated carbon is injected into the flue gas after ESP. Mercury in flue gas is absorbed by these activated carbon particles. Then, the flue gas is passed through a fabric filter where these activated carbon particles are collected. This collected material is treated as toxic material and is kept in a separate place for disposal.

11.8  FLUE GAS VELOCITY Flue gas velocity plays a major role in case of a boiler. As discussed earlier, the flue gas passes through different heat transfer surfaces like superheater, evaporator, economiser and air heater. In these heat transfer units, heat from the flue gas is transferred to other medium like steam, water and air. Flue gas contains different gases and small solid particulates which are responsible for tube erosion and failure of heat transfer units. The flue gas flows in the flue gas path with certain velocity. This velocity depends upon the draft of boiler. While designing a boiler, flue gas velocity is properly selected. The design flue gas velocity depends upon the concentration of solid particulates in the flue gas. The solid particulates mainly consist of dust, soot and fumes. These particles are responsible for erosion of tubes. If the dust load is less, then flue gas velocity can be designed more. But if the dust load is more, then lesser gas velocity is selected.

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In case of low flue gas velocity, these solid particulates are deposited on boiler tubes. So, the heat transfer capacity of the tubes decreases. Considering these factors, flue gas velocity is to be properly selected for any type of boiler.

11.9  CHIMNEY Chimney is a structure for venting hot flue gas from boiler to the outside atmosphere at a suitable height to ensure the pollutants are dispersed over a wider area to meet legislation or safety requirement. The chimney height is determined primarily by environment protection agency permitting ground level concentration limits. The chimney is almost vertical to ensure a smooth flow of the flue gas. It also helps in creating natural draft in the boiler. But nowadays, chimney is used to vent the flue gas and the draft is maintained by mechanical means. The flue gas duct of a boiler is connected to the chimney with suitable sealing arrangement. The formula used to calculate the minimum height of a chimney is given as H = 14(Q)0.3 where H = height of chimney (in metres) Q = emission rate of SO2 (in kilogramme per hour) There are different types of chimneys. These are either made of steel, masonry or concrete. Among them, concrete chimneys are mostly used in boilers. Sometimes, steel chimney is also used in small boilers. Chimney is normally cylindrical in construction. It is exposed to tough environment at inside and outside. Flue gas with its abrasive and corrosive characteristic can damage the structural material. For this, normally the chimney is lined with suitable material like fire brick, FRP, etc. Mostly, bricklining is preferred in boiler chimney. Corbel supported brickline with suitable air space between concrete shell and brickline is preferred by most of the power engineers, as shown in Figure 11.16 depicting a reinforced cement concrete (RCC) chimney.

Figure 11.16  RCC chimney.

Chimney is basically a structure with very few mechanical parts that require maintenance. Mostly, chimney is overlooked by power plant personnel. As told earlier, chimney is exposed

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to a corrosive inside environment. Due to thermal sock or other reasons, crack is developed in brick lining. The flue gas enters into the air space and condenses there. The acidic condensate corrodes the concrete interior and develops leakages through concrete joints. Also, it can damage the corbel joints and the brick wall may collapse which leads to forced shutdown of the boiler, as the flue gas path is restricted. During low load operation, less fuel is used. So, the volume of flue gas is also less. The exit velocity of flue gas also decreases, creating a problem of particulate build-up on the bricklining. So, proper inspection and cleaning are required regularly. Due to friction, the flue gas draft loss takes place. It is given by DD =

fW 2CH

A3 where DD = draft loss W = weight of gas passing per second C = perimeter of chimney H = height of chimney A = area of chimney f = a constant depending upon the type of chimney and gas temperature The outer side of chimney (shell) is subjected to condensation, rain, thermal variation, ultraviolet exposure, lightning, atmospheric carbon dioxide, wind and ground stability. When concrete is exposed to carbon dioxide, continuous carbonisation takes place. So degradation of RCC continues year after year and thus, a suitable coating is to be done. The coating of chimney helps in

• Protecting against environment • Protecting against process gases • Compliance with aviation administration requirement

The stack is normally painted with alternate band of white and red colour. For protection against lightning, lightning rod is provided with proper earthing at the top of the chimney. As the height of chimney is more, flash lights (aviation lamp) are fixed for aviation requirement. Depending upon the capacity of plant and statutory requirement, chimney height is decided. For ground stability, the foundation of chimney is designed properly. Raft or pile type foundation is adopted. There are very high chimneys. The tallest chimney of the world is located at GRES-2 Power Station in Ekibastuz, Kazakhstan. It is 419.7 m high.

EXERCISES

1. What is slagging? 2. What are the main functions of a water wall?

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3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 21. 22.

What is buckstay? How is the free expansion of a furnace checked? What is flame impingement? On what factors do the furnace depth, width and height depend? What is the characteristic of refractory? On what factor (s) does the grade of refractory depend? What are the uses of mortar and castable? Why is the insulation of boiler done? Which insulation materials are used in a boiler? Why is the capacity of ID fan more as compared to FD fan? Why is draft required in a boiler? What is a balanced draft? Which methods are applied for flow control of ID fan? What are the main constituents of flue gas? What is the permissible limit of SPM? What is respirable suspended particulate matter (RSPM)? What is stoichiometric ratio? How does the formation of NOx and SOx take place? What are particulates and how can these be separated? What are the main functions of chimney?

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12

Ash Handling System

12.1  INTRODUCTION Indian coal has high ash. After combustion of coal, these ash particles remain in the boiler. Different types of boilers produce different types of ash like bottom ash and fly ash. Depending upon the ash percentage, 25% to 60% of the total coal used is produced as ash in coal-fired boilers. Among all the boilers, ash production is more in coal-fired boilers. Hot ash is to be removed from the boiler continuously. So, it is required to make it cool before transporting it to a suitable location. Furnace bottom ash and fly ash are collected by different methods. For conveying ash, different methods are used. Due to strict environmental regulations, fly ash present in the flue gas is to be separated before it is vented to the atmosphere. All these points are discussed here.

12.2  ASH Ash is the remaining product of solid fuel after burning. It is present in coal in two forms. These are inherent or fixed ash and free ash. Inherent ash of the coal cannot be removed. Free ash is due to the presence of clay, shale, pyrites, etc. It can be removed from coal by washing. Coal is graded into various grades depending upon the ash contents in the coal. Higher grade coal has less ash contents. Normally, ash has following constituents:

• • • • • • •

Silica (SiO2) Aluminum oxide (AlO3) Iron oxide (Fe2O3) Sodium oxide (Na2O) Potassium oxide (K2O) Calcium oxide (CaO) Magnesium oxide or magnesia (MgO)

Liquid and gaseous fuels contain very little ash. So, these boilers are not having ash handling system. We know there are various types of coal-fired boilers depending upon the firing methods adopted. These are grate-fired boilers, stoker-fired boilers, pulverised coal-fired boilers, AFBC boilers and CFBC boilers, etc. Total ash produced in these boilers can be classified as bottom ash and fly ash. 212

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12.2.1  Bottom Ash Bottom ash is collected from the boiler furnace. In case of pulverised coal-fired boiler, this bottom ash may be collected in dry form or in molten form. In dry form, ash temperature is less than ash fusion temperature. This type of boiler furnace is called dry bottom type furnace. In some boilers where the furnace temperature is more than ash fusion temperature, ash is collected from the furnace bottom in molten slag form. This type of furnace is called wet bottom type furnace. Bottom ash is some fraction of the total ash production. It depends upon the type of boiler. In case of pulverised coal-fired boiler, percentage of bottom ash is less than that of the fly ash. As the fuel burns in suspended condition, most of the ash is taken away by the flue gas. Like this, in case of grate-fired boiler, fuel burning takes place in the moving grate. In this case, bottom ash percentage is more than fly ash. In stoker-fired boiler, coal is thrown into the furnace. Some portion of coal burns on suspended condition. In this boiler, bottom ash quantity is more than that of a pulverised boiler and less than that of a grate-fired boiler. In a fluidised boiler, fuel burns in fluidised condition. Here, generation of bed ash is less as compared to fly ash.

12.2.2  Fly Ash When the fuel burns in suspended condition, ash produced is taken away by the flue gas. Ash which is carried out by flue gas is called fly ash. Generation of fly ash depends upon the size of coal. As size of coal in a pulverised boiler is very small, so it generates more fly ash. This fly ash is required to be separated from the flue gas by a suitable method like electrostatic precipitator (ESP), fabric filter (bag house), etc. These methods are discussed in subsequent sections. More fly ash in flue gas creates problem at downstream heat exchanger units. Fly ash is abrasive in nature. It creates erosion if flue gas velocity is more. In case of low gas velocity, this fly ash is deposited on the heat transfer surfaces and it lowers the efficiency. Like bottom ash, fly ash is also required to be removed from the boiler continuously. Fly ash contains silica upto 60%. So, it can be used with reinforced concrete. Fly ash bricks are manufactured using fly ash and can be used in place of normal clay bricks. Fly ash can also be used for construction of road and filling of embankments. This waste product is to be utilised properly; otherwise it requires huge space for storage and disposal.

12.3  BOTTOM ASH REMOVAL SYSTEM In this section various methods of ash removal from the boiler furnace are discussed. Once this ash is removed from the boiler, it is transported to a suitable location for further disposal. Bottom ash removal is very difficult in a boiler. It is because of the following reasons:

• The ash is at higher temperature. • It is very abrasive and corrosive in nature. • Proper sealing of furnace is required to avoid outside air ingress.

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• When ash comes in contact with water, dangerous fumes and corrosive acid are formed. • Clinker is formed on grate which restricts the primary air flow. It is required to be broken which is a dangerous job.

Proper water sealing is required in this case to avoid the outside cold air ingress into the furnace which disturbs the boiler draft and reduces the efficiency.

12.3.1  Dry Bottom Furnace Ash Removal In this method, ash is collected in dry form. Ash temperature is normally below the ash fusion temperature. Ash from the furnace bottom drops into water-filled hopper (Figure 12.1). This water hopper serves two purposes. Firstly, it seals the boiler furnace to avoid air ingress and secondly, it cools down the hot ash. Water in the hopper is circulated continuously to carry out this heat.

Figure 12.1  Dry bottom furnace.

In pulverised coal-fired boiler, ash is removed in dry form. Here, the furnace bottom is called as dry bottom furnace. The furnaces of grate-fired and stoker-fired boiler are not considered as dry bottom furnace. But ash removal system is mostly same as dry bottom furnace. In a grate-fired boiler, coal is fed from one end and burning of coal takes place on the moving grate. Finally, ash drops into a water hopper like earlier case. From this water hopper, ash is removed by different methods like hydraulic or mechanical extraction system (chain drag conveyer).

12.3.2  Wet Bottom Furnace Ash Removal In this case, ash is collected in molten slag form. Ash temperature is more than the ash fusion temperature. Mostly, in tangentially fired pulverised boiler, furnace temperature is more than the ash fusion temperature. So, 70%–80% of the total ash produced is collected in molten form. This molten ash falls into a water hopper. With sudden contact with quenching water, the molten ash is converted into hard coarse granular particles.

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12.4  DIFFERENT ASH HANDLING SYSTEM Ash coming out from the furnace is required to be removed continuously. For this, three methods, i.e., hydraulic ash handling system, mechanical ash handling system and pneumatic ash handling system are adopted. These are discussed here in detail.

12.4.1  Hydraulic Ash Handling System In this method, ash is carried out by the stream of water. Ash collected from the furnace is transported to a suitable location called as ash sump or settling pond where it is allowed to settle down. Water from the sump is recycled and used for carrying the ash again. The hydraulic system is dust-free and clean. As no mechanical part comes in contact with corrosive ash, so there is no maintenance problem. Ash is handled in cold condition. So, this system is very simple. There are two types of hydraulic ash handling systems, namely low velocity system and high velocity system. Low Velocity System In this system, low velocity water at a velocity of 3 m/s–5 m/s is used to carry out the ash removed from the boiler furnace. Ash from the grate or bottom of the furnace falls into water channel, as shown in Figure 12.2. Water flows with low velocity in the water channel and carry out ash into ash settling pond. At settling pond, ash settles down and the water is recycled. Settled ash then reclaimed and transported for disposal/dumping. There are more than one water channel per boiler. Ash carried with water contains corrosive acids and salts and it is highly abrasive in nature. So, water channels are made of corrosion and wear-resistant material. In this system, ash may be carried upto 500 m.

Figure 12.2  Low velocity system.

High Velocity System In this system, high velocity water is used to carry out the ash from the boiler.

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High pressure water is directed to ash, just coming out from the grate through a set of nozzles fitted at the hopper (Figure 12.3). This water quenches the ash. Other set of nozzles are fitted at the bottom portion. These nozzles are used to drive out the ash to the settling pond. Like low velocity system, ash is settled at settling pond and water is recycled.

Figure 12.3  High velocity system.

This method can also be used in case of pulverised boiler with dry and wet type of furnace. Water requirement in this case is lesser as compared to the low velocity system. More ash can be removed in this system and it can be transported upto 1 km distance. Sometimes, ash is pumped to the settling pond through pipeline with the help of a slurry pump (Figure 12.4). Ash collected from the boiler furnace is crushed first in a crusher. Slurry is prepared in a slurry tank. This slurry is pumped through a pump to the settling pond.

Figure 12.4  Slury pump system.

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Fly ash collected from ESP can also be put into the slurry tank to transport this ash to the settling pond.

12.4.2  Mechanical Ash Handling System In case of hydraulic method, ash is carried out by water. But in mechanical ash handling system, ash is removed by means of mechanical methods like belt conveyer or chain conveyer. Belt conveyer or drag chain conveyer is submerged in water so that the ash can be cooled. Also, the water ensures sealing of the furnace. Ash from the boiler furnace falls on the running submerged conveyer, as shown in Figure 12.5. Conveyer takes out the ash continuously to the ash hopper. From ash hopper, the ash may be transported to the ash storage area either by means of further conveyer system through truck or by slurry pump method through pipe, as discussed earlier.

Figure 12.5  Mechanical ash handling system.

Water in which the belt is submerged comes in contact with the hot corrosive ash. So, its temperature increases. Also, the water is mixed with small ash particles. So, this water is taken out to the settling pond and the recycled. Make-up water is also added to maintain the water level and temperature. If water level becomes low, then the temperature of belt may increase and it may burn out. Drag chain conveyer has no risk of high temperature failure. But as it is exposed to acidic and erosive environment, it requires proper maintenance.

12.4.3  Pneumatic Ash Handling System Pneumatic ash handling system is widely used nowadays. High pressure air is used for conveying ash to a suitable location in this case. This system handles dry fly ash. As fly ash requires more settling time at settling pond, pneumatic conveying system is preferred. Bottom ash can also be removed by this method after crushing it in a crusher. Following are the three types of pneumatic conveying system classified on the basis of air to ash ratio:

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• Lean phase • Medium phase • Dense phase

Dense phase is mostly used at power plants. In dense phase system, high pressure air consumption is less, as the volumetric ratio of air to ash is more (20-100:1). Ash flows in fluidising condition. Flow characteristic of this is like that of liquids. The average material velocity in the conveying pipeline is 4 m/s. Due to low velocity in the system, wear and tear of the conveying pipe is less. Ash is transported in an enclosed pipe. So, spillage and dust pollution are eliminated. The system can be automated easily. So, ash handling system can be operated through an automatic control system from control room. For the above advantages, dense phase conveying is preferred nowadays in place of mechanical dust handling system (screw conveyers, chain conveyers, elevators, etc.). Instead of pressurised air, vacuum is used for ash transportation sometimes. The operating procedure of dense phase conveying system is discussed here. The ash conveying system is placed below the ash hopper. If the temperature of ash is more, then the hopper is made water jacketed. Cooling water flows continuously inside this jacket. If bottom ash is to be transported, then it is to be crushed first before coming to the ash hopper. Conveying activity is controlled through the solenoid valves. The system can be operated in automode from remote or manually from local. Instrument air supply is required other than the conveying air for the operation of this system. This system is having its own control panel. Pressure switches, PLC and solenoid valves are fitted in this control panel. The system is controlled by PLC or DCS of main plant. One plate valve is placed between the ash hopper and the conveyer vessel to isolate the system for maintenance (Figure 12.6). When ash inlet valve or dome valve of the vessel opens, ash falls into the vessel of the conveyer. This dome valve or ash inlet valve closes when level switch in the vessel is operated or after some predetermined time (timer mode). When inlet valve closes it seals the ash hopper from ash vessel. The vessel is pressurised by the opening vessel pressure solenoid valve to admit compressed air into the vessel. When vessel pressure attains some predetermined value, ash discharge valve opens. When the sealing of inlet valve or ash discharge valve is not proper, pressure of the vessel does not increase. After the opening

Figure 12.6  Pneumatic ash handling.

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of discharge valve, blow valve opens to allow the conveying air. This conveying pressurised air moves the ash to the storage hopper which is located at a suitable location for further disposal. The discharge valve closes when vessel pressure reduces to some predetermined value. After some time, the blow valve closes and the ash inlet valve opens for further cycle of conveying. In this system, more than one hopper may be connected to a common conveying pipe with common conveying air. This arrangement is called master and slave arrangement. The system is most suitable for automatic operation. The conveying pipeline may be routed as per the requirement. From the storage hopper, ash may be disposed after conditioning it by an ash conditioner. Dry dust from the storage hopper is taken out by a screw conveyor where water nozzles are provided. Through these nozzles water is sprayed to the ash to make it moist. This moist ash can be loaded on truck and can be disposed off, as shown in Figure 12.7.

Figure 12.7  Ash conditioner.

12.5  SELECTION OF SUITABLE ASH HANDLING SYSTEM Different ash handling systems are used for different boilers. Ash handling system performs the following three functions:

• Remove ash from the boiler furnace and other ash collection hoppers. • Convey this ash to the storage area/storage hopper. • Dispose this ash.

Ash removal and disposal are the major functions in a boiler, specifically in a coal-fired boiler. As the ash contents in Indian coal are around 40%, so 40% of the coal burnt in a boiler is removed as ash. This huge quantity of ash is to be handled properly. Otherwise, it may lead to stoppage of the boiler. Also, the ash is at higher temperature, so proper care is to be taken. Ash produced from coal is highly abrasive and acidic in nature. So, it makes the ash handling system complicated. Selection of proper ash handling system can make this task easier. For selecting a suitable system, there are so many factors. Some of them are discussed below: Boiler design and configuration:  There are various types of boilers. The capacity also varies from a small process boiler to a large power boiler. Different types of fuels are used in different boilers. In some boilers, coal is used in pulverised form and in some cases, it is

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grate-fired or spreader stocker type. As discussed earlier, percentage of fly ash to bottom ash generation varies according to the type of boiler. In case of pulverised boiler, 60% to 80% ash is produced as fly ash and the remaining is bottom ash. In case of stoker-fired boiler, 20% to 30 % ash is produced as fly ash and the remaining is bottom ash. So, different types of ash handling systems are required for different boilers. As fly ash takes longer time to settle in settling pond, so hydraulic system may not be suitable in this case. Normally, pneumatic system is preferred here. Higher capacity boiler consumes a lot of coal, so ash production is more as compared to a lower capacity boiler. So, the size of a boiler is a factor for deciding the type of ash handling system. • Disposal condition:  In hydraulic ash conveying system, settling pond is required. This pond requires large space. So, if space is limited, hydraulic conveying system may not be suitable. Storage bin requires less space, so it can be used suitably where the space is limited. For storage bin, mechanical or pneumatic ash handling system is preferred. • Water availability:  A lot of water is required in hydraulic ash handling system. So, where the water is not available sufficiently, this system cannot be used. Other system may be used in this case. • Type of coal:  Different types of coal contain different percentage of ash, sulphur and other chemical contents. Good quality coal contains less ash, so ash production is less. Low capacity ash handling system is sufficient in this case. If coal contains high calcium oxide, then it solidifies when come in contact with water. In this case, hydraulic system is not suitable. • Distance of transportation:  The distance of ash storage area from the boiler plays a major role. When ash is to be transported to a longer distance, pneumatic or mechanical system may be used.

12.6  FLY ASH SEPARATION SYSTEM In a solid fuel-fired boiler (particularly, in coal-fired boiler) flue gas contains dust particles which is generated during combustion. These dust particles are mainly ash. This ash is called as fly ash which is required to be separated from the flue gas before it is vented to the atmosphere. Then, the separated dust is collected (Figure 12.8) and removed for disposal.

Figure 12.8  Ash collection in boiler.

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There are various methods of dust separation. In some methods, dust is separated in dry condition and in some methods, dust is separated in wet condition. Mechanical and electrostatic principles are applied for dust separation. Various methods of dust separation are as follows:

• Inertial separators

– Settling chambers – Baffle chambers – Centrifugal (cyclone) separator

• • • •

Wet scrubber Fabric separator (bag filter) Electrostatic precipitator (ESP) ESP/fabric hybrid filter

These are discussed one by one in the subsequent sections.

12.6.1  Inertial Separators In this method, forces like centrifugal, gravitational and inertia are used for dust separation from the flue gas. The separated dust is moved by gravity into a hopper from where it can be removed easily. Mostly, three types of inertial separators are used. Though these systems are not so effective, still these principles of separation are used along with other separation methods for more efficient dust separation. Settling Chamber A large box is installed in the flue gas path, as shown in Figure 12.9. Flue gas duct size increases suddenly. Due to sudden increase in the size of this chamber, flue gas speed reduces and heavier dust particles settle down in the hopper.

Figure 12.9  Settling chamber.

Normally, this method is not used alone for dust separation. This method can be used along with other methods. Baffle Chamber In this method, baffles are placed in the flue gas path, as shown in Figure 12.10. This arrangement changes the direction of flue gas flow suddenly. Heavy dust particles cannot change its direction

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Figure 12.10  Baffle chamber.

rapidly. So, these particles are settled in a dead air space due to gravity. This system is normally used along with the other dust separators. Centrifugal (Cyclone) Separator Centrifugal separator uses cyclonic action for dust separation from the flue gas. Dust-laden gas enters into the separator at an angle and spins rapidly (Figure 12.11). Due to centrifugal force created by this circular flow, heavier dust particles are thrown away towards the wall of cyclone. The dust particles fall into an ash hopper after striking the wall of the separator.

Figure 12.11  Cyclone separator.

Cyclone separator creates a dual vortex to separate heavier particles. The main vortex spins down and carries the dust particles. The inner vortex is created near bottom of the cyclone and spins upward. The separation efficiency of a cyclone separator depends upon the dimension of cyclone. Smaller diameter and smaller apex angle make the cyclone efficient. Longer size cyclone is

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efficient but increases the flow resistance. So, multiple cyclone separators are used. Small diameter and longer cyclones are connected in parallel having common flue gas inlet and outlet. A cyclone separator is having the following advantages:

• • • •

Simple construction Have no moving parts Have low pressure drop Little maintenance

12.6.2  Wet Scrubber In this method, dust is separated from the flue gas in wet condition. Normally, water is used as scrubbing liquid. Water is sprayed to the dust-laden flue gas. Dust removal efficiency is higher if the contact of flue gas and water is more. The dust particles and water droplets come in contact by four primary mechanisms. These are as follows: • Internal impaction:  When water droplet flows in the path of dust-laden gas stream, water droplets and dust particles flow in the stream. Due to inertia, heavy dust particles continue in a straight path and hit water droplets and become encapsulated. • Interception:  Finer particles moving within a gas stream do not hit droplets directly but brush against them and adhere to them. • Diffusion:  When liquid droplets are scattered among dust particles, the particles are deposited on the droplet by diffusion. • Condensation nucleation:  If the gas passing through a scrubber is cooled below the dew point, then the condensation of moisture occurs in the dust particles. This increases the particle size and makes collection easier. Dust laden flue gas enters from the lower portion of the tower. The gas distribution plate distributes the gas evenly throughout cross section of the tower. Water is sprayed from the top. Dust particle is separated and fall down with water. Clean gas leaves the tower from top. A mist eliminator (demister pad) is provided to remove water from gas, as shown in Figure 12.12.

Figure 12.12  Wet scruber.

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Another type of wet scrubber mostly used is known as venturi scrubber. In this type of separator, dust-laden gas passes through a venturi to increase the gas velocity. Water is sprayed into the venturi throat. High velocity gas immediately atomises the coarse water spray. Due to high turbulence and high velocity of flue gas, collision takes place between water droplets and dust particles at the throat. Agglomeration process takes place between them in the diverging section of the venturi. Large agglomerates formed in the venturi are removed by an internal separator. Efficiency of this type of separator depends upon the pressure drop across the venturi. In wet scrubber, water comes in contact with the flue gas which is acidic in nature. So, this system is prone to corrosion.

12.6.3  Fabric Separator (Bag Filter) In fabric separator or bag filter or bag house, fabric collectors or fabric bags are used to filter the flue gas to separate dust. Dust-laden gas enters the bag house and passes through fabric bags which act as filter. The bags are woven or felted nylon, synthetic or fibre glass fibre material. Each bag is supported by a metal cage. An explosion vent is provided to protect the bag house from any accidental explosion. Bag filter is one of the most efficient and cost-effective type of dust separator. Its collection efficiency is more than 99% and very fine particles can be separated. It is used in the boilers to separate fly ash from the flue gas. The separated fly ash is collected in a hopper from where this can be removed through mechanical screw conveyer or pneumatic conveying system. Bag house filter is used where low sulphur coal is fired. Dust is collected at the outer surface of the bag. Flue gas flows from outside to inside of the bag. The fabric/bag provides a surface on which dust particles are deposited due to the following mechanisms (shown in Figure 12.13):

Figure 12.13  Dust collection mechanism.

• Gravity:  Large size heavy dust particles fall down to the hopper placed below the bag house due to gravitational force. • Inertial collection:  Heavy dust particles strike the fibre bag placed in the flue gas path.

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They fall down into the hopper, as they cannot change their flow direction suddenly with gas stream due to inertia. • Interception:  The dust particles cannot cross the filter bag because of the fibre size. • Diffusion:  Submicron dust particles are diffused so that the probability of contact between the particle and the fabric filter surface increases. • Electrostatic:  Due to the electrostatic force between the dust particles and filter bag, dust capture capacity of the bag increases. These different mechanisms are not independent but operate simultaneously in a bag filter. The effectiveness of a mechanism depends on the particle size, mass velocity, density of gas, electrostatic forces and the type of fabric used. Dust is deposited on the surface of bag as a cake known as dust cake. Due to this dust cake, resistance of flue gas flow increases. The chocking condition of bags can be judged from the differential pressure across the filter. So, it is required to clean the bags periodically. There are two type of cleaning methods, i.e., online and offline. In case of online cleaning method, cleaning is done without interrupting dust-laden flue gas flow. In offline cleaning method, the flue gas flow is interrupted temporarily during cleaning. Depending upon the cleaning method of bags, bag filters may be divided into following three types:

• Mechanical shaker • Reverse air • Reverse jet

Mechanical Shaker In this type of filter, filter bags are shaked by a mechanical system. Force exerted on the dust particles removes them from the filter bag. Normally, this is done offline. Reverse Air Reverse air bag house (RABH) is compartmentalised so that the bags can be cleaned offline by stopping the dirty gas flow and passing clean air into the compartment in the reverse direction of the normal gas flow. The cleaning air obtained from a separate fan flows from inside to outside of the bags. Due to reverse flow of air, the dust cake breaks and falls down to the hopper. The operation is repeated until all the compartments are cleaned and returned to service. Flow reversal in the compartment is done automatically by a set of dampers and automatic sequential controller. Reverse Jet Mostly, reverse jet bag filter is preferred widely, as the cleaning of bags can be performed online. In this type of bag filter, flow of dust-laden flue gas is normally from outside to inside of the bag (Figure 12.14). Bags are cleaned by a sort burst of compressed air injected through a solenoid valve and set of nozzles. Duration of compressed air burst is very short. It acts as a rapidly moving air bubble travelling through the whole length of the bag and causing the bag

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Figure 12.14  Bag filter (reverse jet type).

surface to flex. This flexing of the bag breaks the dust cake and the dust falls into the hopper. Cleaning of few bags is done at a time while other bags continue filtration. Continuous cleaning of this type of bag filter is done automatically by a timer. So, the bags are maintained clean. Volume of gas flow per unit area of the bag is called air to cloth ratio. To clean more volume of gas, more cloth area is required to avoid large pressure drop. Normally air to cloth ratio is maintained 1:2. Depending upon the temperature of the flue gas stream, different types of fabrics are used. Higher temperature tolerance fabric is more expensive. Recommended maximum operating temperatures for various fabrics are mentioned in Table 12.1: Table 12.1  Recommended Maximum Temperatures for Various Fabrics Fabric Nylon Polyester Polyphenylene sulphide (PPS) or ryton Polytetrafluoroethylene (PTFE) or teflon Fibre glass Fibre glass fabric coated with PTFE

Continuous Working Temperature (°C) 88 135 190 240 260 260

For the selection of a suitable fabric, following important factors are considered:

• • • • • • •

Flue gas temperature Moisture level Particulate size Gas stream chemistry Oxygen percentage Air to cloth ratio Particulate abrasiveness

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12.6.4  Electrostatic Precipitator (ESP) Electrostatic precipitator uses electrostatic forces to separate dust particles from the flue gas. ESP may be installed before or after air heater of the boiler. If ESP is installed before the air heater, it is called hot side ESP. It handles high temperature dust-laden flue gas. As the volume of hot gas is more, so the size of hot side ESP is larger. If ESP is installed after the air heater, it is called cold side ESP. The basic principle of ESP is the attraction of two oppositely charged particles. Particulates present in the flue gas are negatively charged by the ionization of gas molecule. Then, these negatively charged dust particles are attracted to positively charged collecting plates. Details of the basic principle of operation of ESP is discussed in the subsequent sections. Principle of Operation ESP consists of a number of discharge electrodes and collecting plates (Figure 12.15). The discharge electrode is connected to the negative terminal of high voltage direct current source. High voltage direct current (DC) is obtained through a transformer rectifier (TR) set. The collecting plate (normally a large flat surface) is connected to earth.

Figure 12.15  Electrostatic precipitator.

Dust-laden flue gas flows between these two electrodes. When supply is given to the discharge electrode, electric field is created. Due to high field strength, corona is established. Corona is the ionization of gas molecules by the high energy electrodes in a strong electric field. This corona charges the particulates present in the flue gas. These charged particulates are attracted by the collecting plates. Once these charged particulates come in contact with the collecting electrodes, they lose their charge. Particles are attached to the collecting surface and form a dust cake. Periodically a rapper strikes the collecting plate to dislodge the collected ash. This dislodged ash then falls into an ash hopper placed below ESP. Total function of ESP may be divided into following three parts:

• Ionization of dust particles flowing between the electrodes • Migration and collection of particles on oppositely charged collecting plates • Removal of particle from collecting surface to a hopper by vibrating or rapping the collecting surface

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The main components of ESP are as follows:

• • • •

Power supply unit (TR unit) Ionizing section and collecting surface A means of removing the collected particles A housing to enclose

Factors Affecting the Performance of ESP There are many factors which influence the performance of an ESP. These are discussed below: • Corona:  Corona ionizes gas molecules and charges dust particles. At higher temperature, flue gas density reduces. Lower density of the flue gas initiate corona at lower voltage. Corona power is the power required to energise the discharge electrode and create corona. Corona power is expressed in watts per 1000 cubic metre per hour or watts per 1000 actual cubic feet per minute (ACFM). It is approximately 60 to 300 watts per 1000 cubic metre per hour. • Resistivity of particulates:  It is a main factor that influences an ESP performance. This is the measurement of resistance to electrical conduction. Resistivity is the electrical resistance of a dust sample of 1 cm2 in cross section and 1 cm in thickness. The unit of resistivity is ohm centimetre (W cm) and it is normally 108 to 1012 for coal fly ash. The charged particulates are supposed to transfer their charge to the collecting plate. It is difficult to charge the particulates having high resistance. But once they are charged, they do not give up their acquired charge to the collecting plate easily. The particles having low resistivity can be charged easily and give up their acquired charge easily. If the resistivity is too low, the particulates discharge their charge too quickly and escape from the collecting plate and come back to the gas stream again. This phenomenon is called as re-entrain. If the resistivity is too high, particles do not give up their charge completely to the collecting electrode. So, the charge is accumulated on the collecting plate and leads to back corona. This back corona reduces ionization and particles escape with the flue gas. The particles also remain strongly attracted to the collecting plate, as they are still having charge. So, it is difficult to rap off. The major factors that influence ash resistivity are temperature, carbon particles and chemical composition (sodium and sulphur trioxide). Carbon particulates in the fly ash reduce resistivity. The resistivity of ash versus temperature for different sulphur containing coal is shown in Figure 12.16.

Figure 12.16  Resistivity of ash.

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The resistivity is maximum between 300 °F to 400 °F. Resistivity of low sulphur coal is more. To make the resistivity normal, gas conditioning is required. Small amount of sulphur trioxide (SO3) is injected into the flue gas when low sulphur coal is used in boiler to reduce flue gas resistivity. The critical sulphur level of ash particle for better performance of ESP is 0.5% of the flue gas. 10 ppm to 20 ppm of SO3 is sufficient in flue gas to maintain the resistivity of fly ash below the critical level. In case of high sulphur coal, SO3 level is more, so the resistivity is less. To maintain the resistivity, ammonia (NH3) is injected into the flue gas for conditioning. • Flue gas velocity:  It is having a significant effect on the dust collection efficiency of ESP. Efficiency increases when flue gas velocity decreases. Two forces act on a particle at ESP. First is due to the flue gas flow and second is due to the electrostatic force created. They are at right angle to each other [Figure 12.17(a)]. So, the particle flows in the resultant direction. If the electrostatic force is higher than the force exerted due to flue gas flow, then the particle flows in path 1, as shown in Figure  12.17(b) and gets collected at the collecting plate. If the flue gas velocity is higher than the electrostatic force, then the particle follows path 2, as shown in Figure 12.17(b) and escape from the collecting plate.

Figure 12.17  (a) Resultant force on particle and (b) Flow direction of particle.

Low gas velocity also provides sufficient residual time for proper charging and collection of dust particles. High gas velocity may lead to erosion. Gas velocity of 0.75 m/s is suitable for ESP. Gas flow through ESP chamber should be slow and evenly distributed. Gas velocity is reduced in ESP by the expansion at diverging section of inlet plenum. Inlet plenum contains perforated diffuser plates (Figure 12.18) to evenly distribute the gas inside the ESP chamber. ESP chamber is formed by gastight plates.

Figure 12.18  Inlet plenum.

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• Particle migration velocity:  The operating principle of ESP is based on Deutsch–Anderson equation. The simpler form of this equtation is given by

h = 1 – e–w(A/Q)

where h = collection efficiency of the precipitator e = base natural logarithm (2.718) w = migration velocity or drift velocity of dust in centimetre per second A = effective collecting plate area in square metre and Q = gas flow through ESP in cubic metre per second Migration velocity or draft velocity is the speed at which the particles migrate towards the collecting plate after they are charged. Migration velocity is affected by particle size, strength of electric field and viscosity of the gas. Migration velocity is given by w=

d p Eo E p

4pm where w = migration velocity dp = diameter of the particle in micrometre Eo = strength of field in which particles are charged (represented by peak voltage in volts per metre) Ep = strength of field in which particles are collected (in volts per metre) m = gas viscosity p = 3.14 From the above discussion, it is clear that by increasing the field strength, migration velocity increases. So, the collection efficiency also increases. Like this, large particle size increases the migration velocity and hence, the collection efficiency too. • Collecting plate area:  From Deutsch–Anderson equation, it is clear that collection efficiency increases with the increase in collecting plate area. In an ESP, the collecting plates and discharge electrodes are placed in parallel with the gas flow. There are a number of collecting plates provided across the width of an ESP (Figure 12.19).

Figure 12.19  Collecting plate.

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The passage between two collecting electrodes is called channel.

Number of channel = N – 1

where, N is the number of collecting plates. So, the collecting plate area is given by A = Ap  (N – 1)  Ns where A = area of collecting plate in square metre Ap = area of each plate (Height of plate H  Length of plate L) N = number of plates Ns = number of sections Specific collection area (SCA) is defined as the ratio of collecting surface area to the gas flow through ESP. This is the ratio A/Q, as mentioned in Deutsch–Anderson equation. SCA =

Total collection surface (m 2 ) Gas flow rate

Specific collection area of 200 m2/m3/s is suitable for an ESP. • Aspect ratio:  Aspect ratio is the ratio of length to height of an ESP. This ratio is an important factor for reducing the rapping loss (dust reentrainment). If the height of collecting plate is more as compared to the length, then during rapping, the dislodged dust particle are carried out by the gas flow before they settle in the dust hopper. So, the collection efficiency decreases. Aspect ratio =

Effective length (m) Effective height (m)

Effective length of the collecting surface is the sum of plate lengths in each section and effective height is the height of plate. If the plate length is 3 m and there are five sections, then the effective length is 3  5 or 15 m. If the height of each plate is 10 m, then the aspect ratio in this case is 15/10 or 1.5. Aspect ratio of ESP is kept approximately between 0.5 and 2. • Sectionalisation:  To collect dust in an ESP efficiently, ESP is divided into a series of independent sections or fields in the direction of flow. Each field is having separate power supply units (TR sets) to energise the discharge electrodes. This type of arrangement provides better flexibility. The dust load at the inlet section of the ESP is more and it gradually comes down as it is collected in the upstream sections. The gas is clean towards the outlet end (Figure 12.20). So, more power is required at the inlet end to charge the dust particles. As the dust concentration is more at this end, so most of the particles are collected at this field. At the downstream field of ESP, dust concentration is less, so less power is required to charge the remaining particles. Sectionalisation of fields provides flexibility to operate an ESP in various conditions. ESP can also be put in service if one field is down. Depending upon the quantity of flue gas to be cleaned and the dust load, number of sections may be taken into line.

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Figure 12.20  Sectionalisation of ESP.

Removal of Fly Ash We have discussed how the fly ash is collected in the collecting plate. Now, it is required to remove this from the plate periodically so that ESP can be operated continuously. Dust is removed from the collecting plate by rapping the plates or causing vibration. The dust falls onto a hopper from where this can be taken out continuously with the help of a screw conveyer or pneumatic system. The discharge electrode also requires rapping. There are two types of rapping. In the first type, known as magnetic impulse rapper, the plate is rapped by a falling weight. The weight is normally lifted by an electromagnet. Intensity of rapping can be adjusted by varying the height from which the weight is dropped. This is done by adjusting the accelerated field strength. In the second type of rapping, known as tumbling hammer, a rotating hammer is used. To change the intensity of rapping, the weight of the hammer is changed. Both types of rappers are having a facility to adjust the rapping interval which is set between 1 to 10 minutes depending upon the condition. Normally, one rapper is provided for every 1200 to 1500 square feet of collecting area. Dust falling onto the hopper after rapping is stored there temporarily. These hoppers are pyramid-shaped that converge to round or square discharge end. Hopper walls are steeply sloped to prevent dust accumulation in the side wall. There are different hoppers for different sections of ESP. Screw conveying or pneumatic conveying is used to remove ash from the hopper. Advantages and Disadvantages of ESP ESP is a very efficient dust separation unit used in the boilers. It is having some advantages and disadvantages which are discussed below: • Advantages:  The advantages are as follows:

• Pressure drop of flue gas across ESP is very less. • ESP has collection efficiency.

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• Silicon control rectifiers (SCR) and other modern control devices allow an ESP to operate automatically. • Maintenance cost is low.

• Disadvantages:  The disadvantages are as follows:

• Size of an ESP is large. • It is prone to corrosion if the temperature of any part (which is exposed to the flue gas) drops below the acid dew point. • ESP is designed for a particular type of fuel. If the fuel characteristic changes, then the performance of ESP also changes. • Capital cost of ESP is high. • For heavy dust load, suitable precleaner may be required. • As it operates at high voltage, so it requires proper skill to handle. • If any combustible particle enters into ESP and a spark is initiated, there is a chance of explosion.

12.6.5  ESP/Fabric Hybrid Filter To get a lower emission level, ESP/fabric hybrid filter is used nowadays in Indian power plants. This is a combination of ESP and fabric filter. It has two separate sections. A majority of dust particles is collected at ESP section first. So, the dust load reduces at the subsequent fabric filter section. Fine particles are collected at fabric filter section. So, lower emission is possible.

12.7  UTILISATION OF ASH Indian coal contains high percentage of ash. In thermal power plants, huge amount of ash is produced. So, a lot of space is required to dump this ash. Also, it creates a lot of dust nuisance. For this, it is required to use as much ash as possible in a better way. Government of India is very serious in this regard. Ministry of environment and forest had brought a draft amendment on 6th November 2002 for the utilization of this ash. As per this gazette, construction company (like housing boards, hotels etc.) which are situated within 50 km to 100 km from a coal-fired thermal power plant are required to use a certain minimum percentage (by volume of their total consumption) of ash products like bricks, blocks, tiles, etc. Fly ash utilization program (FAUP) is started in India with the help of ministry of science and technology, ministry of power and ministry of environment and forest. A lot of initiatives have been taken by technology information forecasting and assessment council (TIFAC). Government of India had organized international congress on fly ash (2005) at New Delhi during 4th to 7th December 2005 with the help of fly ash mission (FAM), fly ash utilization program (FAUP) and other government institutes. National highway authority of India (NHAI) is using ash in its ongoing projects. Some reputed government institutions of India have developed following fly ash-based building components for their use in houses:

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Wood substitute door panel by RRL, Bhopal Ceramic tiles (containing 35% ash) by CGCRI, Ahmedabad Fly ash granite (60% ash) by BHEL Sintered aggregates (70%–85% ash) by RRL, Bhubaneswar

Other than this, fly ash bricks and blocks are produced by the local suppliers. The above discussion indicates the seriousness of government of India for the utilization of ash. The ash is collected in three ways from a coal-fired boiler, as discussed earlier. These are as follows:

• Bottom ash • Fly ash • Pond ash (ash collected from settling pond) These ashes may be used in different ways, as discussed here.

12.7.1  Construction of Embankments and Fills The geotechnical property of ash is suitable for fill and embankment construction. Indian road congress (IRC) has issued guidelines for the use of ash in road embankment. Merits of ash for this purpose are as follows:

• Ash is lighter than the soil. Density of ash is lower than the soil. So, it minimises transportation cost. • Ash is suitable in weak/clayey subsoils. • It has low compressibility, so there is negligible subsequent settlement within the fills. • During rainy season also, work can be done, as ash is having quick draining properties. • It is eco-friendly, as soil is not to be taken out from the agriculture land.

12.7.2  Road Construction Bottom ash, fly ash and pond ash can be used for road construction. Bottom ash can be used for subbase of road, fly ash and pond ash can be used with soil/lime/cement/moorum for base or subbase purpose. Fly ash can be mixed with cement concrete for a rigid final layer.

12.7.3  Pozzolana Cement Manufacturing Flay ash-based Portland pozzolana cement (FAPPC) is found to be more effective than ordinary Portland cement (OPC). Fly ash contains approximately 45% silica (SiO2), 21% alumina (Al2O3) and 17% ferric oxide (Fe2O3). Silica present in fly ash reacts with lime [calcium hydroxide or Ca(OH2)] in the presence of water and forms calcium silicate hydrate gel which is a binding material. Otherwise, this calcium hydroxide would not be utilised. Fly ash-based Portland pozzolana cement (FAPPC) is produced by grinding Portland cement clinker, fly ash and gypsum in certain proportion.

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12.7.4  Cement Concrete and Mortar While preparing cement concrete or mortar, upto 35% of fly ash can be used in place of cement and sand. It improves the strength, workability and reduces the cost. This can be used for foundation, walls, floors, etc.

12.7.5  Brick Manufacturing Fly ash may be used for brick manufacturing for the construction purposes. These bricks are of higher quality than the normal clay bricks. The test result shows that the compressive strength of a normal clay brick having 40 kg clay and 10 kg sand is 60.47 kg/cm2, whereas in case of a fly ash clay brick manufactured from 50 kg clay and 20 kg fly ash, this strength is 81.5 kg/cm2. Another type of fly ash brick is manufactured by mixing the fly ash, sand and lime or cement. These bricks have smooth and plain surface. So, the requirement of mortar for joining and plastering of the surface reduces by 25%. Also, these bricks are lighter than the conventional clay bricks. Water absorption power of these bricks is less than 20% than that of clay bricks. So, the outer surface of the wall may not require plaster. Clay bricks cannot be manufactured during rainy season. But these fly ash bricks can be manufactured throughout the year.

12.7.6  Manufacturing Building Components As discussed earlier, fly ash may be used for the manufacturing of wood substitute door panel, partition panel, tiles, granite, blocks, etc. used in the interior of a building.

12.7.7  Backfilling of Mines Ash may be used to fill up the mining area from where coal is mined. Coal is mined from the open cast as well as from the underground mines. These mines require a lot of material to fill up. So, ash may be the most suitable material for this purpose.

EXERCISES

1. 2. 3. 4. 5. 6. 7. 8.

What are the main constituents of ash? What is the difference between wet bottom and dry bottom furnace? What is fly ash? How is it separated from the flue gas? Why is sealing required at the bottom ash hopper? What are the main ash handling methods adopted for ash removal from a boiler? What is ash settling pond? What are the merits of pneumatic ash handling system? What is dense phase ash handling system?

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What are the cleaning methods adopted to clean bags of fabric filter? What is reverse jet cleaning? What is air to cloth ratio? What is the principle of operation of an ESP? What are the main components of an ESP? How does the resistivity of dust particle affect an ESP performance? What is the aspect ratio and specific collection area of an ESP? Which methods are used to remove ash from the collecting plate? What are the main uses of fly ash?

9. 10. 11. 12. 13. 14. 15. 16. 17.

Chapter

13

Operation of Boiler

13.1  Introduction In previous chapters, we have discussed so many aspects about constructional features of a boiler. Now we will discuss about the operation of a boiler. This will give an idea to a boiler engineer that how a boiler is operated practically during different conditions and situations. Starting of a boiler is discussed step by step. In a running boiler, so many parameters like steam pressure, temperature, etc. are monitored. There are different methods to control these parameters. Some boilers are operated in full automode so that any variation in any parameter can be taken care automatically without any manual intervention. Apart from routine operation, it is required to take care during emergency situations. Routine inspection is carried out to avoid any undesirable situation. To shut down the boiler, some operational practices are followed. Also, when boiler is to be kept out of service for a longer period, it is to be kept in such a condition that corrosion does not take place at pressure parts of the boiler. All these operational practices are discussed step by step in the subsequent sections.

13.2  Feedwater fill-up in boiler Steam is generated from water in a boiler. So, initially, the boiler is to be filled with feedwater. Economiser, water walls and evaporators are to be filled prior to light up a boiler. As discussed in previous chapters, feedwater is pumped from deaerator to economiser through a boiler feed pump. After economiser is filled up, water enters into the boiler drum. From drum, water comes down through downcomer tubes and evaporators/water walls are gradually filled up. When all these tubes are filled up, then water level in the drum starts increasing. Air present in economiser and evaporator/water walls is vented during initial water fill-up. Otherwise, the air may be trapped in the system and affect heat transfer. For venting the air from the system, air vents are provided at economiser and steam drum. Water holding capacity (i.e., the total water that is hold at different heat transfer elements of the boiler) is mentioned by the boiler manufacturer. This can indicate how much feedwater is required for initial fill-up of a boiler. Following steps are followed for initial fill-up of a boiler but it is recommended to follow the instruction of the boiler manufacturer, as mentioned in their operation and maintenance manual:

• Take sufficient feedwater into a deaerator storage tank. When boiler is in cold condition, water at normal temperature may be used. 237

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• Ensure all the required isolating valves of feedwater line of a boiler feed pump is in open condition. • Ensure gland cooling and bearing cooling water is available for boiler feed pump. Check healthiness of the pump. • Keep economiser air vent and steam drum vent in open condition. • Start boiler feed pump by keeping the discharge valve closed. Observe pump vibration, temperature, sound and current taken. • Open pump discharge valve slowly and notice the change in vibration, sound, current taken, suction pressure, etc. • Start taking feedwater into an economiser slowly by opening feedwater control valve. If the feedwater is hot, it should enter into the economiser slowly to avoid any thermal shock. Flow of water to the boiler may be controlled by feed control valve. • After some time when the water is filled up in the economiser, it starts coming out from the economiser vent. • When water comes out from the vent in pressure, then stop the vent valve. • Now, water starts entering into the steam drum. From steam drum, this water comes down through downcomers and water wall tubes/evaporators are filled up gradually. • When all water tubes are filled up, drum level gets raised. • Keep the drum level below the normal working level. When the boiler is fired, the temperature of water increases and hence, the volume too. Water level swells when it is heated. This is called as swelling. Drum level may be adjusted after swelling.

Mostly, this procedure is followed in all boilers for feedwater fill-up. For hydro test, all the pressure parts of the boiler are to be filled up with feedwater. Superheater can be filled up after filling the drum fully. In that case, drum is filled till water comes out from the drum air vent. When water comes out in pressure from this vent, then the valve is closed. Now, the water enters into the superheater. For filling superheater, superheater vent valve is to be kept open and drain valve is to be closed. When water comes out from the superheater vent, then this valve is to be closed. Now, the feed control valve may be closed, otherwise the pressure of the pressure parts will start increasing. A boiler feedwater circuit for hydrotest is shown in Figure 13.1. Hydro test procedure is discussed later.

Figure 13.1  Boiler feedwater circuit for hydro test.

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13.3  Boiler Start-up After taking water into the boiler, fuel firing is started. This is called boiler light up. There are two types of start-up depending upon the hot condition of the boiler. If it is started from cold condition, it is called as cold start-up. If it is started from hot condition (boiler is in pressurised condition), it is called as hot start-up or hot restart. This situation comes when the boiler is to be started after a short duration of stoppage. These two types of start-up are discussed separately. The starting procedures for different types of boilers are different. In this section, proper care is taken to cover the normal starting procedures for all types of boilers. Still, the boiler operation manual supplied by the boiler manufacturer may be most helpful. Operating personnel are required to be familiar with the boiler system. He should have an idea about the safe operating limits of different parameters.

13.3.1  Cold Start-Up As mentioned earlier, in this type of start-up, the boiler is started from complete cold condition to the normal working condition. In this situation, the boiler is started after a long period of stoppage. A lot of care is required to be taken in this condition. Prestart-up Checking Some special care is to be taken during the start-up of a boiler, particularly during cold start-up. Mostly after maintenance and repairing of boiler, cold start-up procedure is followed. So, careful checking of the complete system is required. To avoid the chances of missing any point, a checklist may be used. A sample prestart-up checklist is given in Table 13.1. A person after checking a point may put his initial if he found this point is healthy. During the starting of a boiler, a lot of activities are involved and there is always a pressure from the top officials to start the boiler quickly. This type of checklist ensures the chances of overlooking any point. Table 13.1  Prestart-up Check List S.No.

Check Points

1 2

Entire maintenance job is complete. No work permit is pending with electrical/mechanical/control and instrumentation. Trail run of all auxiliary equipments are completed. Boiler area is clean. No foreign material like scaffolding material is inside the boiler. No foreign material like welding rod, cotton waste, etc. are present inside the pressure parts, particularly inside the steam drum. All access doors on the air path and flue gas ducts are closed. Retractable soot blowers are in retracting position. Normal HT/LT electric power is available.

3 4 5 6 7 8 9

Condition Healthy or Not

Checked by

(Contd.)

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Table 13.1  Prestart-up Check List (Contd.) S.No. 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26

Check Points

Condition Healthy or Not

Checked by

Instrumentation air is available. Cooling water is available. Sufficient DM water is available. All unauthorised personnel are removed from the area. Sufficient fuel is available in day tank/coal bunker. Furnace ash hopper water sealing is healthy. Start-up burner is in correct position. Start-up oil system is in line. All control valves are in manual mode and in closed position. All instruments and transmitters are in line. Water level is normal in the boiler drum. Safety valves are not in gagging condition. All drain and vent valves are in start-up condition. Pulverisers and feeders are available for service. All trip interlocks and alarms are healthy. ID/FD fan dampers are operating smoothly and inlet dampers are in closed position. Boiler feed pump is in service.

Some other checkpoints may be added to this depending upon the type of boiler and the actual checks required. A start-up valve position chart may be prepared showing which valve is to be kept in open condition and which valve is to be kept in closed condition. This helps the operating staffs to close/open the required valve during prestart-up check and avoid any confusion during start-up. A sample start-up valve position is given in Table 13.2. Depending upon the type of boiler, some more start-up valve positions may be prepared as per the requirement. Table 13.2  Start-up Position of Drains and Vent Valves Valves Drum Vent Start-up Vent

Start-up Position open open

Superheater Vent open Main Steam Line Drain open Superheater Drain open

When to Open/Close Close when drum pressure reaches 2 kg/cm2. Throttle when boiler starts steaming and close after steam is drawn from the boiler. Close when steaming. Throttle when steaming and close when the steam is drawn. Throttle when steaming and close the when steam is drawn.

Light up Light up procedure for different boilers is different. Here, it is tried to describe the light up procedure of commonly used boilers (stoker-fired, pulverised, oil-fired, FBC boiler).



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In case of oil fired, pulverised and FBC boilers, light diesel oil (LDO) is used for start up. For chain/grate/stoker-fired boiler, initial firing is done with the help of wood pieces. Wood pieces are kept on the chain/grate. It is then fired with help of cotton waste dipped in diesel. When wood starts burning and temperature raises, coal feeding is started. Various steps that may be followed for the light up of boilers are discussed here. Liquid fuel, pulverised coal and FBC boiler:  The steps for light up of these types of boilers are given below:





• Close the outlet damper of ID fan and start the fan. After starting, regulate the damper to get negative pressure in the furnace. • Start FD fan. After starting, regulate the damper to get minimum 30% of the total air flow. Adjust furnace pressure by adjusting the damper or speed of the ID fan. If any combustible gas is present inside, the furnace will be taken out. It is called as furnace purging. • Start LDO pump and open atomising air of start-up burner and ensure sufficient pressure at LDO line. • After purging of furnace, start LDO burner. Then, the oil solenoid valve opens and sparking takes place at the spark rod. • Check flame of the burner and adjust. Normally, the lower tier burner is started first in case of oil and pulverised boilers. • Slowly increase firing rate by adjusting LDO flow rate. Adjust secondary air as per the requirement. Increase furnace temperature gradually. • When temperature of furnace reaches more than the ignition temperature, pulverised coal or heavy fuel oil (HFO) burner may come on line. • In case of HFO-fired boiler, HFO pump is to be started. Oil heater is to be on line. After opening the atomising steam, burner is to be started. Normally, the burner placed at the upper tier of a start-up burner is made on line. • In case of a pulverised boiler, pulveriser may be started and the burner may be placed on line. • In case of a FBC boiler, start-up burner is directed towards the bed material. If there is no start-up burner, bed temperature can be increased initially by using charcoal. Bed mixing is done to obtain uniform bed temperature. Coal feeding is started when bed temperature becomes higher than the coal ignition temperature (around 600 °C). • The water starts swelling. Adjust the drum level by giving blowdown. When drum pressure reaches 2 kg/cm2, close the drum air vent. • During heat up, the boiler is free to expand. Check the expansion and record. • Control the rate of fuel supply so that rate the of raise of saturated temperature follows the start-up curve, as specified by the boiler manufacturer. In case of waste heat recovery boiler, the flow of flue gas inside the boiler is to be regulated to get this. • Fuel is to be adjusted in such a way so that in any case, the furnace temperature does not exceed the limit, as specified by the boiler manufacturer. During starting, there is no steam flow or the steam flow is less in the superheater. So, the furnace exit temperature of the flue gas is to be kept within limit during starting. Coal feeding rate to the pulveriser is to be controlled in case of a pulverised boiler. In case of a FBC boiler, compartments are

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to be activated gradually. Primary and secondary air are to be adjusted to ensure proper combustion of fuel. Furnace draft is maintained properly by adjusting ID fan damper. When drum pressure and temperature increase, throttle drains and vents, as mentioned in start-up position of valves and drains. Maintain sufficient flow of steam in the superheater by adjusting the start-up vent to avoid overheating of superheater tube. Start other burners as per the requirement and stop start-up burner. Fuel feeding may be increased slowly as per the requirement. When the minimum required steam temperature and pressure are achieved, the main steam isolation valve of the boiler may be opened. In case of turbine use, starting activity of turbine may be started. Steam coil air preheater (SCAPH) if provided, may be charged. Deaerator steam may be charged to heat feedwater. Deaerator pressure may be maintained by controlling the pressure control valve. Deaerator is to be charged slowly to avoid hammering. HP/LP dosing may be started. Close opened/throttled vents and drains as per the start-up position. Gradually steam temperature and pressure reach to their normal values. Now, the boiler is ready to be loaded fully. Other burners/pulverisers may be taken into line as per the load demand. More compartments may be activated in case of a FBC boiler. Ash handling system is to be started for ash removal. ESP field may be charged when the flue gas temperature is more than the desired temperature as per the ESP design. Before charging ESP, steps mentioned in the ESP manual may be followed. Put burner management system and other controls in automode when situation permits. Turbo feed pump may be started.

Chain/grate/spreader stoker-boiler:  Initial firing procedure of this type of boilers is different from the firing procedure of oil, pulverised and FBC boilers. There is no burner arrangement in these boilers. So, initial firing is done manually. Wood, charcoal, coal, cotton waste, jute and other combustible materials are kept on the grate. With the help of cotton waste and jute, firing of the above materials is done. Normally, ID and FD fans are not started during this period. When wood cuts fire, air is supplied through FD fan as per the requirement. Small amount of coal is put into the fire through spreader or coal control grate. When it is ensured that coal has cut fire, then the feeding of coal is controlled and the grate is allowed to move slowly. Firing rate is controlled as per the start-up curve. After that, other starting steps (as mentioned earlier) are followed. Proper bed thickness is maintained as per the requirement and the supply of air is done through FD fan. Proper draft is maintained by ID Fan. When coal burning is proper on the grate and the steam temperature and pressure are normal, then the boiler can be loaded. The above discussion may give a preliminary idea about light up of a boiler. In actual situation, steps mentioned here may vary depending upon the type of boiler and fuel used. It is always recommended to follow the starting procedure of the boiler manufacturer.

13.3.2  Hot Start-Up When the boiler is restarted after a short duration of outage, it is called as hot start-up.

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The boiler is already in pressurised and hot condition. Following steps are required to be followed for hot start-up:

• Check the required points as per the checklist earlier mentioned in cold start up. • Crack open superheater drain and other start-up drains as far as practicable, keeping in view the existing boiler pressure. • Start ID and FD fan. Ensure minimum 30% of the air flow and maintain the draft. Purge the furnace, as mentioned earlier. • If the furnace temperature is more than the fuel ignition temperature, feed fuel slowly. Otherwise, make a start-up burner on line and then, the main fuel too. • Ensure that the condensate in the superheater is drained completely. Then, the superheater drain may be closed. Start-up vent may be used as per the requirement to maintain the steam flow through the superheater. • Raise steam temperature and pressure as per the hot start-up curve. Accordingly, fuel supply may be adjusted. • Main steam stop valve may be opened and start-up vent may be closed.

13.4  BOILER LOAD INCREASING/DECREASING To generate more steam, more heat input is given to the boiler furnace by supplying more fuel which requires more combustion air to burn. More air can be supplied by opening the FD fan damper more widely or by increasing the speed of fan. When more air is supplied for combustion, furnace draft is disturbed. So, ID fan damper is to be opened more or the speed of the fan is to be increased to maintain the furnace draft. During decreasing of load, it is in reverse way, i.e., fuel supply is decreased and hence, FD fan damper and ID fan damper are also decreased or the speeds of both the fans are decreased. Nowadays, all these functions are performed automatically with help of an advanced control system. Steam pressure is the master controller which controls all these activities. Steam pressure varies with the load on the boiler. Pressure drops when steam demand is more and increases when load demand is less with a fixed supply of fuel. Pressure controller depending upon the steam pressure, gives signal to adjust the fuel supply, combustion air and draft of the boiler furnace. Now, we will discuss how fuel supply is controlled in different type of boilers to maintain the steam pressure. Oil-fired Boiler Each oil burner is having its own isolating valve and a trip valve (solenoid valve). There is oil trip valve (OTV) and oil return valve (ORV) at the main oil supply line, as shown in Figure 13.2. When oil return valve is closed, oil pressure increases and when oil return valve is opened, oil pressure decreases. To increase oil flow in the burner, oil pressure is increased by closing the return valve. To decrease oil flow, oil return valve is opened. When oil flow in a burner becomes more than 80% of the rated capacity, another burner is made on line. Like this, when flow in burner decreases below 80% of the rated capacity, one burner may be taken out of service.

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Figure 13.2  Oil burner arrangement.

Trip valve closes automatically when the boiler trips. Pulverised Coal-fired Boiler In this case, to increase load, coal feeder speed is increased. So, more coal enters into the pulveriser. Accordingly, hot primary air damper is opened more to maintain the coal temperature. Secondary air is supplied as per the requirement and finally, the draft is maintained through ID fan. If the pulveriser system is a unit system, second pulveriser is to be made on line when the feeder loading of first pulveriser exceeds 80% of its rated capacity and the pulverisers may be adjusted to share an equal load. To decrease the load, feeder speed may be decreased to supply less coal to the pulveriser. When feeder rating drops to minimum, stop the feeder and close hot primary air. Stop pulveriser when the temperature drops and the pulveriser is empty. FBC Boiler Coal feeder speed is increased or decreased as per the requirement of steam. Fuel bed is sectionalised having independent coal feeder and air supply arrangement. In case of lower load, coal supply and fluidising air may be stopped to one compartment. This is called as bed slumping. Bed temperature of the slumped compartment is required to be maintained. This is done by supplying fluidising air and coal supply for a short period. In case of higher load, more compartments may be taken into service. Spreader Stoker/Grate-fired Boiler In this case, the speed of coal feeder is increased to supply more coal to the boiler in case of increased demand.

13.5  SHUTDOWN OF BOILER Like start-up, some steps are also followed to stop or shutdown the boiler. There are two types of shutdown. One is shutdown to cold and another is shutdown to hot. In shutdown to cold, boiler pressure is brought down from operating condition to the atmospheric and the boiler is cooled down completely. This type of shutdown is required when some repairing job is required in the boiler and this shutdown is required for a longer period.

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In case of shutdown to hot, the boiler load is reduced to zero and the fuel supply is cut off. Boiler is boxed up to keep the boiler in the existing pressure and temperature condition. There is another type of shutdown called emergency shutdown. It is same as shutdown to cold but with rapid rate of cooling. It is required when the boiler is to be stopped under an emergency condition. These types of shutdown methods are discussed here in detail.

13.5.1  Shutdown to Cold As discussed earlier, the boiler is stopped from the operating condition and allowed to cool down. Boiler pressure is allowed to drop to the atmospheric pressure. Some important steps are discussed below:



• Reduce load of the boiler gradually. Accordingly, the fuel is to be reduced. In case of pulverised and oil-fired boilers, burners at the upper tire may be preferred to stop first. When fuel flow in the burner/pulveriser comes down to minimum, burner/pulveriser may be stopped. In case of grate/spreader and FBC boilers, coal feeding may be reduced as per the requirement. • Soot blowers are to be operated at 50% load of the boiler. • Whenever required, put boiler control in manual mode. Stop burner, pulverisers and fuel feeding to the boiler. • Maintain the boiler draft and the air flow. Stop the main steam stop valve when the external load becomes zero. • Observe the boiler expansion positioners. • Open the superheater drains and vents when the pressure is reduced. • Keep FD and ID fan in operation to achieve the desired rate of cooling. These fans should not be stopped till the flue gas temperature at the air heater inlet drops. • If rapid cooling is required, furnace doors may be opened. • Maintain the normal water level. • When the drum pressure drops to 2 kg/cm2, open the drum air vent. • If the boiler is required to be made empty, water may be drained out when the temperature of drum water comes down to 90 °C.

13.5.2  Shutdown to Hot In this situation, the boiler is stopped for a shorter duration. The existing pressure and temperature of the boiler are maintained. Load on the boiler is reduced. Fuel supply is cut off and the main steam stop valve is closed. Superheater drains and vents are kept in closed position to keep the boiler in pressurised condition. After the fire in the boiler furnace is off, ID and FD fans are kept in service for few minuets with the minimum air flow. Then, these fans are stopped and dampers are closed. This condition is called hot banking or hot box up condition. In case of emergency shutdown, pressure of the boiler is reduced rapidly by opening the superheater drain, vent and if required, through start-up vent also. Sufficient air is allowed to

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flow through the boiler furnace to cool down rapidly. If required, the furnace doors are also opened.

13.6  NORMAL OPERATION OF BOILER Most of the time, boiler runs in normal condition. During normal operation, following activities are performed mostly:

• • • • • • • • • • • • • • •

Generating steam as per the required quantity Maintaining steam temperature and pressure within limit Maintaining flue gas temperature at various zones Maintaining draft at various locations Uninterrupted supply of feedwater to the boiler for maintaining the drum level Controlling boiler water quality Continuous supply of fuel to the boiler Monitoring firing condition in the furnace Ensuring complete combustion of fuel without much excess air Supplying the required primary and secondary air at desired temperature Removing ash from the boiler Routine checking of the boiler and the healthiness of support system Logging of important parameters Soot blowing as per the requirement to maintain the flue gas exit temperature within limit Taking proper action in case of any abnormality and initiating an alarm

In a modern boiler, most of the above activities are performed automatically with the help of a sophisticated automation system. Most important job is to check the healthiness of all support system regularly. For this, some routine checking is to be carried out. Here is an example of routine checking schedule of a boiler. Depending upon the requirement, this may be modified. At least once in every two hours these points may be checked. Routine Checking of Boiler During Normal Operation This involves to ensure the following things:

• Sufficient fuel is available and fuel handling system equipments are healthy. • Ash handling system is working properly. There is no jamming and problem in the system. • Field equipments like ID fan, FD fan, boiler feed pump, ESP, bag filter, dosing pumps, pulverisers, feeders, instrument air compressor, etc. are running smoothly. • Water level at gauge glass is at normal range and matching with the remote water level. • No leakage at steam, feedwater, flue gas and fuel system. • Sufficient dosing chemical is available in the dosing tank. • Feed water, boiler water, saturated steam (steam from the drum), superheated steam qualities are tested at laboratory and the results are within limit. • Sufficient DM water is available at DM tank. • Automatic control system is working properly. • All abnormality conditions, initiated by alarm have been taken care.

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Firing condition of the furnace is normal. Cooling water is available to all the coolers. All field instrument readings are matching with the remote readings. Position of all control valves/isolation valves are as per the requirement.

If any abnormality is found, this is to be rectified as and when the situation permits. For this, a defect register may be maintained where any defects noticed can be noted for further rectification. Soot blowing is to be carried out whenever required. When soot is deposited on the tube, heat transfer is affected. Exhaust flue gas temperature increases. Soot blowing frequency depends upon the type of fuel used in the boiler. During any abnormality in the boiler, audible and visual alarms are initiated at the control panel. Proper action is required to bring back the system to the normal operation. A log book is supposed to be maintained to note down the important parameters. This log book is helpful to monitor the system. In modern control system, most of the DCS and PLC are having trending facility of the parameters for effective monitoring program. In addition to that, manual logging at an interval of 1 to 2 hours may be helpful. Rate of fuel feeding, steam generation (flow), final superheater steam temperature, final steam pressure, air supply, air temperature, draft at various zones, flue gas temperature at various zones, feedwater inlet temperature, drum level, current taken by various drives, ash hopper level, coal feeder speed, grate speed, bed temperature, pressure drop across fuel bed, etc. are the main parameters that may be logged. Other parameters may be added as per the requirement.

13.7 ABNORMAL OPERATING CONDITIONS AND EMERGENCY SITUATIONS Apart from the normal situation, it is required to handle the boiler during abnormal situation and emergency. Mostly, boilers supply steam to the turbo generator set for power generation. Abnormality in steam generation may trip the set causing huge loss. Also, an emergency situation may lead to a severe accident to man and machine. Some abnormal conditions and emergencies are listed below: Combustion System

• • • • • • •

Loss of igniter Loss of burner Loss of pulveriser/feeder Loss of primary air Loss of coal feeder Loss of fuel Master fuel trip

Combustion Air and Flue Gas System

• Loss of ID/FD fan • Loss of air heater

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• Failure of dampers • Blockage in air/flue gas duct

Feedwater System

• • • • •

Loss of feed pump Problem in feedwater heater Low deaerator temperature Malfunctioning of feed control valve Low suction pressure of feed pump

Boiler General

• • • • • • • • •

Economiser, water wall, superheater tube leakage Safety valve leaking Low superheater temperature High superheater temperature Low steam pressure High steam pressure Low/high water level Loss of ash handling system Problem in soot blowing system

Some emergency situations are discussed here along with the action to be taken to familiarise a boiler operation engineer with these situations.

13.7.1  Low Water Level It is known that the amount of feedwater required in the boiler is equal to the amount of water evaporated and drawn from the boiler plus the blow down and losses in the system. If due to any reason, sufficient amount of water could not be pumped into the boiler, then the water level of the boiler comes down. Following problems may lead to low water level in the boiler:

• • • • • •

Failure of boiler feed pump Leakage in feed pipe Malfunctioning of drum level controller Boiler tube failure Neglect of operator (human error) Heavy load change

When there is no water inside the tube and it is exposed to hot flue gas, then the tube is severely overheated. This situation is called starvation. Starvation is highly dangerous. Most of the boilers have provision to trip automatically due to low water level. If the boiler has no such provision, then the fuel supply must be stopped immediately. The main steam stop valve must be stopped so that further loss of water can be avoided. The boiler should be cooled down rapidly as soon as possible.

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If feedwater supply is resumed, then it is to be bed to the boiler slowly to avoid quenching (i.e., supplying cold feedwater to an overheated boiler tube). Supply of feedwater to a hot boiler suffered from starvation is dangerous. So, proper care is to be taken in this situation. If the boiler tube is damaged due to starvation, it may be required to repair. Emergency shutdown procedure may be followed.

13.7.2  High Water Level Boiler drum level may become high for different reasons. Some of the reasons are given below:

• • • •

Malfunctioning of feed control valve Heavy increase in the boiler load Human error Foaming of boiler water

High water level may lead to priming. Due to priming, carryover of feedwater salts may take place. These salts may be deposited at the superheater tube or at the turbine blade. Priming is associated with sudden drop in steam outlet temperature. Following steps may be taken to normalise this situation:



• Control feedwater flow manually. • To bring down the water level, immediately open the blow down valve. It is to be kept in mind that when the boiler is at maximum load, avoid to open the water wall blowdown. This affects natural circulation. If mud drum is there, its blowdown valve may be opened in this situation. • Reduce the steaming rate. • Try to increase the drum pressure. • Normally, feed control valves are air failed to open type. So, failure in instrument air may open the valve fully. In this case, restore the instrument air supply.

13.7.3  Master Fuel Trip There are different interlocks for master fuel trip of a boiler. Some of them are high/low drum level, ID/FD fan trip, furnace pressure high/low, loss of auxiliary power to burner management system, high steam temperature, etc. In this situation, fuel supply to the boiler stops. Following steps may be followed in this situation:

• • • •

Stop the main steam stop valve. Purge the furnace, as discussed earlier. Normalise the fuel trip condition. To start boiler immediately, follow the hot start-up procedure.

13.7.4  High Steam Temperature Temperature of superheated steam is controlled automatically by various methods, as discussed earlier. Due to gradual increase in the furnace exit flue gas temperature, temperature of the

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steam raises gradually over a period of time. This is due to soot deposition in the furnace wall. In this case, soot blowing may solve the problem. Sometimes, the steam temperature rises suddenly. Sudden temperature rise may be due to the following reasons:

• • • •

High excess air Sudden increase in fuel burning rate Failure of autotemperature control Sudden reduction in load

In most of the boilers, temperature control is done automatically with the help of a suitable control system. Sudden variation in temperature may create problem in the turbine. Following steps may be followed to bring back the temperature to the normal:

• Put temperature control in manual mode and try to maintain manually. • Decrease the temperature of air. • Increase consumption of steam, if required open start-up vent to allow more steam to flow in the superheater. • Increase the temperature of feedwater. • Reduce the excess air.

13.7.5  Furnace Explosion This is the most dangerous emergency situation in a boiler. This may lead to severe damage to man and machine. So, proper care is to be taken to avoid furnace explosion. Furnace explosion mainly happens due to the accumulation of unburnt fuel in the furnace or hot gas path. Some of the reasons for furnace explosion are mentioned below:

• • • • •

Leakage in fuel oil inlet valve Introduction of fuel without sufficient ignition energy Not shutting of the fuel inlet valve when fire is extinguished Mixture of unburnt fuel with air in an explosive proportion Excessive furnace pressure due to failure of ID fan

When unburnt fuel gets sufficient air, it cuts fire instantly in a confined space causing an explosion. To avoid this situation, following steps are to be followed:

• Before starting of a boiler, purge the furnace to prevent accumulation of explosive mixture. For purging, minimum 30% air flow is to be maintained for minimum 5–10 minutes. • Ensure the idle burner fuel shut off valve is closed. • Watch the fire regularly. Shut off the fuel if proper combustion is not maintained. • Regularly check that the furnace safety system and the trip interlocks are functioning properly. • Never introduce fuel without the required ignition energy. • Analyse flue gas regularly. Flue gas should not contain carbon monoxide. • Maintain proper furnace draft. Boiler should have an autotrip interlock in case of high furnace pressure.

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13.7.6  Boiler Tube Failure Water tube boiler contains a lot of tubes. High pressure water and steam flow inside these tubes. During tube leakage, this water and steam mix with the flue gas and escape to the atmosphere. So, to maintain the water level, more make-up is required. If the tube leakage is not attended earlier, it may damage the adjacent tube by steam impingement and erosion. So, it is better to shutdown the boiler when leakage is found as early as possible. There are so many reasons for tube failure. Some of them are mentioned below:

• • • • • • • • •

Flue gas side erosion of tube due to soot blowing and high flue gas velocity Waterside corrosion of tube Impingement of flame on tube surface Welding defect Flue gas side corrosion of tube Uneven temperature Waterside and gas side scaling of tube Design defect Frequent start-up and shutdown of boiler

In some cases, due to improper design, tube failure is noticed at a particular zone. To avoid this, proper care is required during design stage. Some precautionary steps as mentioned below may be taken to avoid tube failure:

• Measure tube thickness regularly during boiler shutdown. Replace the tube if thickness reduces by 30% of the new tube thickness. • Use dry steam with required pressure for soot blowing, as advised by the boiler manufacturer. • Maintain draft in all zones of the boiler within limit. • Improve combustion condition. • Avoid frequent start and stop of the boiler. • Maintain feedwater and boiler water quality. • In area where erosion is more, tube shields may be used. • Adjust flame to avoid flame impingement. • Avoid sudden change in the tube metal temperature to avoid thermal shock. • During shutdown, check whether the tube is free for expansion. If the tube is not free, then it will bend like a bow when heated. This is called as bowing of tube.

When tube leakage is small and water level can be maintained, boiler shutdown is to be taken as early as possible for repair. Shutdown to cold method may be followed in this case. When leakage is severe and water level cannot be maintained, then in that condition, fuel supply is to be cut immediately. Water supply to the boiler is to be stopped and the boiler is to be cooled by maintaining sufficient air flow. Tube leakage in water wall and superheater can be detected by monitoring regularly the feedwater make-up. Economiser tube leakage produces sound. So, this can be detected by sound and increased consumption of make-up water.

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13.8  PRESERVATION OF BOILER When a boiler is to be kept out of service for a longer period, some special care is required to be taken to avoid corrosion of its pressure parts. The boiler tube corrodes rapidly in the presence of oxygen and moisture. So, to avoid corrosion, it is required to eliminate either oxygen or moisture from the boiler tube. There are two methods of preservation of a boiler. In first method, care is taken to keep the boiler tube moisture-free. This method is called dry preservation. In this method, dry air is circulated continuously through the empty boiler tube. In second method, care is taken to eliminate oxygen from the boiler tube. This method of preservation is called wet preservation. Total boiler pressure parts (economiser, steam drum, water wall and superheater) are filled with feedwater having high concentration of Hydrazine (200 ppm). Such high concentration of hydrazine ensures there is no dissolved oxygen available in the feedwater. The boiler is kept under pressure so that atmospheric air cannot enter into the boiler pressure parts. Wet preservation is preferred over dry preservation. This method is easier and most effective. Nowadays, due to complex design and more number of bends in a boiler tube, it is not always possible to keep the circuit dry in dry preservation method.

13.9  HYDROSTATIC (HYDRAULIC) TEST Hydrostatic test (commonly called as hydro test or hydraulic test) is conducted to ensure the pressure parts can withstand working pressure continuously. Also, by hydrostatic test, any leakage in pressure part can be detected. This test is conducted at least once in a year during annual inspection or after each repairing job in the boiler pressure parts. For hydro testing, Feedwater is filled up in entire pressure parts of the boiler and pressure is raised with the help of a high pressure pump. Following steps are followed for hydrostatic test:



• Remove safety valves and make the flanges blind. Otherwise, the safety valves are to be gagged. • Close main steam stop valve and all drain line valves. • Fill up the drum upto the normal working level as per the boiler fill-up method discussed earlier. • Allow more water into the drum through the fill-up pump or boiler feed pump. • Close the drum vent when water comes out from this vent. Now, the water enters into the superheater. Ensure that the superheater vent is open. • Stop the superheater vent when water comes out. • Regulate the flow rate to the boiler. Pressure starts increasing gradually once the superheater is filled up. • Some boiler manufacturers recommend to fill the boiler through drain header for hydro testing. In this case, water overflows to steam drum once the superheater, evaporator, economiser are filled up. Continue this fill-up till the water comes out from the drum vent. Then, stop the vent. • Feedwater to be used for hydro test should be at atmospheric temperature.

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• Once the boiler pressure parts are filled up completely, increase the pressure gradually through hydro test pump or boiler feed pump with throttled discharge valve. • The rate of raising the pressure in the boiler should be maximum 10 kg/cm2 per minute. • Check the pressure tightness of the pressure parts. If there is any leakage, water will start leaking there. • Hold pressure raise intermediately and notice if there is any pressure drop. If there is any leakage, pressure will start dropping once the pump is stopped. • If no pressure drop is noticed, raise the pressure gradually till hydrostatic test pressure. • At hydrostatic test pressure, stop the hydro test pump/boiler feed pump or close the filling valve. Maintain pressure for 10 minutes and watch for any abnormal drop of pressure or any leakage. • Hydro test is successful if the pressure parts withstand the test pressure for 10 minutes without any leakage. • After successful hydro test, reduce the pressure at the rate of 10 kg/cm2 per minute. Pressure may be reduced by opening the sampling line valve or blowdown valve one by one to flush the line. • When pressure drops to 2 kg/cm2, open the drum vent and allow pressure to drop to zero. • Open the blowdown valve and maintain the normal working water level. • Open the superheater drain to completely drain out water. • Fit the back safety valve or open the gagging.

Most of the time confusion arises during hydraulic test of the boiler for deciding the test pressure. There are different types of pressure ratings of a boiler. A discussion is made here to make the reader understand. But the decision of the Inspecting authority is final to decide at what pressure hydraulic test will be carried out. Operating Pressure or Working Pressure This is the actual pressure at which a boiler is operated. Design Pressure Design pressure is used for calculating the minimum thickness requirement for the boiler pressure parts. Design pressure is taken as maximum allowable working pressure in the steam drum of the boiler in case of drum type boiler and maximum allowable working pressure at the final superheater steam outlet in case of a once through boiler. In practice, design pressure is higher than the maximum permissible working pressure. Maximum Allowable Working Pressure (MAWP) or Maximum Permissible Working Pressure (MPWP) This is the maximum allowable working pressure that is permitted by the inspecting authority for the boiler. Highest pressure setting of the drum safety valve is done at this pressure. Hydraulic Test Pressure Hydraulic test pressure depends upon purpose of hydrotest. Hydraulic test is conducted normally at 1.5 times of the maximum allowable working pressure for a new boiler and 1.25 of the

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maximum allowable working pressure for a repaired (renewal of pressure parts) boiler. Normal hydraulic test for renewal of certificate (without renewal of any pressure parts)  is carried out at 1.25 to 1.5 times of the working pressure. 

13.10  SOOT BLOWING During the normal operation of a boiler, soot is deposited on the boiler tube. Due to this soot deposition, heat transfer rate decreases. So, the flue gas temperature increases. Exit flue gas temperature can indicate soot deposit condition on the tube. When soot deposition is more in the furnace wall tube, heat transfer in the furnace decreases. So, the furnace outlet flue gas temperature increases and hence, the superheated steam temperature also increases. It is required to clean the boiler tube regularly for effective heat transfer. This is an activity done during the normal operating condition. This is called soot blowing. Frequency of soot blowing depends upon the type of fuel used. Coal is used in powdered form in the pulverised coal-fired boiler. So, a lot of soot is deposited in this type of boiler. Frequent soot blowing at an interval of 8 to 10 hours is required in this case. In case of oil and gas-fired boilers, ash percentage in fuel is very less, so the soot deposition is nearly negligible. Soot blowing is required once in 10 to 12 days. Normally, dry steam at 10 kg/cm2 to 12 kg/cm2 is used as blowing medium. Soot blowers are placed in the flue gas path to clean some portions of the tube. When blowing is started, this high pressure steam comes out at high velocity from the nozzle of the blower. This high velocity steam cleans the soot deposited on the tube. The blower rotates by 360° (some time 180° also) by means of an electric motor. So, the high velocity steam can clean the tube surface around it. Dislodged soot is taken out by the flue gas. There are two types of soot blowers. These are rotary soot blower (RSB) and long retractable soot blower (LRSB) (Figure 13.3). Rotary soot blower rotates in a fixed position. In long retractable soot blower, there is a retractable lancer which is retracted outside when the blower is not in service. During the operation of this blower, the lancer enters the flue gas path and also rotates like a rotary blower. The movement of lancer and the rotation of blower are done through a motor.

Figure 13.3  Soot blowers (a) Rotary soot blower and (b) Long refractable soot blower.

A retractable blower is installed at high temperature zone, whereas a rotary blower or fixed blower is installed at lower temperature zone like air heater and exit end of the economiser.

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All the soot blowers are connected to a common soot blowing steam line. Soot blowing is started one by one in the direction of flue gas flow. Normally, blowing is done sequentially once it is started. Otherwise, this can be done manually one after the other in the flue gas direction. Steam used should be dry. It is supplied to that particular blower which is in service and cut off automatically by a poppet valve when the blowing of that blower is finished. The movement of blower is controlled through limit switches. Soot blowing is preferably done at a load above 50% of the maximum continuous rating (MCR). Following important steps are followed during soot blowing:

• Open the isolation valve of soot blowing steam line. • Open the drain valves of this line to drain out condensate, if any. Allow steam to flow for some time through these valves to increase the temperature of that line. • Put the control valve of the line in automode to get 10 kg/cm2 to 12 kg/cm2 pressure. • Check all retractable blowers are in withdrawn position. • Increase the draft a little higher. • Start the sequence. Blowing is started one by one. In case of manual system, start blowing one by one in the direction of flue gas flow. • After the completion of blowing sequence, bring back the draft to the normal and close the steam isolation valve.

13.11  INSPECTION OF BOILER A boiler generates high pressure steam at high temperature. Any abnormality in the boiler may lead to a severe accident causing heavy loss to man and machine. Inspection of boiler is required at regular interval for safety. During shutdown, it is required to inspect the water wall, superheater, economiser and the air heater. Tubes are cleaned and checked properly to find out corrosion, erosion, swelling, warping, blistering, burning and cracking. Also, internal inspection of the boiler (i.e., waterside of pressure part) is done to find out corrosion and pitting. For this, hand hole cap of water header may be opened. Steam drum manhole is opened after draining the water and isolating the other connected pipeline valves (feedwater, dosing, blowdown, drain and sampling line). Drum internals are cleaned properly and inspected for corrosion and pitting. Boiler is properly cleaned before inspection. Scaffolding is arranged to clean the entire furnace and the bank tube. Tube may be cleaned with the help of water, jute, sack, brush or even through high pressure hydro jet. All these activities are carried out during annual inspection of the boiler. A detailed discussion about annual inspection is made in Chapter 21.

13.12  EFFICIENCY CALCULATION For the generation of steam, fuel is used in the boiler. Fuel is costly. So, the efficiency of a boiler plays a vital role in lowering the fuel cost. Boiler is operated continuously. A non-efficient boiler can consume huge quantity of fuel. So, it is the duty of a boiler operation engineer to have an idea about the efficiency of a boiler.

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As per ASME performance test code PTC 4.1, following are the two methods to measure the efficiency of a boiler: • Input-output method or direct method • Heat loss method or indirect method Due to simplicity, direct method is preferred by the boiler engineers.

13.12.1  Input-Output Method or Direct Method Direct or input-output method of boiler efficiency calculation is very simple for the calculation of boiler efficiency. It is preferred by most of the boiler engineers. Following input data are required for the calculation of efficiency in this case: • Steam pressure (kg/cm2) • Steam temperature (°C) • Steam flow (Qs) • Feed water temperature (°C) • Calorific value of fuel (kcal/kg) • Quantity of fuel used (Qf) Output Efficiency  Input Output from the boiler is the net heat added to the steam in the boiler which is given by

Steam flow  (Heat available in steam – Heat on the supplied feedwater)

Input to the boiler is the heat energy supplied to the boiler by fuel which is given by Fuel flow  Calorific value of fuel

So,

Efficiency 

Steam flow (Heat available in steam  Heat on feedwater) Fuel flow  Calorific value of fuel

The calorific value of fuel is expressed as gross calorific value (GCV) or higher heating value (HHV) and lower heating value (LHV) or net calorific value (NCV). LHV or NCV is always less than GCV or HHV. So, the efficiency calculated on LHV or NCV basis is higher than the efficiency calculated on GCV or HHV basis, provided the other data remain unchanged. EXAMPLE 13.1  Some observations made from a coal-fired boiler are shown in Table 13.3: Calculate the efficiency of the boiler by the direct method. Table 13.3  Observations From a Coal-fired Boiler

Parameter

Steam Pressure Steam Temperature Steam Flow Feedwater Temperature Calorific Value of Coal Used (GCV) Calorific Value of Coal Used (LCV) Coal Consumption

Value 50 kg/cm2 (abs) 480 °C 100 t/hr 40 °C 3500 kcal/kg 3300 kcal/kg 23 t/hr

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Solution  From Table 13.3, the enthalpy of steam at 50 kg/cm2 (abs) and 480 °C is found 809 kcal/kg. As the feedwater is supplied to the boiler at 140 °C, so it contains 140 kcal/kg of heat. As per formula, Efficiency (GCV basis) = 100 

(809  140)  83% (23  3500)

Efficiency (LCV basis) = 100 

(809  140)  88% (23  3200)

13.12.2  Heat Loss Method or Indirect Method The total heat supplied to the boiler by fuel is not utilised for the generation of steam. Various losses take place in the boiler. In heat loss method or indirect method of boiler efficiency calculation, various losses are calculated and the efficiency is calculated by subtracting these heat loss fractions from 100. Principal heat losses that take place in a boiler are listed below:

• • • • • •

Heat Heat Heat Heat Loss Heat

loss in dry flue gas loss due to evaporation of water formed due to hydrogen present in the fuel loss due to evaporation of moisture present in the fuel loss due to moisture present in the combustion air due to unburnt fuel in ash loss due to radiation and other unaccounted losses

Also, some heat is added to the boiler other than the fuel. These are called credits. Some of the credits are as follows:

• • • •

Heat in feedwater Heat in combustion air Heat from auxiliary equipment Sensible heat on fuel

For the calculation of efficiency by indirect method, following data are required:

• • • • • • •

Ultimate analysis of fuel (H2, O2, C, S, moisture %, ash%) Percentage of O2, CO, CO2 in flue gas Flue gas temperature at boiler exit (Tf °C) Ambient air temperature (Ta °C) and humidity GCV of fuel (kcal/kg) Percentage of unburnt fuel in ash GCV of ash (kcal/kg)

Following steps are followed for the calculation of efficiency:

• Calculate the theoretical air requirement for the combustion of fuel. As discussed earlier, it is given by 4.35[(8/3C + 8H2 + S) – O2]/100 kg/kg of fuel. • Calculate the percentage of excess air and the actual mass of the air supplied per kilogramme of the fuel. Excess air (EA) = O2  100/(21 – O2) Actual mass of air supplied per kilogramme of fuel = (1 + Excess air/100)  Theoretical air

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• Calculate all heat losses as mentioned below: – Percentage heat loss due to dry flue gas:  This loss can be calculated as

m  Cp(Tf – Ta)  100/GCV of fuel

where, m is the mass of dry flue gas in kilogrammes per kilogramme of fuel and Cp is the specific heat of flue gas (0.23 kcal/kg). Mass of dry flue gas can be calculated as

Mass of actual air supplied + 1(Mass of fuel supplied) – (M + 9H2)

here, M is the percentage of moisture in 1 kg of fuel. – Heat loss due to evaporation of water formed due to hydrogen present in the fuel:  This loss can be calculated as

9  H2[584 + Cp(Tf – Ta)]/GCV of fuel

where, H2 is the percentage of hydrogen in 1 kg of fuel and Cp is the specific heat of superheated steam (0.45 kcal/kg). – Heat loss due to evaporation of moisture present in the fuel:  This loss can be calculated as M[584 + Cp(Tf – Ta)]/GCV of fuel where, M is the percentage of moisture in 1 kg of fuel and Cp is the specific heat of superheated steam (0.45 kcal/kg). – Heat loss due to moisture present in the combustion air:  This loss can be calculated as Actual mass of air supplied  Humidity ratio of air  Cp(Tf – Ta)  100/GCV of fuel – Loss due to unburnt fuel in ash:  This loss can be calculated as

Ash collected per kilogramme of fuel  GCV of Ash  100/GCV of fuel

– Heat loss due to radiation and other unaccounted losses:  This loss can be assumed according to the surface condition and size of the boiler. For a smaller boiler, this loss may be assumed as 1% to 2% and for a larger boiler, this can be assumed between 0.2% to 1%.

• Calculate the boiler efficiency.



Boiler efficiency = 100 – Sum of all above losses

EXAMPLE 13.2  Find the efficiency of a coal-fired boiler by heat loss or indirect method. Some observations from the boiler are mentioned in Table 13.4. Table 13.4  Observations from a Boiler Parameter Ultimate Analysis of Coal

Value H2 O2 C S Moisture Ash

2% 5% 38% 1% 5% 47%

Operation of Boiler 



Flue Gas Analysis (O2) Flue Gas Temperature at Boiler Exit Ambient Air Temperature Humidity Ratio Relative Humidity GCV of Fuel Ash Generation GCV of Ash Specific Heat of Flue Gas Superheated steam

259

3% 140 °C 40 °C 0.04 of fuel kg/kg 80% 3400 kcal/kg 0.47 kg/kg of fuel 200 kcal/kg 0.23 kcal/kg 0.45 kcal/kg

Solution  Theoretical air requirement for combustion of per kilogramme of coal





 8     3 C  8H 2  S  O 2    kg/kg of fuel = 4.35 100  8     3  38  8  2  1  5  = 4.35  100 = 4.93 kg/kg of coal Percentage of excess air = O 2 

100 100 3  16.67% (21  O 2 ) 21  3

Actual mass of air supplied per kilogramme of fuel = (1 + Excess air %/100)  theoretical air = (1 + 0.1667 )  4.93 = 5.75 kg/kg of coal Now, all heat losses are calculated. Percentage heat loss due to dry flue gas can be calculated as Mass of dry flue gas = Mass of actual air supplied + 1 – (M + 9H2) = 5.75 + 1 – (0.05 + 9  0.02) = 6.52 Dry flue gas loss = m  Cp(Tf – Ta)  100/GCV of fuel = 6.52  0.23 (140 – 40)  100/3400 = 4.41% Heat loss due to evaporation of water formed due to hydrogen present in the fuel

= 9  H2[584 + Cp(Tf – Ta)}/GCV of fuel = 9  2[584 + 0.45(140 – 40)]/3400 = 3.33%

Heat loss due to evaporation of moisture present in fuel

= M[584 + Cp(Tf – Ta)]/GCV of fuel = 5[584 + 0.45 (140 - 40)]/3400 = 0.925%

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Heat loss due to moisture present in combustion air = Actual mass of air supplied  Humidity ratio of air  Cp(Tf – Ta)  100/GCV of fuel = 5.75  0.04[0.45(140 – 40)]  100/3400 = 0.3% Loss due to unburnt fuel in ash = Ash collected per kilogramme of fuel  GCV of ash  100/GCV of fuel = 0.47  200  100/3400 = 2.76%



Heat loss due to radiation and other unaccounted losses are assumed depending upon the type of boiler. In this case, let these be 1%. Boiler efficiency = 100 – Sum of all above losses = 100 – (4.41 + 3.33 + 0.925 + 0.3 + 2.76 + 1) = 100 – 12.88 = 87%

EXERCISES 1. 2. 3. 4. 5. 6. 7. 8. 9. 10.

11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 21.

Why is air vented out during boiler filling and how is it done? What is the water holding capacity of a boiler? What are the main steps to be followed during initial fill-up of a boiler? What is swelling of boiler water and when does it take place? What is the difference between cold start-up and hot start-up? When is drum vent opened and when is it closed? Why is the start-up vent kept open till the steam is drawn from the boiler? What is furnace purging? What is the difference between shutdown to cold and shutdown to hot? How is load controlled in a PC boiler? On what basis is the addition and stoppage of pulveriser decided? How does the bed temperature increase during starting of an AFBC boiler? How is load controlled in an AFBC boiler? What is bed slumping? What is hot box up condition in a boiler? What are the normal activities carried out during a normal boiler operation? What are the important emergency situations in a boiler? Why is low water level dangerous in a running boiler? What are starvation and quenching? Why is high water level is not recommended? Why is the water wall header blowdown valve not to be operated in a running boiler? Mention the interlocks for master fuel trip of a boiler. What steps are taken to control the superheated steam temperature?



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22. What are the causes of furnace explosion and what steps are to be taken to avoid this situation? 23. Why is it not advisable to operate the boiler having tube leakage? 24. What are the main causes of a boiler tube failure? 25. When should the boiler tubes be replaced? 26. When is the preservation of boiler required? 27. What are the preservation methods of a boiler? 28. What is wet preservation? 29. Why is hydro test of a boiler carried out? 30. What steps are followed for hydro test? 31. What should be the rate of rising of pressure during hydro test? 32. What is the difference between working pressure and maximum allowable working pressure of the boiler? 33. What is hydro test pressure? 34. At what pressure the highest pressure setting of safety valve is to be done? 35. What indicates about soot deposition on tubes? 36. Where are rotary and retractable soot blowers used? 37. Which methods are used for boiler efficiency calculation and which method is simple? 38. What inputs are required to calculate the boiler efficiency by direct method? 39. Why is the efficiency calculated on NCV basis higher than the efficiency calculated on GCV basis? 40. What are the principal losses and heat additions (credits) in a boiler?

Chapter

14

Pipes, Tubes and Fittings

14.1  INTRODUCTION In previous chapters, we have discussed about the boiler and the process of steam generation. In this chapter, details about pipes, tubes and different fittings used in the piping system are discussed. Generated steam from the boiler is brought upto the load through pipeline. Feedwater and steam with high pressure and temperature flow through the pipe. So, special care is required to be taken while selecting a pipe material. It has to withstand high pressure and temperature. Mechanical vibration is produced when steam flows through a pipe. A pipeline has its own weight and weight of the fluid it carries. So, the pipeline is to be supported suitably at suitable locations. Also, a pipeline expands when the high temperature fluid flows through it. Proper care is taken to accommodate this expansion to avoid damage of the line. For isolating flow of the fluid, isolation valves are provided in the pipeline. Different types of isolation valves are used in the pipeline. Like pipe, these isolation valves have to withstand high temperature and pressure. There are different classes of valves according to their pressure rating. Condensation takes place in the steam line. Traps are used to remove this condensate. Steam traps are used in the pipeline for this. A pipeline is to be properly insulated, as high temperature fluid flows through it. Proper insulation minimises the radiation loss. Other pipe fittings and ancillaries like flanges, non-return valves, etc. are used in the pipeline. In a boiler house, mostly the steam and feedwater flow through the pipeline. Like pipe, boiler tube is manufactured from different grades of steel. Temperature of different zone is different in a boiler. So, different grade tubes are used.

14.2  TUBE AND PIPE Steam is formed in a boiler due to gain of heat by the feedwater in boiler tube. Boiler tubes are arranged in parallel path to gain more heat. Steam is generated at high temperature and pressure. This high temperature and pressure steam is brought upto the load point through pipe. It is always confusing to know the difference between the tube and pipe. The difference between tube and pipe is discussed here before discussing further. 262

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14.2.1  Difference between Tube and Pipe Tubes and pipes are used in a boiler. There are no significant differences between them. Both of them have inner diameter (ID) or bore, outer diameter (OD) and wall thickness. But they can be differentiated by the following three dimensions:



• Tube is produced with higher tolerance. Outer diameter (OD) and wall thickness are commonly used to express the size of a tube. When wall thickness of the tube (having same OD) increases, inner diameter (ID) reduces. A 2 in  0.065 in tube means OD of the tube is 2 in and wall thickness is 0.065 in. These two dimensions are preciously measured. Thickness of the tube wall is selected as per the pressure rating. • Pipe is manufactured with lower tolerance. Inner diameter (ID) is the critical dimension of a pipe. ID is expressed normally or approximately. A 2 in pipe means ID of the pipe is approximately 2 in. • Wall thickness of a pipe is designated by various schedules. Exact wall thickness of any one schedule changes with the pipe size. Wall thickness of a 2 in, schedule 40 pipe is 0.154 in. Whereas, for a 3 in, schedule 40 pipe, it is 0.216 in.

But irrespective of the schedule, the outer diameter of a particular size pipe is same. OD of a 2 in, schedule 40 and schedule–80 pipe is 2.375 in in both the cases. The difference between 2 in  0.065 in tube and a 2 in, schedule 5 (wall thickness 0.065 in) is shown in Figure 14.1.

Figure 14.1  (a) Tube and (b) pipe.

A tube is used where heat transfer takes place at the time of fluid flow. But, in case of pipe, only the fluid flows.

14.3  Pipe schedule It was discussed that the wall thickness of a pipe depends upon the schedule of the pipe. A particular size pipe having different schedule numbers has the same outer side diameter. The inner diameter and the wall thickness vary with the schedule number. For the same schedule number, thickness of pipes having different sizes is different. There are different schedule numbers used for pipe to determine the wall thickness. American National Standard Institute (ANSI) sponsored by American Society for Testing Materials (ASTM) and American Society of Mechanical Engineers (ASME) has standardised this schedule as

Pipe OD (in)

0.405 0.54 0.675 0.84 1.05 1.315 1.66 1.9 2.375 2.875 3.5 4 4.5 5 5.563 6.625 7.625 8.625 9.625 10.75 11.75 12.75 14 16 18 20 24 26 28 30

Nominal Pipe Size (in)

0.125 0.25 0.375 0.5 0.75 1 1.25 1.5 2 2.5 3 3.5 4 4.5 5 6 7 8 9 10 11 12 14 16 18 20 24 26 28 30

0.035 0.049 0.049 0.065 0.065 0.065 0.065 0.065 0.065 0.083 0.083 0.083 0.083  – 0.109 0.109  – 0.109  – 0.134  – 0.165  –  –  –  –  –  –  –  –

0.049 0.065 0.065 0.083 0.083 0.109 0.109 0.109 0.109 0.12 0.12 0.12 0.12  – 0.134 0.134  – 0.148  – 0.165   0.18 0.25 0.25 0.25 0.25 0.25 0.312 0.312 0.312

 – –  –  –  –  –  –  –  –  –  –  –  – –   –  –  – 0.25  – 0.25  – 0.25 0.312 0.312 0.312 0.375 0.375 0.5 0.5 0.5

 – –   –  –  –  –  –  –  –  –  –  –  –  –  –  – –  0.277  – 0.307  – 0.33 0.375 0.375 0.437 0.5 0.562   0.625 0.625

Schedule Schedule Schedule Schedule 5 10 20 30 0.068 0.088 0.091 0.109 0.113 0.133 0.14 0.145 0.154 0.203 0.216 0.226 0.237 0.247 0.258 0.28 0.301 0.322 0.342 0.365 0.375 0.375 0.375 0.375 0.375 0.375 0.375 0.375 0.375 0.375

Std 0.068 0.088 0.091 0.109 0.113 0.133 0.14 0.145 0.154 0.203 0.216 0.226 0.237  – 0.258 0.28  – 0.322  – 0.365  – 0.406 0.437 0.5 0.562 0.593 0.687  –  –  –

 –  –  –  – –  –  –  –  –  –  –  – 0.281  –  –  –  – 0.406  – 0.5  – 0.562 0.593 0.656 0.75 0.812 0.968  –  –  –

Schedule Schedule 40 60 0.095 0.119 0.126 0.147 0.154 0.179 0.191 0.2 0.218 0.276 0.3 0.318 0.337 0.355 0.375 0.432 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5   0.5

XS 0.095 0.119 0.126 0.147 0.154 0.179 0.191 0.2 0.218 0.276 0.3 0.318 0.337  – 0.375 0.432  – 0.5  – 0.593  – 0.687 0.75 0.843 0.937 1.031 1.218  –  –  –

 –  –  –  –  –  –  –  –  –  –  –  –  –  –  – –  – 0.593  – 0.718  – 0.843 0.937 1.031 1.156 1.28 1.531  –  – – 

 –  –  –  –  –  –  –  –  –  –  –  – 0.437  – 0.5 0.562  – 0.718   0.843  – 1 1.093 1.218 1.375 1.5 1.812  –  –  –

 –  –  –  –  –  –  –  –  –  –  –  – –  –  –  –  –  0.812  – 1 –  1.125 1.25 1.437 1.562 1.75 2.062  –  – –

 –  –  – 0.187 0.218 0.25 0.25 0.281 0.343 0.375 0.437  – 0.531  – 0.625 0.718  –– 0.906  – 1.125  – 1.312 1.406 1.593 1.781 1.968 2.343  –  –  –

Schedule Schedule Schedule Schedule Schedule 80 100 120 140 160

Pipe Schedule/Wall thickness (in)

Table 14.1  Wall Thickness of Differenct Schedule Pipes

–  –  – 0.294 0.308 0.358 0.382 0.4 0.436 0.552 0.6 0.636 0.674 0.71 0.75 0.864 0.875 0.875  –  –  –  –  –  –  –  –  –  –  –  –

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per ANSI B 36.10 standard. As per this standard, there are 11 standards, i.e., schedule 5, 10, 20, 30, 40, 60, 80, 100, 120, 140 and 160. Wall thickness and hence, the weight of the pipe increase with the increase in schedule number. As per ANSI B 36.19 standard, the schedule for stainless steel pipe is ranged from 5S to 80S. The addition of the letter ‘S’ after schedule number identifies it as stainless pipe. Depending upon the thickness of wall, weight per unit length of pipe varies. There are normally three categories of wall, i.e., standard wall (Std), extra strong wall (XS) and double extra strong wall (XXS) or double extra heavy wall (XXH). The wall thickness for different sizes of pipes for different schedule numbers as per ANSI  B 36.10 standard is given in Table 14.1.

14.4  Nominal Bore (NB) of Pipe Size of a pipe indicates approximate inner diameter of a pipe. As the dimension is approximate, so the diameter is called nominal diameter (ND) or the bore of the pipe is called nominal bore (NB). In metric system, it is expressed in millimetres. Pipe size is also expressed in inches (in) called nominal pipe size (NPS). A 1/8 NPS pipe means ID of the pipe is approximately 1/8 in. The conversion of NB to NPS is given in Table 14.2. Table 14.2  Conversion of NB to NPS Nominal Bore (NB) or Nominal Diameter (ND) (mm) 6 8 10 15 20 25 32 40 50 65 80 100 150 200 250 300

Nominal Pipe Size (NPS) (in)

Nominal Bore (NB) or Nominal Diameter (ND) (mm)

Nominal Pipe Size (NPS) (in)

1/8 1/4 3/8 1/2 3/4 1 1 14 1 12 2 2 12 3 4 6 8 10 12

350 400 450 500 550 600 650 700 750 800 900 1000 1100 1200 1400 1500

14 16 18 20 22 24 26 28 30 32 36 40 42 48 54 60

14.5  Different Standard Specifications for Tube and Pipe Different standards are followed for pipe and tube, throughout the world. Among them, following standards are well known:

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• • • • • • • •

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American Society for Testing Materials (ASTM) American Petroleum Institute (API) British Standard Institute (BSI or BS) Deutsche Industrie Normen (DIN) (German institute of standardisation) Japanese Industrial Standard (JIS) Gosudartsvennye Standarty (GOAST) (State standards of Russian federation) Indian Standard (IS) European Standard (EN)

ASTM standard is mostly used for the boiler tubes and pipes in India. In ASTM standard, SA or only A is prefixed before the standard. For example, standard SA210 or A210. For pipes and tubes of a boiler, there are different ASTM standards. Following standard tubes and pipes are found to be used in India: Tube Standards

• SA178 – Electric-resistance-welded carbon steel and carbon–manganese steel boiler and superheater tube • SA192 – Seamless carbon steel boiler tube for high pressure use • SA209 – Seamless carbon–molybdenum alloy steel boiler and superheater tube • SA210 – Seamless medium carbon steel boiler and superheater tube • SA213 – Seamless ferritic and austenitic alloy steel boiler, superheater and heat exchanger tubes

Mostly SA210, Grade A1 and C (seamless medium carbon steel boiler and superheater tube) and SA213, Grade T11, T22 and T91 (seamless ferritic and austentic alloy steel boiler, superheater and heat exchanger tubes) are used in the boilers. Carbon steel is used in economiser evaporator and other low temperature tubes and alloy steel is used for high temperature superheater tubes. Carbon steel is used maximum upto 420 °C. Pipe Standards

• SA106 – Seamless carbon steel pipe for high temperature service • SA335 – Seamless ferritic and austenitic alloy steel pipe for high temperature service • SA358 – Electric fusion welded austenitic chromium–nickel alloy steel pipe for high temperature service

Mostly SA106, Grade A, B and C (Seamless carbon steel pipe for high temperature service) and SA335, Grade P11, P22 and P91 (Seamless ferritic and austentic alloy steel pipe for high temperature service) are used in a boiler house.

14.6  CARBON STEEL AND ALLOY STEEL 14.6.1  Carbon Steel Depending upon the percentage of carbon in steel, gradation of steel is done as low carbon, medium carbon or high carbon steel. Low carbon steel contains less than 0.3% carbon and



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it is also called as mild steel. Medium carbon steel contains 0.3% to 0.45% of carbon. High carbon steel contains 0.45% to 0.75% of carbon. Carbon steel also contains less than 1.65% manganese, less than 0.6% copper and small amount of silicon, sulphur and phosphorus. As per American Iron and Steel Institute (AISI), steel is considered to be carbon steel when no minimum content is specified or required for chromium, cobalt, columbium (nobium), molybdenum, nickel, titanium, tungsten, vanadium or zirconium or any other element to be added to obtain a desired alloying effect. By changing the percentage of carbon in steel, property of the steel also gets changed. Steel with increased carbon is harder and stronger but less ductile.

14.6.2  Alloy Steel Any steel which contains more than 1.65% manganese or more than 0.6% copper or a guaranteed minimum amount of any other metal is called alloy steel. The elements most frequently used for alloying are chromium, molybdenum, manganese, nickel, vanadium, tungsten, etc. Alloy steel posses higher thermal, mechanical and chemical properties than the normal steel. Due to high temperature in a boiler, these properties are most important. Particularly, the superheater of a boiler is exposed to high temperature. Also, there is a chance of erosion due to high velocity of dust particles. So, alloy steel is mostly used in this case. Merits of some alloying elements are discussed below: Chromium It makes steel wear-resistant, corrosion-resistant and increases its hardness. Chromium forms an inert passive film on the surface of the tube which resists the attack by oxidising reagents. Chromium is used as a carbide stabiliser. Molybdenum Molybdenum forms complex carbides. It increases the strength of steel at higher temperature, makes steel more heat-resistant. Molybdenum minimises the temperature, brittleness and reduces the mass effect. It is normally used in combination with other alloying elements. Manganese Manganese reduces oxides and counteracts the harmful influence of iron sulphide. It is used to reduce carbon contents to get a steel having same tensile strength but improved ductility. Nickel Nickel lowers the eutectoid temperature. It also increases the rate of cooling of steel. Mechanical properties changes with nickel contents. Steel with 0.5% nickel is similar to carbon steel but is stronger on account of the finer pearlite formed and the presence of nickel in solution of ferrite. Vanadium Vanadium acts as a scavenger for oxides. In the presence of other elements, it forms carbides and has a beneficial effect on the mechanical properties of heat treated steel.

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Tungsten Tungsten refines the grain size and produces less tendency to decarburisation during working. Like molybdenum, it makes the steel heat-resistant. Silicon Silicon dissolves in ferrite of which it is an effective hardener. It contributes oxidation resistance in the heat-resisting steels. This is a general purpose deoxidiser. Titanium and Nobium These elements prevent intergranular corrosion of steel.

14.7  FERRITIC AND AUSTENITIC STEEL We have discussed that different elements are added to steel for alloying purpose to get better thermal, chemical and mechanical properties. Depending upon the alloying element, microstructure of the steel changes. Steel is normally classified by its microstructure. It is identified as ferritic, austenitic or duplex (austenitic and ferritic). Iron, carbon, chromium and nickel are the primary elements that affect the microstructure. Other alloying elements also control the microstructure. Austenitic steel exhibits a single phase, face-centered cubic (FCC) structure. Ferritic steel has a body-centred crystal (BCC) structure, known as ferrite at all the temperatures below its melting point. Duplex (austenitic and ferritic) steel usually comprises of approximately equal proportions of the body-centred cubic (BCC) and face-centred cubic (FCC) structures in its microstructure. Alloying elements promote the formation of certain phase or stabilise it. When alloying element promotes or stabilises the austenitic phase, it is called austenitic forming element. Nickel and manganese mainly belong to this group. They stabilise austenitic phase even at the room temperature. Other alloying elements may be added to austenitic steel to get the other special properties like corrosion resistance, oxidation resistance, strength at higher temperature, etc. Like this, alloying elements which promote or stabilises ferritic phase are called ferrite forming elements. Most important elements of this group are chromium (Cr), silicon (Si) and molybdenum (Mo). It may be concluded that in austenitic steel, nickel is used for alloying along with the other elements. In ferritic steel, alloying elements other than nickel are used. In case of austenitic and ferritic steel, all the alloying elements including nickel are used.

14.8 CHEMICAL COMPOSITION AND MECHANICAL PROPERTY OF DIFFERENT STANDARD PIPES AND TUBES It has been discussed that carbon steel and alloy steel tubes and pipes are used in the boilers. Now, we will discuss the chemical composition and some mechanical properties of some of the widely used tubes and pipes.

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Different standard pipes and tubes are used in the boiler. The chemical composition and some mechanical properties of some of these tubes and pipes are shown in Table 14.3 and Table 14.4 respectively.

14.9  FLOW THROUGH A PIPE In a boiler house, steam and feedwater flow through the pipe. So, some basic knowledge regarding the flow through a pipe is required to be understood by a boiler engineer. The main purpose of the piping system is to supply the fluid at correct pressure to the point of use. Two types of fluid can flow through a pipe. First is compressible and second is incompressible fluid. When fluid volume is directly related to pressure and temperature of the fluid, it is called compressible fluid (such as steam). Whereas, when the volume of fluid remains relatively constant with the change in pressure and temperature, the fluid is known as incompressible fluid (such as water). Flow through a pipe is given by Flow (m3) = Cross sectional area of a pipe (m2)  Flow velocity (m/s) Velocities of some fluid normally adopted in the power plants are given below:

• • • •

Feedwater suction Feedwater discharge Saturated steam Superheated steam

0.6 to 1 m/s 1 to 4 m/s 20 to 40 m/s 25 to 80 m/s

When any fluid flows through a pipe, some mechanical energy is lost due to friction at the wall of pipe. This pressure loss of the fluid depends upon the following factors:

• • • • • •

Length of pipe L (m) Diameter of pipe D (m) Mean velocity of fluid flow U (m/s) Dynamic viscosity of the fluid m (kg/m s) Fluid density r (kg/m3) Roughness factor of the pipe Ks

Pressure or head loss due to friction in a straight pipe is given by Darcy–Weisbach equation. As per this equation, 4 fLU 2 hf = 2 gD where hf = head loss due to friction in metres f = friction factor (dimensionless) L = length of pipe in metres U = flow velocity in metre per second g = gravitational constant (9.81 m/s2) D = diameter of the pipe in metres The friction factor of a pipe depends upon the Reynolds number and roughness of the pipe’s inner surface. Friction factor can also be found from Mody chart.

0.030 0.030 0.045

0.15 0.50–1.00 0.30-0.60 maximum 0.15 0.25–1.00 0.30-0.60 maximum 0.50–1.00 0.30-0.60 0.15 maximum 0.50 0.30-0.61 0.15 maximum maximum 0.15–0.25 0.15–0.35 0.30-0.61 0.15 0.50 0.30-0.60 maximum maximum 0.15 0.50 0.30-0.60 maximum maximum 0.08–0.12 0.20–0.50 0.30-0.60

T7

T9

T11

T12

T17

T21

T22

T91

0.020

0.030

0.030

0.045

0.030

0.030

0.15 0.50 0.30-0.60 maximum maximum

0.045

0.10-0.20 0.10–0.30 0.30-0.61

T5

0.048

0.048

0.010

0.033

0.030

0.045

0.045

0.030

0.030

0.030

0.030

0.045

0.058

0.058

6.00–8.00

8.00–10.00 0.90–1.10 1.00–1.50 0.80–1.25 0.80–1.25 2.65–3.35 1.90–2.65

 –  –  –  –  –  –  –

8.00–9.50

4.00–6.00

 –

0.4

0.50–0.81

 –

 –

V 0.15 maximum

 –

 –

 –

 –

 –

 –

 –

 –

Others

0.85–1.05 N 0.030–0.070, Al 0.04 maximum Ni-Cu 1.00 maximum

0.87–1.13 V 0.18–0.25, Cb 0.06–0.1

0.80–1.06

 –

0.44–0.65

0.44–0.65

0.44–0.65

0.44–0.65

0.44–0.65

 –

 –

 –

 –

Mo

 –

Cr

 –

P S Ni (Maximum) (Maximum) (Maximum)

T2

0.35 0.10 0.29–1.06 maximum maximum

C

SA213 (Alloy Steel)

0.27 0.10 0.93 maximum maximum maximum

Mn

A1

Si

SA210 (Carbon Steel)

C

Grade

Standard

Table 14.3  Material Composition for Different Specification Tube

580

415

415

415

415

415

415

415

415

415

485

415

Tensile Strength (Minimum) MPa

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0.025 0.025

0.15 0.50 0.30–0.60 maximum maximum 0.05–0.15 0.25–1.00 0.30–0.60 0.05–0.15 0.50–1.00 0.30–0.60 0.05–0.15 0.50 0.30–0.61 maximum 0.05–0.15 1.15–1.65 0.30–0.60 0.05–0.15 0.50 0.30–0.60 maximum 0.30–0.60 0.05–0.15 0.50 maximum 0.08–0.12 0.20–0.50 0.30–0.60

P5

P9

P11

P12

P15

P21

P22

P91

0.020

0.025

0.025

0.025

0.025

0.025

0.025

0.10–0.20 0.10–0.30 0.30–0.61

P2

0.025

0.025

0.10–0.20 0.10–0.50 0.30–0.80

0.35 0.10 0.29–1.06 maximum minimum

C

0.025

0.025

0.010

0.025

0.025

0.025

0.025

0.025

0.025

0.025

0.025

0.025

0.025

0.025

0.025

4.00–6.00

8.00–10.00 0.90–1.00 1.00–1.50 0.80–1.25  – 2.65–3.35 1.90–3.35

8.00–9.50

 –  –  –  –  –  –

 0.4

 –

 –

 –

 –

 –

 –

 –

 –

 –

 –

 –

Others

0.85–1.05 Cb 0.06–0.10, V 0.18–0.25

0.80–1.06 N 0.30–0.070, Al 0.04 maximum

0.80–1.06

0.44–0.65

0.44–0.65

0.44–0.65

0.44–0.65

0.44–0.65

0.50–0.81

 –

0.44–0.65

 –

 –

 –

– 

 –

 

 –

 –

 –

Mo

– 

 –

Cr

 –

P S Ni (Maximum) (Maximum) (Maximum)

P1

0.30 0.10 0.29–1.06 maximum minimum

B

SA335 (Alloy Steel)

0.25 0.10 0.27–0.98 maximum minimum

Mn

A

Si

SA106 (Carbon Steel)

C

Grade

Standard

Table 14.4  Material Composition for Different specification Pipes

585

415

415

415

415

415

415

415

380

380

485

415

330

Tensile strength (Minimum) (MPa)

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Reynolds number is a dimensionless parameter which serves to determine the flow regimes of fluid in the pipe. There are different types of flow regimes. These are plug flow, laminar flow and turbulent flow. Also, reynolds number is a factor of pipe diameter, velocity of fluid, fluid density and fluid viscosity. It is given by rUD Re = m

when Re is below 2000, the flow is called laminar flow. The flow is calm and regular in this case. When Re is more than 4000, the flow is called turbulent flow. The flow in this case is in the form of swirl and movement. Head loss in pipe calculated by the above method is for straight pipeline. Other than the friction loss in the pipe, pressure also drops due to pipeline bends, valves, etc. These losses are converted into equal pipe length. The equal pipe length is then added to the total pipe length for calculation of loss. Equivalent loss for the different pipe fittings is shown in the next section. To keep the total loss within limit, pipe size (diameter) is selected. Demerits of oversize pipes are discussed below:

• These are more expensive due to bigger size of valves, fittings, etc. • Installation cost is higher for support work and insulation. • In steam pipe, more condensate is formed due to greater heat loss. More traps are required for the removal of this condensate. Demerits of undersize pipes are discussed below:



• Pressure drop is more, so less pressure is available at the load end. • There is a risk of starvation due to excessive drop. • There is also a greater risk of erosion, water hammer and noise due to high velocity.

14.10  PRESSURE LOSS DUE TO PIPE BENDS AND VALVES Equivalent length (in metres) for additional pressure drop due to valves and bends are shown in Table 14.5. For calculating the pressure drop in a pipeline, Table 14.5 is very helpful. Table 14.5  Equivalent Length for Additional Pressure Drop due to Valves and Bends Pipe Dia (NB)

Gate Valve

Globe Valve

Tee

90° Bend

45° Bend

10 15 25 40 65 80 100 125 150

0.099 0.122 0.204 0.314 0.515 0.605 0.788 0.975 1.167

5.33 6.44 9.81 14.65 24.03 28.23 36.77 45.48 54.43

1.116 1.369 2.18 2.93 4.806 5.646 7.354 9.097 10.885

0.434 0.483 0.763 1.13 1.716 2.016 2.626 3.249 3.888

0.23 0.277 0.436 0.628 1.03 1.2 1.576 1.95 2.333

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EXAMPLE 14.1  A 50 m 40 NB pipeline has one globe valve, one gate valve and one tee. Calculate the equivalent length of the pipeline. Solution  With the help of Table 14.5, we can calculate the equivalent length of the pipeline as

50 + 14.65 + 0.314 + 2.93 = 67.894 m

14.11  THERMAL EXPANSION OF PIPE All piping systems expand and contract with the change in temperature. Expansion of pipe depends on the expansion coefficient of the piping material and the temperature difference. Change in length of a pipe is given by Dl = aLoDt where Dl = change in length a = coefficient of linear expansion Lo = original length Dt = change in temperature Pipeline used in a boiler house carries hot fluid, so it must be allowed to expand. It is subjected to large variation in temperature during the fluid flow and no flow. U-loops or expansion loops (Figure 14.2) are provided in the pipeline to take care of this thermal expansion. These expansion loops allow piping system to absorb the force generated by the expansion without doing any harm to the pipeline. Other than the expansion loop, 90° bends, U-bends and offsets (Figure 14.2) are used to reduce the expansion stress. The effect of expansion is usually absorbed by the system at the curves of the pipe.

Figure 14.2 Arrangement for pipeline expansion (a) 90° bend, (b) U-bend, (c) Expansion loop, (d) Offset and (e) U-loop.

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Expansion loop is provided at suitable interval to minimise the expansion stress. Expansion joints are used in low pressure pipelines. Expansion bellow shown in Figure 14.3, makes the pipeline flexible. It can take care of dimension change due to thermal expansion.

Figure 14.3  Expansion bellow.

14.12  PIPE SUPPORTS AND HANGERS Pipeline is subjected to various forces like

• • • • • • •

Weight of the pipe itself Thermal expansion Pressure of the fluid flowing in the pipe Wind load on the pipe Occasional load during hydro test, etc. Vibration due to water hammer Earthquake

To take care of these forces, pipeline is supported at suitable intervals by the pipe supports and hangers. The pipe supports are placed below the pipeline to carry the weight and the supporting members are in compression. Pipeline is hanged on the pipe hangers and the weight carrying members are in tension. Load on the pipe when the pipeline is in cold condition is known as cold load and the load when the pipeline is in hot operating condition is known as hot load. Support locations are dependent on pipe size, piping configuration, location of heavy valves and fittings as well as on the structure available to support the pipe. There are different types of pipe supports/hangers. These are as follows:

• Rigid support • Variable spring support • Constant spring support

Rigid supports/hangers shown in Figure 14.4, are normally used at locations where there is no vertical movement of the pipe. Rollers or antifriction elements are provided to facilitate the axial movement of pipe. In variable spring support/hanger shown in Figure 14.5, vertical expansion of the piping causes expansion or compression of a spring which supports the pipe. The compression and expansion of the spring from cold condition to hot condition is known as travel of support/hanger.

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Figure 14.4  Rigid hanger.

Figure 14.5  Variable spring hanger.

Supporting force varies with the deflection of spring. Since the pipe weight is same during cold or hot condition, the variation in supporting force results in pipe weight transfer to the adjacent support. So, variable spring supports are used when the load variation is less.

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This type of support/hanger is having locking arrangement to make the support inoperative during hydro test, etc. The piston plate should move up and down freely during operation. Normally, the moment of this piston plate is marked with a pointer and scale to show the travel. Position of the pointer is to be checked regularly. A constant support/hanger provides constant supporting force to the pipe at any vertical expansion and contraction. This is achieved by a helical spring and a lever (shown in Figure 14.6) in such a way that the spring force always remains equal to the pipe movement. Constant spring supports are used when load variation is more. Travel indicator of the support indicates the travel.

Figure 14.6  Constant spring hanger.

14.13  INSULATION OF PIPE When hot water or steam flows through pipe, considerable amount of heat energy is radiated out of the pipe surface to the surrounding atmosphere and the fluid temperature drops. To minimise this loss, pipeline is insulated to prevent radiation of heat from the pipe to the surroundings. Different types of insulating materials are used for insulating the pipe. Mineral wool and fibre glass or glass wool insulation with support wire mesh netting and aluminum cladding are used normally in the pipelines. Steel wire mesh is used to provide strength to the insulation. Aluminum cladding is provided for mechanical protection and waterproofing. Insulation slab is available in the market with different thickness. It is cut as per the requirement and fitted. Mineral wool (rock and slag wool) is non-combustible and has a high melting point (1800 °F–2000 °F). It has excellent thermal resistance. Its conductivity is 0.036 kcal/mhr °C and average density is about 100 kg/m3–200 kg/m3. Glass wool is having thermal conductivity 0.045 kcal/mhr °C and its average density is about 80 kg/m3–100 kg/m3. Nowadays, precasted insulations are available for different sizes of pipes, valves and flanges. Thickness of insulation on the pipe depends upon the following factors:

• Heat carried by the fluid • Diameter of the pipe • Temperature of the fluid

Thickness of the insulation is so selected that the surface temperature is around 60 °C. Normally, an insulation upto 65 mm thickness is done in a single layer. If the required thickness is more, then the insulation is done in multilayers.

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Most of the time, the engineers neglect the pipe insulation. Damaged insulation can cause significant loss in the system. So, proper care is to be taken to keep the insulation in proper condition and ensure the insulation is not damaged in any location. Mostly insulation degradation takes place due to following factors:

• Repair of pipeline components or fittings • Steam or water leakage and moisture contamination • Lack of opportunity to repair the damaged insulation due to production constraints

It is advisable to repair the damaged insulation as and when required to avoid heat loss in the system.

14.14  STEAM PIPE LAYOUT Hot steam flows through the pipeline upto the load end. Some amount of heat is lost due to radiation inspite the pipeline is insulated. Due to this loss, some amount of condensate is formed in the pipeline. So, the pipeline is to be properly laid so that this condensate can be removed easily to avoid corrosion, erosion and water hammer. To remove the condensate from the pipeline, steam traps are provided at suitable locations (normally, at lowest point of the system). Trap is fitted to a pocket which is normally provided at the bottom of the pipe, as shown in Figure 14.7.

Figure 14.7  Trap connection in steam line.

It is required to lay the pipeline as straight as possible to minimise the pressure drop. Pipe should be laid with a fall of around 100:1 (1 m fall for every 100 m run) in the direction of steam flow to facilitate the condensate to move towards the trap point. When the diameter of a pipeline is required to be changed, reducers are fitted. Use of eccentric reducer is more suitable than the concentric reducer to avoid water hammer. When a branch pipeline is to be taken from the main pipeline, it should be taken out from the top of the main line, not from the bottom of the line. If it is tapped from the bottom, there is a chance of entry of condensate in the branch line. Suitable isolation valve is to be provided for each branch line. In some cases, more than one incoming steam lines are connected to a common pipeline. In this case, the incoming pipelines should be provided with isolating valves. Sufficient support and proper expansion facility are to be provided to take care of thermal expansion.

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Apart from the above points, following points are to be considered for a perfect pipeline layout:

• Operating and control points are easily accessible. • Pipeline should have sufficient clearance to facilitate maintenance and replacement of fittings. • All pipeline supports are to be accessible for inspection. • Safety of operating and maintenance personnel is to be considered.

14.15  WATER HAMMER Due to the heat loss in a pipeline, steam is condensed. Velocity of steam flowing over the accumulated condensate causes ripples in the water. Turbulence builds up until the water forms a solid mass or slug (Figure 14.8). When this slug of condensate collides with the pipe wall or fittings at high velocity, then the noise and vibration are produced and this is called water hammer. In some cases, the strength of water hammer is so high that it can fracture the pipeline, leading to a severe situation.

Figure 14.8  Water hammer.

Normally, water hammer occurs at the lower point of the pipe due to inadequate removal of the condensate. Opening line isolation valve too quickly during start-up when the pipeline is cold may produce water hammer. So, during starting, it is to be ensured that the condensate is removed completely and the valve must be opened slowly.

14.16  PIPE FITTING Pipe fittings are normally used to

• • • •

Modify flow direction Bring pipes together Alter pipe diameter Terminate pipe

Most commonly used pipe fittings are elbow, bend, tee, reducer, cross, plug and cap. These fittings have flanged or welded ends. Elbow and bend [shown in Figure 14.9(a) and (b)] are used to modify the flow direction. Tee and cross [shown in Figure 14.9(c) and (d)] are used for the branch connection. Reducers are used to join pipes of different sizes. There are two types of reducer—concentric reducer and eccentric reducer as shown in Figure 14.9(e) and (f).

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Plugs and caps are used in the pipe to close the end of the pipe. An end cap is shown in Figure 14.9(g).

Figure 14.9 Pipe fittings (a) Elbow, (b) 90° bend, (c) Tee, (d) Cross, (e) Concentric reducer, (f) Ecentric reducer and (g) End cap.

EXERCISES

1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19.

What is the difference between a tube and a pipe? What do you mean by pipe schedule? What is the ID of a 100 NB, schedule 40 pipe? What is ASTM standard? On what factor (s) does the material standard of the pipe depend? On what factor(s) does the pipe wall thickness depend? Which standards are used for carbon steel tube and pipe? What are SA210 and SA213? What are SA106 and SA335? To which standard does the grades T11, T22 and T91 belong? What is the definition of carbon steel as per American Iron and Steel Institute (AISI)? Where is alloy steel used? What are the roles of chromium and molybdenum in alloy steel? What is difference between austenitic steel and ferritic steel? How is the flow through pipe is calculated? What are the demerits of oversize and undersize pipelines? Where does more pressure drop take place–across gate valve or globe valve? Why is the pipe support required? What are the different types of pipe supports used in a steam pipeline?

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What is the difference between variable spring support constant spring support? What is cold load and hot load? What is travel of a support and how is it measured? Why is the insulation of a pipeline is done and why is cladding provided? Specify the location at which the trap is fitted in a pipeline. From where branch line is taken from a steam line and why? What is water hammer? Why is a reducer used in pipeline and what are its types?

20. 21. 22. 23. 24. 25. 26. 27.

Chapter

15

Pipe Fittings and Ancillaries

15.1  INTRODUCTION A pipeline has different fittings and ancillaries. In the previous chapter, we have discussed about some fittings. In this chapter, we will discuss about some commonly used fittings and ancillaries like flanges, valves, traps and strainers. Practically, in a boiler house, much attention is not paid on these fittings and ancillaries.These small pipeline components play a major role in smooth transportation of fluid in the pipeline. In this chapter, it is tried to provide some details to the reader about these components.

15.2  FLANGE A flange is used to connect two pipes mechanically or to connect a pipe to a valve, tee or other piece of equipment. The principle of a flange is to the mechanical force (by tightening bolts) to preload the gasket sufficiently so that when internal pressure is applied due to fluid pressure, there is enough contact stress between the flange and the gasket to maintain a seal. Flange is required to be fixed to the pipe. This is done by welding, threading and other weldless connections. Flange is manufactured by forging, casting or from plate. Following are the different types of flanges which are classified as per their attachment to the pipe:

• • • • • •

Weld neck flanges Socket weld flanges Slip on flanges Threaded flanges Blind flanges Lapped flanges

Weld Neck Flange Weld neck flange is recognised by its long tapered hub as shown in Figure 15.1. This type of flange is mostly used for high pressure application. 281

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Figure 15.1  Weld neck flange.

Socket Weld Flange In socket weld flange type of flange, a pipe fits into the internal pocket and allows smooth flow through the flange. It is not so much stronger as a weld neck flange. Figure 15.2 shows a socket weld flange. Slip on Flange Slip on flange fits over the pipe and then welded in position. Figure 15.3 shows a slip on flange.



Figure 15.2  Socket weld flange.

Figure 15.3  Slip on flange.

Depending upon the face type, flanges are classified as follows:

• Flat faced flange • Raised faced flange Figure 15.4 shows both these types of flanges.

Figure 15.4  Flange face (a) Raised faced flange and (b) Flat faced flange.

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Normally, for high pressure steam and feedwater pipeline, socket weld raised face (SWRF) and weld neck raised face (WNRF) flanges are used. Sometimes, slip on raised face (SORF) flanges are also found in use. Flanges are manufactured as per ANSI standard B16.5. The material specification for flanges as per ASTM standard is given in Table 15.1 for different flanges. Table 15.1  Material Specification for Flanges as per ASTM Standard Steel

Product Form Forging

Casting

Plate

Carbon Steel

A105 A350

A216

A515 A516 A537

Alloy Steel

A182

A217

A387

Flanges are classified into seven classes named as 150, 300, 400, 600, 900, 1500 and 2500. More the class number, stronger is the flange. The class number indicates the maximum pressure in pound per square inch (psi). When the temperature of the fluid increases, then the maximum working pressure of a particular class flange reduces. Temperature and pressure range of different classes of carbon steel forged (A105) flange is given in Table 15.2. From Table 15.2, it is easier to understand about the class and its working range for different pressures and temperatures. Table 15.2  Temperature and Pressure Range of Different Classes of Carbon Steel Forged (A105) Flange Temperature °C 50 150 250

Working Pressure (kPa)/Flange Class 150

300

400

600

900

1500

2500

1830 1450 1070

4940 4680 4370

6560 6260 5850

9850 9400 8780

14840 14130 13170

24670 23500 21920

41130 39200 36600

Threaded Flange Threaded flange is used at the low pressure pipelines where it is fitted to the pipeline through threads. Blind Flange Blind flange is used at the terminating end of the pipeline where the fluid flow is required to be stopped. Lapped Flange Lapped flange is practically identical to the slip on flange. It is used in the pipeline having stub end.

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15.2.1  Gasket Gasket is a sealant material used in a flange. It is inserted between flanges and compressed by bolts to create seal. Following types of gaskets are used in flanges. These are as follows:

• Gasket sheet • Spiral gasket • Solid metal ring

Gasket sheet is available in various thicknesses. Sheet made from compressed asbestos fibre embedded with reinforcement of steel wire is used for steam and hot feedwater application. This sheet can be cut as per the requirement and fitted. Spiral gasket is available in various sizes in the market. Most of the time, leakage takes place in the flanges. Some important reasons for flange leakages are as follows:

• • • • • • • •

Uneven bolt stress Improper flange alignment Improper gasket centring Excessive load at flange location Thermal shock Improper gasket size or material Improper flange facing Damaged gasket

A proper gasket is to be used and the bolts are to be properly tightened. For tightening flange bolts, a proper sequence is to be followed, as shown in Figure 15.5.

Figure 15.5  Flange bolt tightening sequence.

15.3  TRAP The formation of condensate takes place in the pipeline when the steam temperature drops. This condensate is to drained out from the pipeline to avoid further cooling of steam and water hammer. For this, traps are used in pipeline. The main function of steam trap is to discharge

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the condensate and not permit the steam to escape. During start-up, pipe space is filled with air. So, the trap should be capable of releasing this air. A trap is expected to have the following characteristic:

• • • •

Steam loss should be minimum. It should have trouble-free operation with less maintenance. It must possess long operating life. It should be reliable even under dirty steam condition.

Location of trap should be selected in such a manner so that the condensate in the system should automatically flow to the trap by gravity. Normally, the lowest point of the steam line is considered as the ideal place for trap location. Trap should be accessible for inspection and maintenance.

15.3.1  Different Types of Traps Depending upon the operating principle, traps are classified as follows:

• Thermodynamic trap • Thermostatic trap • Mechanical trap The principles of operations of these traps are velocity, temperature and density respectively.

Thermodynamic or Disc Trap The principle of operation of thermodynamic trap is the difference in velocity or kinetic energy between the steam and the condensate. The operation of this trap depends partly on the formation of flash steam from the condensate. When hot condensate at high pressure passes to a low pressure system, flash steam is produced. This trap is robust and very simple in construction. Figure 15.6 shows a thermodynamic trap.

Figure 15.6  Thermodynamic trap.

There is a disc which opens and closes the outlet port. When disc moves up due to incoming pressure of the condensate, the outlet opens and condensate is discharged. The fresh hot condensate then enters the trap chamber. As the pressure of this hot condensate drops at

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the chamber, flash steam is released. This flush steam builds pressure above the disc and moves it down. This downward movement of the disc closes the outlet. Again after some time, flash steam acting above the disc condenses and the pressure drops. So, the disc moves up due to pressure of condensate and it is discharged. The disc closes when flush steam is formed again. In this way, the cycle repeats. The rate of operation depends upon the steam temperature and the ambient condition. This type of trap has following advantages:

• • • •

It works across its entire working range without any adjustment or change in internals. It can be used at high pressure superheated steam line. As disc is the only moving part, so its maintenance is easier and can be carried out in position. It is compact, simple and lightweight.

Thermostatic Trap Thermostatic trap opens and closes with the movement of a temperature sensitive element. Opening and closing of outlet port of the trap is done by a bellow. During starting, bellow is fully contracted and the outlet port is in open condition. The condensate is discharged out. When temperature inside the trap increases due to flow of steam, it heats up the bellow element and as a result, the bellow is expanded. Expansion of the bellow closes the outlet port of the trap. Again, when the temperature inside the trap drops, the bellow contracts and opens the outlet port, allowing the condensate to discharge. A thermostatic trap is shown in Figure 15.7. Figure 15.7  Thermostatic trap. This trap is suitable during start-up, as it remains in open position during cold. Liquid expansion steam trap, balanced pressure steam trap and bimetallic steam trap also belong to thermostatic group. Mechanical Trap Operating principle of this type of trap is the difference in density between the steam and the condensate. Mainly, two types of trap are used in this group that are as follows: Ball float trap:  In ball float trap (shown in Figure  15.8), opening and closing of outlet valve is achieved by floating of a ball in the condensate. When the condensate level in the trap chamber becomes high, float ball raises and opens the valve. After that, the condensate is discharged and the level of condensate comes down. Due to lower level of condensate, float drops and closes the valve. Again, the condensate level starts rising and the cycle continues.

Figure 15.8  Ball float trap.



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In this type of trap, the outlet valve is always sealed with the condensate. So, the air cannot be vented in this type of trap. For this, a little modification is done in the ball float trap. A thermostatic air vent is provided in it. This modified trap is called float and thermostatic trap (Figure 15.9).

Figure 15.9  Float and thermostatic trap.

This is a normal ball float valve with a thermostatic element placed at steam space of the trap. When the non-condensable air increases at steam space, the temperature of air/steam mixture reduces. So, the bellow contracts and opens a valve to release air. When the temperature of this mixture increases, bellow expands and closes the valve and stops the air release. This type of trap is ideal as it can remove condensate and non-condensable gases. Inverted bucket trap:  This mechanical trap is sometimes called Armstrong converted submerged bucket, introduced by Armstrong in 1911. It operates on the principle of difference in density between the steam and the water. In inverted bucket trap, an upside down or an inverted bucket is attached to an operating lever which opens and closes a valve. A small hole is provided at the top of the bucket for air vent. An inverted bucket trap is shown in Figure 15.10.

Figure 15.10  Inverted bucket trap.

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During starting, bucket sinks in the condensate, thereby causing the valve to open. So, the condensate is discharged in this condition. When steam enters the inverted bucket, it floats and the valve closes. The valve remains closed until the upward thrust of steam decreases due to the condensation of steam. Once the steam condenses, bucket sinks again and the operating cycle continues. This type of trap withstands high pressure and has good tolerance to water hammer. When there is a failure in the trap, it usually remains in open condition and avoids accumulation of condensate. The trap may malfunction when there is insufficient water seal.

15.3.2  Problems, Losses and Testing of Traps Steam traps are provided on steam line to remove condensate. In some cases, when trap fails, it discharges steam continuously. This is known as leakage trap. Steam is a costly fluid. So, the leakage of steam from defective trap costs a lot and makes the system inefficient. Sometimes, the trap may remain inoperative, causing accumulation of condensate. This is known as blocked trap. Most of the time, people ignore a faulty trap. Leaking or blocking of trap, both are undesirable. Impurities, corrosion, water hammer and poor maintenance practices are the most common causes that are responsible for trap failure. So, proper inspection and maintenance practices can help to detect leaking or blocking trap. Accordingly, an initiative can be taken to repair or replace the trap. A trap may be inspected by the three methods mentioned below to detect any faulty trap:

• Visual • Thermal • Acoustic

In visual method, trap is inspected to find whether it is discharging the condensate or the steam. Thermal inspection relies on the upstream and downstream temperature variation across a trap. Various methods like pyrometer, infrared, etc. are used to measure the temperature. In a blocked trap, temperature of the discharge side is less. Acoustic technique requires to listen to detect the steam trap operation and malfunctioning. The listening device may be engineers stethoscope, screw driver or ultrasonic detection instrument.

15.4  VALVE Valves are provided in a pipeline to isolate, regulate and control the flow of fluid. An isolating valve is used when full open or full close position is required. A regulating valve is used in any position between full close to full open. A control valve is power operated or pneumatically operated to control the flow rate in a pipeline. An isolation valve is provided for the following reasons:

• To facilitate maintenance • To allow removal of equipment • To allow shutdown of the plant

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Valves are available with different end connections to be fixed into a pipeline. These are either flanged end (FE) type, socket welding end (SW) type or butt weld end (BW) type. Smaller size valves are manufactured by forging process and larger size valves are manufactured by casting.

15.4.1  Different Types of Valves Depending upon the operating motion of the closure device, valves are classified as linear movement valve or rotary movement valve. Gate valve, globe valve, diaphragm valve and needle valve are the examples of linear movement valve whereas, ball valve and butterfly valve belong to rotary movement valve. Gate Valve In gate valve, a gate slides between the seats of the valve. Movement of the gate is at right angle to the flow of fluid. By opening the valve, flow path is enlarged in a highly non-linear manner with respect to percentage of opening. Gate valve is normally used for isolation application where only fully close or fully open position is required. This valve is suitable where frequent opening and closing is required. The gate fully retracts in the bonnet. So, the pressure drop across the valve is less. The main components of this valve are body, bonnet, gate, handwheel and stem (Figure 15.11).

Figure 15.11  Gate valve.

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There are two types of gate valve. One is non-rising stem type and second one is rising stem type (Figure 15.12). In non-rising stem type valve, the stem is threaded on the lower end into the gate. When handwheel is rotated, the gate travels up or down. The stem remains vertically stationary. In rising stem type valve, the stem is raised vertically when the valve is opened.

Figure 15.12  (a) Non-rising stem valve and (b) Rising stem valve.

Globe Valve Globe valve is a widely used valve in high pressure steam and water line. Movement of the valve disc is parallel to the flow of fluid. Disc of the valve needs to move a small distance from its seat to get the full flow. The main advantage of this valve is that it can be used for throttling purpose and where positive shutoff is required. Globe valve is used for isolation and regulation purpose. Figure 15.13 shows a globe valve.

Figure 15.13  Globe valve.

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The fluid has to change its direction of flow in this valve. So, the resistance to flow is more in this case and causes high pressure drop across the valve. Pressure of the fluid acting over the disc generates an axial thrust on the stem. So, more force is required for closing this valve. There are three types of body design in case of globe valve. These are Z-body, Y-body and angle body. In Z-body design, movement of stem is at right angle to the pipe axis and the valve seat is at horizontal position. In this case, the pressure drop is more. In Y-body design (Figure 15.14), stem and seat of the valve are angled at approximately 45°. The angle facilitates a straight flow path during full opening. So, in this design, the pressure drop is less.

Figure 15.14  Y-type globe valve.

Angle body globe valve is having end at the right angle. The fluid flow is through a single 90° turn. This type of valve acts as a valve and pipe elbow. Diaphragm Valve Diaphragm valve is a linear motion valve. This valve is used to open, isolate and regulate the flow. There is a flexible disc (diaphragm) which matches with a seat. Diaphragm is connected to a compressor which is connected to the stem. Compressor is moved up and down with the movement of stem. When the compressor is lowered, diaphragm is pressed which stops the fluid flow. When stem is raised, then the compressor also raises and the diaphragm lifts and allows the fluid flow. Figure 15.15 shows a diaphragm valve.

Figure 15.15  Diaphragm valve.

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Butterfly Valve Butterfly valve is a rotary motion type valve. The disc rotates 90° from the full close position to the full open position. This valve can be used to open, isolate and regulate the flow. Specifically, this valve is suitable for large volume application with less pressure. The disc may rotate on either a vertical or horizontal axis. Figure 15.16 shows a butterfly valve.

Figure 15.16  Butterfly valve.

Needle Valve Needle valve is used for the fine adjustment of fluid flow. The disc of the valve is along and tapered one like a needle. Figure 15.17 shows a needle valve.

Figure 15.17  Needle valve.

Ball Valve A ball valve has a spherical disc having a hole or port at the centre. This spherical disc is operated by a lever. In close position, the disc port is perpendicular to the valve end or flow direction, so the flow is stopped. In open position, the port is in line with the flow direction and allows the fluid flow. The operating lever or handle is so fitted that it indicates the port position.

15.4.2  Stem Sealing The fluid flowing in the pipe may leak from the stem of a valve. Particularly, in high pressure system, this leakage is severe. So, stem sealing is required. Sealing is done by gland

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packing (Figure 15.18). Packing material is packed in layers in the valve gland. Pressure is applied from the top by tightening the gland adjustment nut. By tightening the gland nut, gland flower or bush is pushed and the packing material is compressed. Valve gland is sealed due to the compression of this packing material. Practically, it is noticed that the pressure on all the layers of packing material is not equal. It is more at atmosphere end and less at pressure end.

Figure 15.18  Gland packing.

If the valve is not used for a significant longer period, gland pack may stiffen and leakage may take place when the valve is operated next time. The atmosphere end packing material is subjected to higher pressure. So, it fails faster. It is required to replace first two or three layers of packing regularly. Gland Packing Material For the sealing of valve stem, gland packing is required. Soft packing material is compressed by the external force. By tightening the gland nut, radial pressure is produced on the gland bush which compresses the gland packing. Hence, an effective sealing of stem is done. Radial pressure can be adjusted by adjusting the gland nut. The gland nut should not be tightened more to avoid overcompression of soft packing, otherwise it may lead to excessive friction, stem wear and premature packing failure. Soft packing material contains lubricant to increase density, dissipate heat and lubricate. Due to compression and overheating in service, packing volume is lost and the effective sealing is affected. Some of the main required properties of a packing material are mentioned below:

• • • • • •

Compatible with working fluid Capable to withstand operating temperature Non-abrasive to minimise the stem erosion Non-corrosive to avoid damage to stem and housing Wear-resistant Retain properties for longer time

The materials commonly used for soft packing are given in Table 15.3.

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Table 15.3  Materials used for Soft Packing Main Constituent

Type

Material

Fibre

Mineral Vegetable Synthetic

Asbestos Cotton, flax, jute Glass, graphite filament, nylon, poly tetrafluroethylene (PTFE)

Lubricant

Dry Wet

Graphite, mica Castor oil, solid fractions, paraffin wax, silicon grease, PTFE dispersions

Metals

Stainless steel wire, inconel wire, monel wire

The fibrous compression soft packings are available in the following forms:

• Plated • Braided • Twisted

Packing material in braided form is mostly used for the valve steam packing. Individual yarns are braided tube over tube and squared off in this type. The density of this type of packing is more. For higher temperature use, graphite filament-based packing material reinforced with steel wire is preferred. This type of packing can be used upto 600 °C temperature. Lubricants, as mentioned earlier, are used in different fibre packings. It is applied to the packing by dipping, coating, soaking, vacuum impregnation and dusting. The fibre packing is supposed to retain this lubricant for a longer period. Gland packing is available in the market in long length (roll) of various sizes (thickness). As per the requirement, pieces are cut from the roll and used. The working temperatures of some commonly used packing materials are mentioned in Table 15.4. Table 15.4  Working Temperature of Some Commonly used Packing Materials Material

Temperature, (°C)

Jute Cotton Ruberised Cotton PTFE Graphite Fibre Lubricated Asbestos Fibre Self-lubricated Fibre Asbestos with Flake Graphite or Mica Lubricated Asbestos, Reinforced Stainless Steel

0 to 60 0 to 70 0 to 80 –250 to 220 –200 to 600 0 to 350 0 to 540 0 to 800

15.4.3  Standard and Material Specification of Valve Different valves are manufactured as per ASME B16.34 standard. These are manufactured either by casting or forging. Material specification of most commonly used carbon steel and alloy steel valves for both casting and forging is given in Table 15.5.

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Table 15.5  Material Specification of Carbon Steel and Alloy Steel Valves Material

Casting

Forging

Carbon Steel

ASTM A216 Grade WCA, WCB, WCC

ASTM A105

Alloy Steel

ASTM A217 Grade WC1, WC4, WC5, WC6, WC9, C5, C12

ASTM A182 Grade F1, F11, F22

Forged carbon steel and alloy steel valves are available maximum upto 2 inch size. Cast carbon steel and cast alloy steel valves are manufactured in higher sizes. Valves are classified as per their pressure and temperature ratings. As per ANSI standard, valves are classified from class 150 to class 2500. The class of the valve means pressure rating of the valve. More class number means it can be used at higher pressure. The class number indicates the pressure rating of the valve in pound per square inch (psi). For example, 600 class valve means, its pressure rating is 600 psi. The pressure and temperature ratings of ASTM A216, Grade WCB and ASTM A217, Grade WC6 are given in Tables 15.6 and 15.7, respectively. It is to be noted that carbon steel valve (A216 and A105) can be used maximum upto 420 °C. Table 15.6  Working Pressure and Temperature of ASTM A216 Grade WCB Temperature (°F) –20 to 100 200 300 400 500 600 650 700 750 800 850 900 950 1000

Working Pressure (psi)/Class 150 285 260 230 200 170 140 125 110 95 80 65 50 35 20

300 740 675 655 635 600 550 535 535 505 410 270 170 105 50

600

900

1500

2500

1480 1350 1315 1270 1200 1095 1075 1065 1010 825 535 345 205 105

2220 2025 1970 1900 1795 1640 1610 1600 1510 1235 805 515 310 155

3705 3375 3280 3170 2995 2735 2685 2665 2520 2060 1340 860 515 260

6170 5625 5470 5280 4990 4560 4475 4440 4200 3430 2230 1430 860 430

Table 15.7  Working Pressure and Temperature of ASTM A217 Grade WC6 Temperature (°F) –20 to 100 200 300 400

Working Pressure (psi)/Class 150 290 260 230 200

300 750 750 720 695

600

900

1500

2500

1500 1500 1445 1385

2250 2250 2165 2080

3750 3750 3610 3465

6250 6250 6015 5775 (Contd.)

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Table 15.7  Working Pressure and Temperature of ASTM A217 Grade WC6 (Contd.) Temperature (°F)

Working Pressure (psi)/Class 150

300

600

900

1500

2500

500 600 650 700 750 800 850 900 950 1000 1050 1100 1150 1200

170 140 125 110 95 80 65 50 35 20 20 20 20 15

665 605 590 570 530 510 485 450 320 215 145 95 60 40

1330 1210 1175 1135 1065 1015 975 900 640 430 290 190 125 75

1995 1815 1765 1705 1595 1525 1460 1350 955 650 430 290 185 115

3325 3025 2940 2840 2660 2540 2435 2245 1595 1080 720 480 310 190

5540 5040 4905 4730 4430 4230 4060 3745 2655 1800 1200 800 515 315

15.5  NON-RETURN VALVE (NRV) To prevent the flow reversal in a piping system, non-return valve (NRV) is used. NRV is also called check valve. Some of the main reasons to use NRV in a pipeline are mentioned below:

• Protection of equipment due to reverse flow • Prevention of reverse flow in the system during system shutdown • Prevention of backflow under gravity

In the boilers, this valve is used in feedwater line, attemperator spray water line, HP dosing line and main steam line. The feedwater should not flow back, in case the feed pump pressure drops. Sometimes, the NRV fixed at feedwater line is called feed check valve. A boiler is in pressurised condition during service. If the feed pump fails in this condition for any reason, this higher pressure of the boiler forces the water back from the boiler. If no NRV is fitted, the boiler will be emptied in this condition. Like this, in case of an attemperator, high pressure steam tries to flow in the attemperator spray line if the spray water pressure drops and NRV is not provided. When more than one boiler are connected in parallel, NRV is provided at the main steam line to ensure there is no possibility of steam backflow in any boiler. There are different types of NRV. But the basic principle of operation is same for all NRVs. It is operated by the reverse flow of flowing fluid in the pipeline. It does not require any external actuating force to operate. Pressure of the fluid opens the valve and allows the fluid to flow. When there is a reversal of flow, it closes the valve and stops the flow. The closure of valve is achieved by the weight of check mechanism and back pressure of the fluid or spring. Some of the common types of NRVs are swing check valve, lift check valve, disc check valve, split disc check valve, tilting disc check valve, piston check valve, butterfly check valve, etc. Here, some important types of check valves are discussed only.

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Swing Check Valve Swing check valve has a disc hanging down in the flow path with a hinge, as shown in Figure  15.19. When the fluid flows in forward direction, pressure of the fluid pushes the disc upward, thereby allowing the fluid to flow. Reverse flow drops the disc and seals against the seat. So, the flow stops in reverse direction. During no flow, the valve remains in closed position due to its own weight. In some cases, weighted lever is used to assist the closing.

Figure 15.19  Swing check valve.

Seat of the valve is replaceable. As the disc remains floating on the fluid during normal flow, so the pressure drop in this type of check valve is high. Lift Check Valve Lift check valve is having similar seating arrangement as a globe valve. The disc rests on a seat to close the flow. This type of valve is used in steam and water line having high flow velocity. Figure 15.20 shows a lift check valve.

Figure 15.20  Lift check valve.

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Fluid enters the NRV below the seat. The pressure of upward flow of the fluid lifts the disc from seat and allows the flow. When flow stops or reverses, the disc sits on the valve seat and stops the flow. Disc Check Valve This type of check valve is having a disc which is closed by the action of spring. When fluid enters the NRV in forward direction, a force is exerted on the disc due to the fluid pressure. When this force is more than the spring force, the disc is forced to move from the seat in the flow direction and allows the fluid flow. When the pressure of fluid becomes low or during the reverse flow, the disc back onto its seat and stops the flow due to the action of spring.

15.6  STRAINER Strainer is an important device which removes solids from the flowing fluid. Most of the engineers overlook this simple equipment. But this small equipment protects pump, turbine, meter, control valve, spray nozzle, steam trap and other pipeline equipments. A pipeline strainer is a device which removes solids present in the flowing fluid mechanically by perforated or mesh wire straining element. A strainer protects the downstream equipment by removing the pipeline debris such as scale, rust, jointing compound, weld metal and other solids from the fluid. These are available in two types as per their body configuration. These are Y-type and basket type. Y-type Strainer Y-type strainer is universally used. It has a compact cylindrical shape and is very strong. This can be used in high pressure pipeline. But it has less dirt holding capacity and needs frequent cleaning. A blowdown valve can be fitted in the strainer cap. Where a significant amount of debris is expected. By opening the valve, this can be cleaned by the fluid pressure. During commissioning of pipeline, these strainers get chocked frequently. In horizontal steam line, the strainer is so fitted that the pocket is in the horizontal plane to avoid water collection in the pocket. In feedwater line, the pocket should be vertically downward to ensure that the removed debris does not reenter the fluid. Basket Type Strainer Normally, basket type strainer is used in feedwater line. In this type of strainer, screen is put in a vertical oriented outer chamber. The straining area is more in this case. So, it is preferred in liquid pipelines. If it is used in steam line, suitable draining is required to remove the condensate. Sometimes, duplex arrangement of basket strainer is preferred. Second strainer is placed in parallel with the main strainer. A suitable changeover arrangement is provided for diverting the fluid flow from one strainer to another. One of the strainers is kept in operation while the other one is kept as standby.

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15.6.1  Strainer Screens Two types of screens are used in a strainer. These are perforated screen and mesh screen. Perforated screen is formed by punching large number of holes in a flat sheet and then, rolling into tube and spot welding together. This type of screen is suitable to remove general pipeline debris. Mesh screen is formed by layering fine wire mesh over a perforated screen. Perforated screen acts as a support cage for the mesh. Smaller particles can be removed through this screen. Flanged end or weld end strainers are also available to use in the pipelines.

EXERCISES

1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14.



15. 16. 17. 18. 19.

What are the commonly used flanges classified as per their attachment to pipe? How are flanges classified as per their face type? What does the class of flange mean? What is the function of gasket and how is it done? Why are traps used in a pipeline? What are the common types of traps? How does a defective trap make the system inefficient and how are the traps checked? Why is valve provided in a pipeline? In which end connections are the valves available? What is the difference between gate valve and globe valve? Why is the pressure drop across a globe valve is more than that of gate valve? What is the difference between raising stem valve and non-raising stem valve? How is the valve stem sealing done? What is the standard for cast carbon steel valve and upto what temperature can the carbon steel valve be used? What is the standard for alloy steel valve? What does the class of a valve mean? What is the basic principle of a non-return valve? Why is a strainer used in a pipeline and what are its types? How does a basket type strainer work?

Chapter

16

Steam Turbine

16.1  INTRODUCTION Sir Charles Algernon Parsons (1854–1931), a British engineer, patented modern steam turbine in 1884. The crude form of steam turbine was made by Hero Alexandria during 1st century AD, called Hero’s ball or Aeolipile (Figure 16.1). It was the first form of reaction steam turbine. This device was consisting of an airtight chamber (sphere) with bent or curved pipes projected in opposite directions. When steam is expelled from the curved pipes, the sphere starts rotating.

Figure 16.1  Aeolipile.

The first model of Parsons turbine was connected to a small dynamo to generate electricity. Nowadays , large steam turbines are used to generate 1000 MW electricity. Steam turbine is a mechanical device that extracts kinetic energy from the pressurised steam and converts it into useful mechanical work. It generates rotary motion directly. Interior of a turbine consists of several sets of blades. Some sets of blades are fixed on the casing and some sets of blades are fixed on the rotor. The blades fixed on the casing are called fixed blades and the blades fixed on the rotor are called rotating or moving blades. Clearance between these two blade sets is very minimum. Steam is allowed to expand in these blades. 300

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Fixed blade converts the potential energy of the steam into kinetic energy and directs the flow to the moving blade. Moving blades convert this kinetic energy into force and rotate the turbine shaft. Steam turbines are mostly axial flow type. Steam flows over the blades in the direction parallel to the axis of the rotor. Modern turbines are mostly multistage type. There are number of stages of fixed and moving blades to increase the efficiency of turbine. Depending upon how energy is exerted from the blades, turbines are classified into impulse and reaction turbine. Steam is allowed to enter the turbine through control valve. After passing through different stages of blade sets, steam is allowed to exhaust. This exhaust steam from turbine may have some useful heat contents and may be used for some other purposes. This type of turbine is called back pressure turbine. In some designs, exhaust steam is condensed in a condenser. This type of turbine is called condensing turbine.

16.2  Impulse and Reaction turbine As discussed earlier, on the basis of operation principle, steam turbines are classified as impulse and reaction turbine. Impulse turbine uses impulse force of the steam on the blades to move the rotor. In reaction turbine, shaft is rotated by reactive force rather than by a direct push or impulse.

16.2.1  Impulse Turbine In impulse turbine, instead of a set of fixed blades, a set of nozzles are fitted in the casing. Steam pressure drops at these nozzles. Hence, the velocity of steam increases. This jet of steam contains significant amount of kinetic energy. This high velocity steam is passed through a set of moving blades where pressure of the steam remains constant and velocity decreases, as shown in Figure 16.2.

Figure 16.2  Impulse turbine.

To reduce the rotational speed of turbine, multistaging is done. Multiple set of nozzles and moving blades are fixed in series. This is also called compounding. Either steam pressure or steam velocity is dropped in these stages depending on the type of compounding.

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Compounding of impulse turbine is done in following three ways:

• Pressure compounding • Velocity compounding • Pressure–velocity compounding

In pressure compounding, the total pressure drop of steam is achieved step by step. Pressure drop across several stages is shown in Figure 16.3. Nozzles and moving blades are fixed at every stage. Steam passing through the first stage of nozzles is directed to the first row of moving blades. Exhaust steam of this moving blade row enters the second stage nozzle sets and is diverted to the second row of moving blades. It continues till the exhaust pressure is reached.

Figure 16.3  Pressure compounding of impulse turbine.

In velocity compounding, there is only one set of nozzles. The total pressure drop takes place in this set of nozzles. But velocity drop takes place at different stages of the moving blades, as shown in Figure 16.4. The high pressure steam enters a set of nozzles where the steam pressure decreases and the velocity increases. The steam coming out from this nozzle set is directed to a set of moving blades. On these blades, the velocity drops. The steam coming out from these blades is guided back by another set of fixed blades. Neither pressure nor velocity drops on these fixed guide blades. Steam from these guide blades enters the second stage of moving blades. Here, the velocity of steam reduces further. This process continues till the velocity of steam drops significantly.

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Figure 16.4  Velocity compounding of impulse turbine.

In case of pressure–velocity compounding, pressure drop takes place at different nozzle sets and velocity drop takes place at different moving blade sets, as shown in Figure 16.5.

Figure 16.5  Pressure–velocity compounding of impulse turbine.

Velocity Triangle of Impulse Turbine It can be seen from Figure 16.6 that the steam enters the curved blade at point C from the nozzle.

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For shockless entry and exit, jet of steam enters the blade and leaves the blade tangentially. Steam leaves the blade at point D.

Various vectors shown are Vb = Linear velocity of moving blade V = Absolute velocity of steam entering the moving blade Vg = Relative velocity of steam jet and moving blade Vf = Vertical component of inlet steam velocity Vw = Horizontal component of inlet steam velocity V1, Vg1, Vf1, Vw1 = Corresponding values at exit.

Figure 16.6  Velocity triangle of impulse turbine.

16.2.2  Reaction Turbine In a reaction turbine, fixed blades are attached to the casing. Shape of these blades is such that the space between these blades has a cross section similar to the shape of a nozzle. The moving blades are fixed to the rotor. Shape of these moving blades is so designed that the steam glides over these blades. The steam, while gliding over moving blades produces a reaction on the blade. This reaction force produced, rotates the rotor. Steam coming out from the moving blades is guided by the fixed blades to enter the next stage moving blades. Pressure drop across both moving and fixed blades is shown in Figure 16.7. Velocity Triangle of Reaction Turbine From fixed blades, steam enters the moving blade at end C (Figure 16.8). Steam jet glides over the surface of the moving blade and leaves at point D. Like impulse turbine, steam enters and leaves the moving blade tangentially to minimise the shock.

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Figure 16.7  (a) Reaction turbine and (b) Compounding of reaction turbine.



Vb = Linear velocity of moving blade V = Absolute velocity of steam entering the moving blade Vg = Relative velocity of steam jet and moving blade Vf = Vertical component of inlet steam velocity Vw = Horizontal component of inlet steam velocity V1, Vg1, Vf1, Vw1 = Corresponding values at exit.

Figure 16.8  Velocity triangle of reaction turbine.

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16.3  CLASSIFICATION OF STEAM TURBINE Steam turbines are classified into various types depending upon their mode of operation, constructional features and steam parametres. These are classified normally into the following types: On the Basis of Blade Design

– Impulse turbine – Reaction turbine – Impulse–reaction turbine

On the Basis of Steam Flow

– Axial flow turbine – Radial flow turbine

On the Basis of Exhaust Condition of Turbine

– Straight condensing or closed cycle turbine – Non-condensing or back pressure turbine – Partial condensing or extraction turbine

On the Basis of Pressure of Turbine

– High pressure turbine – Low pressure turbine – Medium pressure turbine

On the Basis of Application

– Utility turbine – Industrial turbine – Marine turbine

On the Basis of Point of Steam Entry

– End admission turbine – Centre admission turbine

On the Basis of Steam Extraction or Admission

– Extraction turbine – Admission turbine Some important types of turbine are discussed below.

Straight Condensing Turbine In straight condensing turbine, steam enters the turbine through a governing valve (Figure 16.9). After doing work inside the turbine, pressure and temperature of the steam decrease. Steam cannot be expanded

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Figure 16.9  Straight condensing turbine.

further, as it becomes wet towards the last stage blade. The exhaust steam is condensed in a condenser and the condensate is used further at a boiler for the formation of steam. During expansion in various stages, pressure of the steam decreases and volume increases correspondingly. So, the blade size of the turbine increases in each stage starting from the first stage to the last stage to handle this increased volume of steam. Back Pressure or Non-condensing Turbine Figure 16.10 shows a back pressure turbine. In this type of turbine, steam is not expanded fully inside the turbine. After utilising the heat energy of steam partially in a turbine, the entire steam is exhausted with certain pressure and temperature. This steam is used elsewhere to process the heat requirement. This exhaust steam parameter is as per the process requirement.

Figure 16.10  Back pressure turbine.

Partial Condensing or Extraction Turbine In extraction turbine, there are two inlet valves (Figure 16.11). The turbine acts as two turbines connected in a series. The first portion of the turbine is called HP stage and the second portion is called LP stage. Some quantity of steam is bleed out after the HP stage. The remaining quantity of steam is passed to the LP stage.

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Figure 16.11  Partial condensing turbine.

There are two types of extraction turbine, i.e. controlled extraction and uncontrolled extraction turbine. In controlled extraction turbine, a desired quantity of steam can be extracted from the turbine. To get more extraction steam, HP control valve is opened and LP control valve is closed. Whereas, in uncontrolled extraction turbine, the extraction quantity depends upon the load (hence, inlet steam flow) of the turbine and that cannot be increased. The steam is commonly extracted to reheat it in the boiler and reuse at the turbine to increase the plant efficiency. Also, the extracted steam is used to heat up the feedwater of a boiler at feedwater heaters. In process plants, extraction steam is used for process heating. Centre Admission Turbine Nowadays, large size turbines are manufactured with higher capacity. In traditional end entry turbine design, the steam enters from one end and is allowed to expand till it is exhausted at the exhaust end. In this case, large amount of axial thrust is produced on the rotor. Thrust produced is taken care by the thrust bearings. But for larger size turbines, this thrust is too high to be taken care by the thrust bearings. So, centre admission turbines are used. Steam flows towards both the ends and the axial thrust produced is minimised. Figure 16.12 shows a centre admission turbine.

Figure 16.12  Centre admission turbine.



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Admission Turbine In this turbine, steam along with various parameters is admitted to the turbine at different points. The steam is allowed to enter the turbine at a particular stage where the parameter of steam matches.

16.4  MAIN COMPONENTS OF STEAM TURBINE High pressure steam at higher temperature is used to drive a steam turbine. Normally, a turbine rotates at higher speed. So, special care is taken while designing the main components of a turbine. Some main components of a steam turbine are discussed here. These components are mainly the integral part of a steam turbine.

16.4.1  Casing Casing of the turbine plays an important role in the performance of a turbine. This is the outer shell of a turbine. Fixed blades and nozzles are attached to this. Casing facilitates to accommodate moving parts and provides passage for steam. Normally, it is manufactured by casting. As the operating temperature of steam turbine is high, so normally, Cr–Mo alloy steel casting is used for casing of a turbine. Casting is thoroughly checked by the non-destructive testing methods. Casing is hydrostatically tested to confirm its suitability for pressure rating of steam. Normally, casting is done in two halves. Each half is machined to accommodate the fixed blades, bearings, labyrinths, etc. Two halves of the casing are matched at parting plane and fastened by bolts. Metal to metal joint sealing is done to avoid any steam leakage. Throttle or control valve assembly are housed in the steam chest located at the inlet end of turbine casing. Steam first enters the turbine through steam chest. Throttle valve regulates the entry of steam to the nozzle block. Facilities for drains, extraction points, instrumentation tapings are provided during casting of the casing. Proper care is required to be taken during the starting of turbine from cold for proper expansion of casing. The mass of casing is high and the wall is thicker. So, it requires more time to expand. A provision is made to facilitate its thermal expansion. The exhaust end of casing is rigidly fixed to the base foundation and the high temperature end is free to expand. So, during operation, casing expands towards the front of the turbine. As the clearance between fixed blades and moving blades is very less, so the expansion of casing and rotor are required to be uniform. Otherwise, there is a chance of rubbing of fixed and moving parts. During starting or low load condition, there are the chances of steam condensation. So, casing drains are provided at lower casing to drain out this condensate. The outer surface of casing is exposed to the atmosphere. So, the entire casing is insulated with a suitable heat insulating material to avoid heat radiation.

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16.4.2  Rotor Rotor is the moving part of a steam turbine which extracts work from the steam. This is the heaviest part of the turbine. A rotor consists of shaft, moving blades and interstage sealing. Thrust collar is provided to take care of axial thrust of rotor during various load conditions. Shaft is a solid forging of suitable material to withstand inlet steam pressure and temperature. Like casing, shaft is tested through NDT procedures to detect any manufacturing defects. Suitable grooves are machined on the shaft to fix the moving blades and interstage labyrinths. Rotor is a critical component of a turbine. It is supported at both ends by journal bearings. As the rotor of the turbine rotates at high speed, so it is dynamically balanced. It is allowed to expand uniformly during starting to follow the starting curve, as advised by the turbine manufacturer. The rotor of a larger turbine should not be allowed to remain standstill when it is hot. Due to its self-weight, there is a chance of sagging or deformation of rotor. So, rotor is having a suitable arrangement for barring device which rotates the rotor at slow speed when the turbine is hot and in stop condition. The inlet steam pressure is higher than the exhaust end pressure. So, an axial thrust is produced. This is counteracted by a balancing piston. The steam is admitted to a dummy or balance piston chamber. This is a disc-shaped attachment to the rotor. When the rotor is fitted inside the casing, a chamber is formed. Steam is admitted in the counterdirection of the main steam flow and hence, a counterthrust is produced on the balance disc. This thrust minimises the rotor axial thrust. Figure 16.13 shows a turbine rotor.

Figure 16.13  Turbine rotor.

16.4.3  Moving Blade As discussed earlier, the kinetic energy of steam is converted into rotational energy as it passes through the turbine blade sets. In each stage of the turbine, there are moving and fixed blades. At each stage, the pressure of steam decreases, so its volume increases. The blade has to handle more volume of steam in the preceding stage. Moving blades are fixed on the rotor shaft by a suitable root design. These rotating blades convert the kinetic energy of steam into mechanical energy to rotate the turbine shaft. A blade has to withstand higher pressure and temperature at the inlet stage. The pressure and temperature of steam decrease gradually. Towards the last stage of blade, the steam becomes

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wet and its volume becomes more. So, the blade size at the exit stage is larger and it has to withstand erosion caused by the moist steam. A suitable material is used for the manufacturing of blade. Properties of a Good Blade Material

• • • • • • • • •

Good tensile and fatigue strength Toughness and ductility at working temperature Resistance to corrosion and erosion Rate of expansion similar to casing material Good machinability Low ductility Good vibration damping property Good creep resistance Weldability

The entire blade can be divided into following three sections (shown in Figure 16.14):

• Tip • Profile • Root

Figure 16.14  (a) Different portions of moving blade and (b) Profile of moving blade.

Tip As the rotor rotates at higher speed and is subjected to variations in the steam impulse during load changes, so the blades are required to be strong enough to withstand this impulse. Tips of the blade are formed into shrouds which closely contact the adjacent blade. Shrouding is done to maintain rigidity. It reduces vibration of the blades due to the change in impulse of the steam flow. Due to minimal clearance between shroud and turbine casing, steam leakage around the outer edge of the blade is prevented. Shrouding is fitted on the blade tip (tenon) by brazing, welding or riveting. Damping wire or lancing wire is fitted at the last stage (bigger size) blades. Lancing wire passes through a hole, drilled on the blade. During the rotation of a rotor, this wire contacts the outer surface of the blade hole due to centrifugal force and increases rigidity.

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Profile The geometry of a blade or profile is designed to minimise the energy loss. The profiles for different stages of blades are different. It depends upon the steam parameter at that particular blade stage. The profiles for impulse and reaction blades are different. Root As discussed earlier, the moving blades are fixed at the rotor. Blades are fitted to the rotor one by one and finally, are locked by suitable means. There are different types of root design depending upon the load on the blade. Normally, blade roots are fitted into the grooves made on the rotor. The turbine rotor blades are highly stressed components. These are subjected to variation in operating parameters, mode of operation, start-up and shutdown, thermal stress, high speed, centrifugal force, etc. So, the blades are required to be fixed to the shaft properly. In some accidental cases, it is found that moving blades have come out from the rotor and caused severe damage. T-root, double T-root, fork root, etc. are some of the root design used for fixing the moving blades. Depending upon the direction in which the root enters the rotor base, the roots are classified as follows:

• Axial entry or side entry type • Radial entry type • Tangential entry type

Figure 16.15 shows different types of roots of a blade. During operation of turbine, there is chance of damage of these roots due to severe thermal and centrifugal force. The root may be damaged due to the bad steam quality, corrosion cracking, etc.

Figure 16.15  Roots of blade.

16.4.4  Fixed Blades and Diaphragm The partitions between pressure stages in a turbine’s casing are called diaphragms. They hold the vane-shaped fixed blades which facilitate the expansion of steam and guide it to flow over the subsequent moving blade row. One-half of the diaphragm is fitted to the top casing and the other half to the bottom. Mostly, the diaphragm is split horizontally for facilitating assembly. These diaphragms are fixed to the casing by a suitable arrangement. Like moving blades, a diaphragm comprises of following three main sections (shown in Figure 16.16):

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Figure 16.16  Diaphragm.



• Outer ring • Blade ring • Inner ring or web

Outer Ring Outer ring can be compared with the root of the moving blade. Through outer ring, diaphragm is fixed to the turbine casing. Blade Ring This portion of the diaphragm contains fixed blades. The profile and orientation of these blades are such that they direct the steam to the next moving blade row. The profile of a fixed blade is mostly same as that of a moving blade. But the tolerance of a fixed blade is less than that of a moving blade, as stress induced in case of fixed blade is less. Inner Ring or Web This is the inner diameter of the diaphragm. Through inner ring, rotor of the turbine passes. Fixed blades are located within the inner and outer rings by the following methods:

• • • • • •

Pinned construction Welded construction Cast construction Machined construction Built-up Fixed body blades

16.4.5  Steam Sealing System Steam entering the turbine is guided by the fixed blades and directed to the moving blades. The entire steam should pass through the fixed blade and moving blade sets. The pressure difference between each stage of the moving blade and the fixed blade sets is different. So, there is a chance of steam leakage from one stage to another, resulting in lower efficiency of the turbine.

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Labyrinth type sealing is adopted in modern steam turbines to minimise the steam leakage. Labyrinth is defined as a complicated network of passage. It prevents easy leakage passage of steam. Sealing depends on the labyrinth gap and the length of leakage path. Cross sections of different types of seal fins are shown in Figure 16.17.

Figure 16.17  Labyrinth seal fin.

The main features of a seal strip are as follows:

• Its thickness b is sufficient to withstand the stress induced due to the pressure drop across it. • It has a very thin tip having thickness x to ensure the strip should wear without damaging and creating excessive heat if rubbing. Various types of labyrinth sealing system are given below:



• Straight through type seal • High low type seal • Alter arrangement type seal

Straight Through Type Seal In this type, series of fins are arranged to throttle the steam between fin tip and body having clearance C, as shown in the Figure 16.18.

Figure 16.18  Straight through type seal.

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High Low Type Seal In this arrangement, higher and lower length fins are provided alternatively to perform successive throttling. As the height of the fins is different, so more turbulence is created, resulting in a better sealing. Figure 16.19 shows a high low type seal.

Figure 16.19  High low type seal.

Alter Arrangement Type Seal In this type of arrangement, fins are fixed alternatively in rotating and fixed parts. Clearance of the upper and lower teeth is kept same. In this case, fins are inserted into rotor and casing in the grooves provided. Fins which are fixed at rotor are subjected to higher stress due to centrifugal force. Fins are inserted into fixed or moving portion by various methods. Sometimes, strips are directly inserted into the parent material. Sometimes, the fins are bent to L-shape and inserted into specially prepared grooves. Figure 16.20 shows an alternate arrangement type seal.

Figure 16.20  Alternate arrangement type seal.

Sometimes, multiteeth seals (Figure 16.21) are inserted into the parent material with suitable root design like blades.

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Figure 16.21  Multiteeth seal.

It is required to provide sealing arrangement between the moving and fixed parts of the turbine to restrict steam leakage from the blade system. Multiple labyrinth seals are provided at the inner faces between the diaphragm and the rotor. For moving blades, labyrinths seal is provided at the casing to restrict steam leakage from the moving blade and the stationary casing. Seal strips are fixed on the rotor at the grove provided for diaphragm sealing. This sealing arrangement is called interstage sealing. Turbine rotor is expanded out of casing at both ends to provide bearings and for coupling. This portion is called gland. At these ends, there are the chances of high pressure steam leakage from the steam entry end and air ingress at the exhaust end where vacuum exists. So, sealing of the gland is very important. Ineffective sealing results in steam leakage and hence, lowers the efficiency. Labyrinth type sealing arrangement is done at the gland portion to avoid steam leakage and air ingress. Along with labyrinth seal arrangement, steam is also used to assist sealing. This sealing arrangement is called gland sealing.

16.4.6  Bearings The rotor of a turbine is required to be supported at both ends. Normally, the extended portion of shaft is supported at both ends—at front and rear bearing pedestal. Mostly, journal bearings are provided at these bearing pedestals to support the rotor. Also, thrust bearing is provided to take care of axial shift of the rotor in both directions and keep the rotor at a desired position. These bearings play a vital role in the smooth operation of the turbines. The function and principle of these bearings are discussed here. Journal Bearing Journal bearing is a cylinder which surrounds the shaft and is filled with lubricating oil. It consists of a split outer shell of hard metal and a soft metal at the inner cylindrical part (Figure 16.22). Shaft (rotor) or journal rotates inside the bearing over a layer of lubricating oil, separating the shaft and bearing due to fluid dynamic principle. This lubricating oil layer supports the shaft, preventing metal to metal contact. Oil is pumped into the bearing through oil pump. When rotor rotates, lubricating oil is drawn up around the journal due to hydrodynamic effect and two surfaces of rolling contact create a large increase in pressure. As viscosity is exponentially related to the pressure, a large increase in viscosity

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Figure 16.22  Journal bearing.

occurs between journal and bearing and creates a thin oil film which prevents their contact. It creates an oil wedge that supports the shaft and relocates it within the bearing clearance. This oil wedge lifts and supports the shaft. Oil also carries out the heat that is generated in the bearing due to friction and heat of the shaft due to conduction. This oil is then cooled in an oil cooler and supplied again to the bearings. Journal bearing is split into two halves in the horizontal plane. So, the bearing can be replaced without removing the rotor. Inner surface of this bearing is coated with a soft metal known as white metal or babbit. Thickness of babbit is 1 mil to 100 mil depending upon the bearing diameter. Babbit metal contains tin with a smaller amount of antimony, copper and lead. This babbit lining is a sacrificial layer and provides a surface which does not damage the shaft if contact is made accidentally. Some of the failure mechanisms of babbit are as follows:

• • • •

Overload Overheating Fatigue Erosion

Minor babbit imperfections can be repaired by scrapping or lapping. Major repair can be done by locally puddling or rebabbiting. Journal bearing also facilitates damping. More viscous and thicker lubrication oil provides higher damping properties. A suitable bearing design holds the rotor at a fixed position during transient moments such as start-up, shutdown and load changes. Damping property also limits the vibration of a rotor. Rotor supported by journal bearing moves relative to the bearing housing during transient. Vibration probes are used to measure these vibrations/relative motions. Non-contact type eddy current or proximity pickup sensors are used to measure the vibration. These sensors are mounted on the bearing pedestal. The vibration probe mounting system is discussed in further chapters of the book.

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To measure bearing temperature, resistance temperature detectors (RTDs) are embedded in the bearing and its lead is taken out from the bearing pedestal for further termination. Lube oil supply and return pipe lines are connected to the bearing pedestal. Sealing ring is provided to avoid oil leakage from the point where rotor penetrates the bearing. This oil seal ring seals the oil leakage in the same principle as labyrinth rings seal the steam at gland area. As discussed earlier, front bearing pedestal is free to expand at both the axial directions to facilitate the expansion of turbine casing. Thrust Bearing Journal bearings are used to take radial load of the shaft. But they cannnot take axial load. Shaft is permitted to float to both the axial directions. But the axial float is restricted to certain limit. Excessive axial shift may damage the rotating and fixed parts. For this, thrust bearings are provided. Particularly in turbines, fluid film tilting pad type thrust bearing is used. Thrust bearing consists of a series of sector-shaped shoes or pads, fixed on pivots and arranged in a circle around the shaft collar (Figure 16.23). Oil pressure causes the pad to tilt slightly, building a wedge of pressurised fluid between the shoe and the collar surface (Figure 16.24).

Figure 16.23  Thrust bearing.

Figure 16.24  Double acting thrust bearing.

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Each pad is free to tilt so that it creates a self-sustaining hydrodynamic oil film to eliminate metal to metal contact. Like journal bearing, the face of these pads is babbited. Pads are arranged around the projected collar of the shaft. Lubrication oil is supplied to create an oil film between the shaft collar and the bearing pad. The pads are fitted with temperature sensors (RTDs). Normally, two sets of thrust bearings are provided in front bearing pedestal at both sides of the shaft collar. Proper oil supply provision is made for proper lubrication. Radial and axial clearances in a steam turbine:  As discussed earlier, the clearance between the internals of a steam turbine is very less. So, proper care is required to be taken for safe operation of the set. Some approximate radial and axial clearances of a steam turbine generator (STG) set are given in Table 16.1. Actual clearance may vary depending upon the size and design of the turbine. Table 16.1  Approximate Radial and Axial Clearnaces of a STG Set Radial Clearance Journal Bearing Steam Gland Blade Tip to Casing Fin Generator Air Gap

0.25 mm to 0.35 mm (varies with journal diameter) 0.35 mm to 0.45 mm 0.7 mm to 1.5 mm 10 mm to 12.5 mm

Axial Clearance With Thrust Pad Without Thrust Pad and With All Internals Active Side Non-active Side

0.35 mm to 0.45 mm 3.5 mm to 4.5 mm 2.5 mm to 3 mm 1 mm to 1.5 mm

Blade Clearance Active Side Non-active Side

5 mm to 7 mm 3.5 mm to 6 mm

16.4.7  Gland In a turbine, rotor rotates inside the casing. Rotor is extended outside the casing at both front and rear ends. The portion from where the rotor exits the turbine casing is called gland (Figure  16.25). There is chance of steam leakage and atmospheric air ingress to the casing at the front and rear gland respectively. So, it is required to seal this portion to prevent the leakage of steam and atmospheric air ingress. Gland at the front end of the turbine is called front gland and that of rear end is called rear gland. To reduce pressure difference between the atmosphere and the inside casing, sets of labyrinth seals are provided. As discussed earlier, these labyrinth seals cause pressure drop along the rotor. But only labyrinth packing is not sufficient to prevent the leakage of steam or air. So, gland sealing steam is used to prevent the leakage. Low pressure steam is supplied at the final sets of labyrinths. Arrangement is done to vent the excess gland steam. To drain out the condensate produced due to cooling of this gland steam, drains are also provided.

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Figure 16.25  Gland.

16.4.8  Exhaust Hood Exhaust hood of the turbine is a structure that connects the space just after the last stage of the turbine blade to the condenser. It is fastened to the neck of a condenser. An expansion bellow is provided in between to absorb any shock. Exhaust steam from turbine is diffused in this area and canalised to the condenser. It is designed to minimise the pressure loss. One inspection door is provided at the exhaust hood to inspect the condition of blade (last stage) and top portion of the condenser tube. In some turbines, water spray arrangement is provided at the exhaust hood to control the exhaust steam temperature. Condensate of the main condenser pumped by condensate extraction pump (CEP) is sprayed at this area. Instrumentation tapping are provided in this area to measure the exhaust steam pressure and temperature.

16.4.9  Emergency Stop Valve (ESV) Emergency stop valve is a quick operating valve which is normally hydraulically operated. The valve opens hydraulically against a spring force. To close the valve, hydraulic fluid is drained and the valve closes immediately due to the force of spring. This valve is normally fully open or fully close type. As shown in Figure 16.26, the valve cone is operated by a spindle which is connected to a piston. This piston is operated through a spring. To open the valve, hydraulic pressure is applied against the spring. To close the valve, this pressure is released by draining the hydraulic fluid. This valve is a quick closing valve and stops the steam entry into the turbine immediately when it closes.

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Figure 16.26  Emergency stop valve.

In most of the stop valves, a strainer is provided to restrict the entry of any foreign material into the nozzle of turbine. Vent and drain point are provided in the gland area of the stop valve to vent out the leakage steam and to drain out the condensate formed. In some designs, this valve is opened and latched hydraulically. The latch releases when hydraulic pressure drops and the valve closes instantly. In some cases, built-in test facility is provided to test the function of the valve while the turbine is running to ensure the moving mechanism is free and ready to shut off the valve during emergency. Valve body is normally forged from alloy steel or carbon steel as per the steam parameter of turbine. Inlet steam pipeline is fastened to this valve without any piping stress.

16.4.10  Governing Valve and Control Valve Control valve regulates the steam flow to the turbine. This valve is placed inside the steam chest of turbine (Figure 16.27). It is operated by a governing valve which is actuated mostly hydraulically. Operating signal for governing valve is obtained from turbine governing system. In actual practice, combination of control valve and governing valve is known as governing valve. But for understanding, these two are discussed separately.

Figure 16.27  Governing valve and control valve.

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Operating lever of control valve is connected to the governing valve. Multiple valve cones are connected to this lever to control steam entry to the turbine. These valves are placed inside the steam chest of turbine. The valves are fixed to the lever in such a way that a particular valve opens or closes at a particular lever position. Multiple valves make the steam flow control more effective and minimise the throttling loss. Steam requirement varies with the load on turbine. The relation of steam requirement to load is shown in a graph called Willans line of the turbine. Willans line (nearly straight) shows the steam consumption (kilogramme per hour) versus power output (kilowatt) for a steam turbine. Depending upon the steam requirement at different load conditions, different valves open and the steam flows to different nozzle sets of the turbine. Nowadays, mostly, electrohydraulic governing system is used. Electrical signal from the governor is converted to hydraulic pressure in an I/P converter. This hydraulic pressure operates the control valve and hence, the lever of valve sets. In controlled extraction turbine, there are more than one governing valves. In a single extraction, there are two sets of governing valves in HP and LP sections.

16.5  THERMAL EXPANSION OF TURBINE Steam turbine operates at high temperature. During exposure to high temperature, the rotor and casing of the turbine expand. Turbine rotor and casing expand/contract at different rates due to the difference in their masses. Casing wall is thick and its mass is more that of than a rotor, so it expands and contracts at slower rate than a rotor. As the clearance between fixed blade and moving blade inside the turbine is less, so the expansion of casing and rotor is required to be uniform. Otherwise, there is a chance of rubbing of fixed and moving parts of the turbine. Thermal condition in the turbine changes during starting, stopping and load change. Special care is taken for smooth expansion of casing and rotor during this period. During starting, turbine starting curve is followed for the smooth expansion of casing and rotor. Sufficient time is allowed for the expansion of these parts. This is called soaking of turbine. More time is given to bring the turbine into full speed from cold condition. In hot start-up, the turbine is already in hot condition. So, the time requirement is less. A typical turbine start-up curve is shown in Figure 16.28.

Figure 16.28  Turbine start-up curve.

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In most of the cases, the rear side pedestal of turbine and hence, the casing is rigidly fixed to the base plate. But the front side pedestal is fixed in such a way so that it can expand towards the front. Temperature of the rotor varies with the steam flow. So, it is subjected to frequent thermal expansion and contraction and it is faster in comparison to casing. For smooth operation of turbine, it is required to monitor the expansion of casing and rotor. Differential expansion of casing and rotor is measured. Eddy current type measuring probes are normally used to measure the rotor expansion or contraction. The rotor axial thermal growth with respect to turbine foundation is measured. This is the relative measurement of rotor axial thermal growth with respect to casing.

16.6  GLAND SEALING SYSTEM In earlier section, details about the gland is given. Low pressure steam is supplied at the gland area for gland sealing. This steam seals the gland and restricts the high pressure steam leakage from the gland area of front gland and atmospheric air ingress at the rear gland area. Gland steam is charged before rolling of turbine and building vacuum in the condenser. During starting of the turbine, steam from an auxiliary steam source or motive steam is used for gland sealing. Superheated steam at a pressure of about 2 kg/cm2 is maintained at the gland steam header. As shown in Figure 16.29, through control valve CV-A, steam is supplied to the gland seal header. When this valve is opened, steam enters both the glands. Steam can be seen at both the gland vents. Gland drains are kept open to drain out the condensate. During cold condition of turbine, gland is charged slowly by opening CV-A. Through control valve CV-B, the gland steam header pressure is maintained. In case, the header pressure raises, this control valve opens and allows excess steam to the flow to the condenser. A safety valve is provided at the steam header to protect the gland from excess steam pressure due to failure of any control valve.

Figure 16.29  Gland sealing system.

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Once the high pressure steam is admitted into turbine, it starts leaking through the front gland and flows in backward direction and increases the header pressure. In this condition, control valve CV-A closes automatically. Leakage steam from front gland is used to maintain the header pressure and hence, the supply steam to the rear gland. Both control valves CV-A and CV-B are kept in automode. In most cases, to utilise leak off steam of both the glands, gland seal steam of front and rear gland is not vented to the atmosphere. This is collected at gland seal condenser. The main condensate from CEP is passed through this condenser which condenses the gland steam here and heat of that steam is utilised to raise the temperature of the main condensate. Condensate produced here is drained to the main condenser (Figure 16.30).

Figure 16.30  Gland steam ejector.

First, the auxiliary steam is charged in the gland seal ejector. Then, the gland seal header is charged. This arrangement minimises the water loss due to gland vent and its heat is utilised in the gland seal condenser to heat the condensate and hence, the plant efficiency increases. In multicasing turbine, gland sealing system is divided into two sections. First section supplies steam to HP/IP turbine gland and the second section supplies steam to LP turbine gland. During start-up/shutdown and low load condition, auxiliary steam is used. During running condition, leakage steam from HP/IP turbine gland is used to seal the glands of LP turbine. Low temperature steam is used at LP gland. So, LP desuperheater is used to control the temperature of this steam.

16.7  BARRING DEVICE In a turbine, the mass of rotor is more. It is subjected to high temperature also. So, it is not advisable to keep the rotor at standstill position after the stoppage of turbine. It is required to rotate the turbine shaft at low speed continuously till the turbine is cooled. Otherwise, due to heavy mass, shaft may deform or sagging may take place. In cold condition also, the shaft is required to be rotated intermediately to avoid the rotor deformation. To avoid sagging or deformation, barring device is provided in the turbine to rotate the rotor at slow speed. In some turbines, this is done by a motor with suitable reducing gear at

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shaft. In some case, shaft is rotated through hydraulic arrangement. Hand barring arrangement is also provided to rotate the shaft in emergency in case of failure of above arrangement. In the motor-driven barring device, clutch provision is made so that the barring device can be declutched automatically above certain speed during the starting of a turbine. It is to be ensured that the lubrication oil is available to all the bearings during barring operation. Interlock is provided to stop barring operation in case of failure of lubrication oil supply. In bigger size turbines, high pressure jacking oil is applied at both end of the shaft to lift the rotor slightly to avoid metal to metal contact during starting. Jacking oil is required during starting only.

16.8  Governing system Governing system is a system of a turbine to control the speed automatically. It controls the energy input (steam) to the turbine. The Main function of a governor is to adjust the steam entry into turbine to maintain the speed at a desired level. Indirectly, a governor also controls load, exhaust steam pressure, etc. Desirable characteristics of a good governing system are given below:

• • • •

Quick response to small speed change Adjust control valve with minimum overshoot Have sufficient power to overcome the back force of control valve Very little speed fluctuation under constant load and steam condition

The function of a governor can be understood from the example discussed here. Suppose a driver is driving a car on a plain road (Figure 16.31). His speed limit is say 50 km/h. From the speedometer of the car, he observes the actual speed of car and adjust the accelerator to match the speed of car to 50 km/h. In case, speed raises, he lowers the accelerator and when speed lowers, he increases the accelerator. When speed matches to 50 km/h, he holds the accelerator in steady position.

Figure 16.31  Car on plain road.

Suppose at the same accelerator position, the car is required to go up on a hilly road (Figure 16.32). Load on the car increases, so speed of the car decreases. Driver observes speed from the speedometer and increases accelerator to achieve the desired speed.

Figure 16.32  Car moving up.

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Suppose, again in the same accelerator position, the car is required to come down on the hilly road (Figure 16.33).

Figure 16.33  Car moving down.

Load on the car decreases. So, speed of the car increases at that particular accelerator position. Driver has to decrease the accelerator to achieve the desired speed. From the above example, it can be concluded that

• • • • •

Set speed of car is 50 km/hr. Speed of car varies according to the load. Actual speed is measured in speedometer. Set speed and actual speed are compared by the driver. In case there is a difference, accelerator is adjusted to control the fuel into the engine of car. • Driver of the car performs the above function.

In governing system of the turbine, same principle is applied. Driver of the car can be compared as a governor of the turbine. Speed of the turbine is set at the governor. Actual speed is measured and compared by the governor. Governor gives signal to the governing valve to adjust steam input to the turbine to achieve the set speed. This function takes place in governing system automatically through the closed loop system as shown in Figure 16.34.

Figure 16.34  Turbine governing system.

Governing system of the turbine consists of the following:

• • • •

Speed sensing device Governor Amplifier or converter Governing valve and control valve

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The main required features of any governing system are given below:

• It should have better steady state stability so that the variation in speed or fluctuation from the speed setting under steadystate operating condition is very small. • It must have less response time, i.e., to sense the deviation of speed and bring it back to the normal level within the shortest possible time. • It should have better stability to control the system within the shortest time without oscillation.

Following are the different types of governors depending upon the mode of their operation.

• Mechanical governor • Hydraulic governor • Electrohydraulic governor

16.8.1  Mechanical Governor Mechanical governor is very old type governor. Fly ball type governor was used to control the turbine speed. In this, two fly balls are attached into rotary shaft of a turbine. When speed of the shaft increases due to centrifugal force, the balls try to move up and the lever attached closes the control valve and the steam entering the turbine reduces (Figure 16.35).

Figure 16.35  Mechanical governor.

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16.8.2  Hydraulic Governor In this system, governor operation is totally hydraulic. Hydraulic oil is obtained from the main lubrication oil system of the turbine. One oil pump is mounted at the front rotor end of the turbine which pumps the primary oil. Pressure of this primary oil depends upon speed of the turbine. According to this primary oil pressure, secondary oil pressure varies which changes the position of control valve. This governing system is having a speed setting arrangement. SR IV type governor made by Woodward is the example of this type of governor.

16.8.3  Electrohydraulic Governor This type of governing system is widely used nowadays. The governor is having following components:

• • • • •

Speed sensor–magnetic pickup unit Microprocessor based electronic governor (to generate electronic signal) I/P converter (to convert electrical signal into hydraulic signal) Governing valve Control valve

Arrangement of this governing system is shown in Figure 16.36.

Figure 16.36  Electrohydraulic governer.

Speed Sensor–Magnetic Pickup Unit (MPU) Magnetic pickup unit (MPU) is used to measure the actual speed of a turbine. Output of this sensor is directly proportional to the speed of turbine. A coil is wrapped around the pole piece of a permanent magnet (Figure 16.37). When any magnetic material passes through the magnetic end of magnetic pickup unit (MPU), a voltage is generated. This sensor is fixed in an area where a gear attached to the turbine rotor rotates radially. Air gap between MPU and the gear is kept very small. Frequency of the voltage generated is proportional to the speed of the gear teeth and hence, to the speed of the rotor too. Output of MPU is connected to the electronic governor. Normally, two MPUs are used to measure the

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Figure 16.37  Magnetic pickup unit (MPU).

speed. The governor generates a trip signal to stop the turbine automatically, if the signal is not obtained from any of these sensors. Microprocessor-based Electronic Governor This is a microprocessor-based electronic controller having a lot of in-built facilities. Turbine speed can be set. Programming can be made for automatic start-up keeping in view the start-up curve, critical band avoidance of the turbine as per the turbine design. It has three proportional integral derivative (PID) controllers—speed controller, auxiliary controller and cascade controller. Also, limiter function can be programmed. In auxiliary control mode, it can control generator power, exhaust pressure, inlet pressure, plant import/export level, etc. Generator breaker and tie breaker contacts are configured to change the governor from speed control mode to auxiliary mode or vice versa. It has overspeed set point and mechanical overspeed test facility. 4 mA–20 mA electronic signal is obtained from this governor. Woodward 505 is an example of this type of microprocessor-based governor, widely used in the turbine governing system. This governor can be connected to the plant distributed control system (DCS) easily. Woodward 505 governor has the following features:

• • • • • • • • •

Critical speed avoidance Autostart sequence Valve limiter Password protection in programming mode First out trip indication Zero speed detector Peak speed recording Remote and front panel set point Front panel display

Depending upon the set value and actual value of the parameter to be controlled, an electronic signal is generated. This signal is used to adjust the control valve position. Various inputs as mentioned below are required in an electronic governor:

• • • •

Actual speed measurement Actual power generated by the generator Generator breaker contact Utility or tiebreaker contact

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Breaker contact provides information to the governor about solo or parallel mode of operation of the generator. Accordingly, a governor acts as speed controller or auxiliary controller. Speed and auxiliary controller set points can also be changed from the remote control desk. An electronic governor also displays various parameters that are as follows:

• • • • • • • • • • • •

Speed set point Actual speed KW setting Actual KW Output signal Idle/rated status Autostart timer time remaining Valve limiter Actuator demand Controlling parameter Peak speed Last trip

In some electronic governing system, instead of separate governor, the governing system program is loaded on the main plant DCS with suitable operator interface. A governor program runs in conjunction with the plant control program. All the facilities like autostart mode, critical speed avoidance, etc. are available. Programming can be done to follow the turbine start-up curve and other requirements. Programming of electronic governor:  Programming of the governor is done as per the requirement of plant operating condition and turbine manufacturer. A governor generates corrective signal according to the preloaded program. Programming is done to get the desired starting curve and to avoid critical speed band for autostart mode of the turbine. Valve limiter and overspeed limit is also programmed for the safety of machine. PID values of different controllers are set during programming. Following important informations are required for the programming of a governor:

• • • • • • • • • • • • • •

Mode of start Rate of speed raise to the minimum idle speed Idle speed Idle period Cold start time Hot start time Teeth seen by MPU Gear ratio Maximum speed limit Maximum governing speed Minimum governing speed Critical speed Critical speed rate Extraction or admission

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Programming is done during turbine stop condition. For safety, programming mode is password protected. Governor for extraction turbine:  In an extraction turbine, two electronic signals are obtained from the electronic governor. These two signals are used in two different I/P converters to regulate the control valve of HP and LP side, as shown in Figure 16.38.

Figure 16.38  Governing system of controlled extraction turbine.

I/P Converter In this converter, electronic signal obtained from the electronic governor is converted into hydraulic signal. Trip oil from the main control oil system is used in this converter. The electronic signal of the governor throttles drain of the converter to build up the secondary oil pressure. At 4 mA signal, drain of the converter is opened fully. When signal rises, it throttles the drain, so secondary oil pressure increases. This secondary oil is used to adjust the actuator position and hence, the control valve too. Normally, Woodward made CPC or Voith made I/P converters are used for this purpose. Actuator or Servomotor (Governing Valve) Actuator is a hydraulic power cylinder. The piston of this cylinder moves upward or downward as per the hydraulic signal obtained from I/P converter. This piston is connected to the arm of the turbine control valve. The function of the turbine control valve is already discussed in the earlier section.

16.9  CONTROL OIL SYSTEM Control oil is obtained from the main lubrication oil system of a turbine. Oil from the main oil pump is used for this purpose. But this oil is not filtered or cooled at the main oil filter or oil cooler. Distribution of this oil system is shown in Figure 16.39.

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Figure 16.39  Control oil system.

16.10  TURBINE PROTECTION SYSTEM Turbine is a very critical machine in any power plant. So, protection of this machine is an important consideration. There are different protection arrangements. Some of the protection systems are incorporated in the main plant automation system. Any abnormal operating condition produces a trip signal and makes the set shutdown. Apart from these protections, there are some in-built mechanical protection systems in the turbine which stop the turbine in case of any deviation in the turbine operating condition. The main in-built protection systems of the turbine are as follows:

• Overspeed • Excess axial movement of the turbine shaft • Low vacuum

Overspeed Protection Turbine overspeed protection stops the turbine in case the speed of the turbine becomes abnormally high. A mechanical overspeed trip arrangement is provided at the turbine shaft (Figure 16.40). Trip oil of the governing system is held at this overspeed protection device. In case of overspeed of turbine, a pin which is fixed to the shaft of the turbine comes out due to centrifugal force

Figure 16.40  Mechanical overspeed protection.

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and hits the lever of the trip device which holds this trip oil. Trip oil is drained. In the absence of trip oil (which is used to keep the stop valve in open condition), the stop valve closes and the turbine stops. The revolution per minute (RPM) at which this pin comes out can be adjusted by adjusting a screw which holds this pin. Excess Axial Movement Protection Excess axial movement of turbine shaft in not desirable, as closely spaced rotating and fixed parts may come in contact and damage the turbine internals. Axial shift at either direction is restricted. The trip lever of the trip device (discussed earlier) is operated by the two projected rings of the turbine shaft (collar) (Figure 16.41). When there is an excessive shift of the shaft in either direction, any one of this collar operates the trip lever and drains out the trip oil to stop the turbine.

Figure 16.41  Excess axial shift protection.

Low Vacuum Protection Low vacuum in the condenser creates back pressure on the turbine blades. So, this protection is essential for the safety of turbine. Nowadays, low vacuum tripping is done at plant automation system through tripping contact of high pressure limit switch or transmitter. But in some turbines, this is done mechanically. Trip oil is held in a low vacuum device located near the condenser neck. Trip oil is held with the help of a piston which is closed when there is a vacuum upto the desired level inside the condenser. When vacuum drops, this piston move downward and drains out trip oil to trip the turbine.

16.11  TURBOVISORY Turbovisory system is the monitoring system of a turbine. It supervises the condition of turbine and informs to an operating person. It also ensures that the monitored parameter does not exceed beyond the maximum permissible limit. Before that, the system stops the turbine. In turbovisory system, following important parameters are monitored:

• Vibration • Bearing temperature

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• Eccentricity • Axial position These parameters indicate the condition of a turbine during operation.

Vibration Vibration of the turbine indicates the condition of turbine in running mode. A rotor rotates at high speed through the sets of journal bearings. There is little clearance in between the rotating and stationary parts. Due to misalignment, disturbance in balancing, rubbing of moving part, etc., the rotor tends to vibrate. This vibration is supposed to be within the permissible limit. Excessive vibration may damage the turbine and lead to an extensive maintenance. To measure vibration, vibration probes are fixed at the bearing housing through a suitable fixing arrangement (Figure 16.42). Normally, two vibration probes are placed 90° apart to measure the vibration. Probes are fixed at both front and rear ends. Also, vibration probes are fixed to measure the shaft vibration of gearbox and generator rotor.

Figure 16.42  Vibration probe.

During standstill condition of turbine, these probes are fixed so that proper gap can be maintained between the probe tip and the rotor. Vibration probes act on eddy current generation principle. Voltage generated in the probe is directly proportional to the gap between the probe and the rotor. This measured voltage is scaled down to measure the vibration of rotor. Limits are set suitably to generate the alarm and trip signal. Alarm signal is generated if the value exceeds alarm level set point. If the vibration increases further and exceeds the trip limit, then the trip signal is generated and turbine trips. Bearing Temperature Due to friction, heat is generated in journal bearing which is cooled with the help of lubricating oil. At higher temperature, babbiting material of the bearing can damage. So, it is required to keep the bearing temperature within the safe limit. For this, temperature of bearing is monitored continuously. RTDs are embedded in the journal and thrust bearings and placed just below the babbiting material to get the actual reading of babbiting material. Through RTDs, bearing temperature of all the journal and thrust bearings are measured. Like vibration, limits are set for bearing temperature to generate the alarm and trip signal.

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During replacement of bearing, special care is taken so that the RTDs are not disturbed or leads are not opened. If the RTD is damaged, it will not be possible to measure the bearing temperature and hence, it will be dangerous to run the turbine. Eccentricity The measurement of eccentricity plays a vital role in the turbine supervision system. Eccentricity is the measurement of rotor bow. Eccentricity of rotor may happen due to the following reasons:

• Fixed mechanical bow • Temporary thermal bow • Gravity bow

Temporary thermal bow and gravity bow may be caused by sudden trip of turbine and failure or non-availability of barring device during this period. It may happen in bigger turbines where the mass of rotor is more. Figure 16.43 shows the process of eccentricity.

Figure 16.43  Eccentricity.

To measure eccentricity, eddy current probes are used. These probes are normally placed away from the bearing location (Figure 16.44).

Figure 16.44  Location of probe for eccentricity measurement.

Axial Position Axial position is required to be measured to know the exact position of the rotor with respect to casing. For this, eddy current probe is used. This probe is placed in axial direction to the rotor. When rotor moves towards the probe, eddy current signal is more and when it moves away, the signal is weak. Calibration is made in such a way so that when the rotor is at exact centre with respect to casing, the reading indicates zero. When it moves towards the front, it shows positive reading and when it moves away, it shows negative reading. Like vibration and temperature, maximum permissible limit is determined to generate the alarm and trip signal.

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16.12  TURBINE CASING DRAIN SYSTEM Steam is expanded at various stages of fixed and moving blades. So, there is a chance of condensation of steam, particularly during starting and low load condition. Accumulation of condensate inside a turbine can damage the turbine. It is required to drain out this condensate. For this, drain points are provided at the turbine lower casing. Also, drain points are provided at the gland portion and emergency stop valve. All these drains are connected to the condenser. Orifice of suitable size is placed at the drains to avoid steam flow in these drains.

16.13  EXTRACTION SYSTEM In an extraction turbine, some amount of steam is extracted from the turbine from certain stage of blades after expansion. There are two types of extraction that are as follows:

• Uncontrolled extraction • Controlled extraction

Uncontrolled Extraction As discussed earlier, extraction steam is used at feedwater heater to increase the feedwater temperature. This is called regenerative cycle. Steam temperature and pressure at different extraction points are different. The steam extracted from the front portion has more temperature and pressure as compared to the steam extracted from the exhaust end. This extracted steam is used for feedwater heating at HP and LP heaters and deaerator. Non-return valve is provided at each extraction line to avoid back flow of steam for the safety of turbine. Quantity of steam extraction is not controllable in this case. A fixed quantity of steam can be extracted after certain load on the turbine. Figure 16.45 shows the uncontrolled extraction.

Figure 16.45  Uncontrolled extraction.

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Controlled Extraction Controlled extraction type of turbine is used at process industries where the steam is extracted from the turbine after certain stage at a desired pressure and temperature. The quantity of steam can be adjusted as per the requirement in this case. Single extraction turbine has two stage, i.e., HP stage and LP stage. Two sets of governing valves are there. The arrangement is like two turbines connected in series (Figure 16.46). Total work done is the sum of work done at HP and LP stage.

Figure 16.46  Controlled extraction.

To get more extraction steam, HP control valve is opened more and more steam enters the HP stage. So, more work is done at HP stage. To maintain same mechanical output, LP control valve is throttled accordingly. Total work done in this case remains the same and extra steam is available at extraction. To reduce the extraction, HP control vale is closed and LP control valve is opened more. To increase the mechanical output, both HP and LP control valves are opened. Opening and closing of these control valves are done through governing system. Three sets of control valve are used to get two-controlled extraction steam at different temperature and pressure. Arrangement of two-extraction system is shown in Figure 16.47. It is like three turbines connected in series.

Figure 16.47  Two-controlled extraction.

In controlled extraction turbine, quick acting non-return valves (QCNRV) are provided to avoid any back flow of steam into the turbine.

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In bigger size turbines, steam is extracted from HP turbine and further heat is added to it at the boiler and reheater. This reheated steam is again used at LP turbine. This is called reheat cycle.

16.14  FEEDWATER HEATER A feedwater heater is a heat exchanger used to preheat the boiler feedwater by means of steam extracted (or bleed) from the steam turbine. Preheated of feedwater improves the efficiency of system. Feedwater heater increases the feedwater temperature upto saturation temperature very gradually. These heaters are classified as closed and open heaters. Closed heaters are mostly used since the tube side fluid remains enclosed by the tubes and does not mix with the condensate. Heat transfer within the vessel takes place by convection and condensation. After heat transfer, the extracted steam is condensed. This condensate is sent to the deaerator or condenser. Deaerator is an example of open heater. Feedwater heaters are of standard shell and tube configuration. Mostly, U-tubes are used in feedwater heater, as they are suitable for thermal expansion during operation. Heaters are of horizontal configuration. These are most stable for level control. Feedwater heaters are classified as per their pressure design. These are as follows:

• Low pressure (LP) heater • High pressure (HP) heater

Low Pressure (LP) Heater LP heater is located between the condensate pump and the boiler feed pump. Extracted steam from the low pressure stage of turbine is used here. High Pressure (HP) Heater HP heater is located between the boiler feed pump and the boiler. Typically, extracted steam from the high pressure stage of turbine is used here.

16.15  LARGE CAPACITY STEAM TURBINE Steam flow is more in large capacity steam turbines used at fossil fuel-fired power generating stations. The parameters of steam (pressure and temperature) are also kept high. High pressure steam cannot be expanded to exhaust the pressure at one go. We know moisture contents at exhaust increase in this case. To avoid this problem, reheating is required. Also, the volume of steam increases so many times after the expansion. To keep the steam velocity constant through the turbine, the flow area is required to be increased proportionately. This results in very large diameter casings and excessively long turbine blades at the exit. It is essential to control the high axial thrust in a large size turbine. For initial heating of feedwater, series of regenerative feedwater heaters are required. To avoid these complexity, following features are added in the large size steam turbines:

• • • •

Reheating Multicasing Multiflow Feedwater heating

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16.15.1  Reheat Turbine As discussed earlier, when high pressure steam is expanded in a turbine, moisture contents of exhaust steam increase and create problem at the exit end blades. So, reheat type turbine is most commonly used for large capacity turbine using high pressure steam. Steam after expanding at HP turbine is sent to the boiler for further heat addition or reheat. This steam is called cold reheat (CRH). Cold reheat is heated at the reheater of a boiler. The reheated steam, called hot reheat (HRH), is then sent to LP turbine where it expands further. Single and double reheat turbines (Figure 16.48) are commonly used for power generation. HP and LP turbines are either of single or double casing type.

Figure 16.48  (a) Single reheat turbine and (b) Double reheat turbine.

During start-up, shutdown and load fluctuations in a power plant, the boiler and steam turbine are required to be operated as per their individual safe limits. For this, turbine bypass system is provided as shown in Figure 16.49. Turbine bypass system helps in reducing the start-up time by controlling the boiler pressure and temperature.

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Figure 16.49  Turbine bypass system.

Turbine bypass system consists of HP and LP turbine bypass. By allowing the steam flow through HP bypass, overheating of reheater tube bank is avoided during start-up and low load conditions. Steam is then routed through LP turbine bypass to the condenser. This arrangement also ensures that the boiler can remain in operation during load rejection. Safety valve lifting due to overpressure can be avoided and other equipments may be kept running, allowing immediate reloading of the turbine. The main functions of turbine bypass system are discussed below:

• • • • • •

To maintain the minimum flow through superheater during start-up and low load conditions To maintain the required minimum flow through the reheater To increase the steam pressure and temperature gradually during boiler start-up To limit the reheat steam pressure drop To dump steam which is not used in steam turbine during load rejection or shutdown To reduce DM water loss

Superheated steam pressure and temperature is much higher than that of cold reheat. So, HP steam pressure is reduced to match the cold reheat pressure and temperature is reduced to match the cold reheat temperature. Like this, pressure and temperature of hot reheat is controlled while dumping in the condenser. For this, pressure reducing and desuperheating (PRDS) system is installed.

16.15.2  Multicasing Turbine Normally, the turbine casing and shafts of a large size steam turbine are arranged in three different styles as mentioned below:

• Single casing • Tandem compound (TC) type • Cross compound (CC) type

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Single casing turbine is the simplest type where a single casing and shaft is coupled to a generator. This type of turbine is already discussed. Large steam turbine is split into HP, IP and LP sections. These sections are accommodated in two or more casings. It is required to connect these individual sections to drive the generator. In tandem compound turbines, two or more casings are joined end to end to drive a single generator, as shown in Figure 16.50. Two or more turbines are connected in series to extract work from a single source of steam. The steam is partially expanded in the high pressure casing and then exhausted to the low pressure casing. A crossover pipe sends steam from intermediate pressure turbine exhaust to the low pressure turbine inlet.

Figure 16.50  Tandem compound turbine

In a cross compound turbine, two or more shafts drive two or more generators, as shown in Figure 16.51.

Figure 16.51  Cross compound turbine.

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The main advantages of compound turbine are as follows:

• The size of casing reduces. • Highest pressure can be confined to the smaller casing which is stronger and made of more expensive material. • Flow in the low pressure casing can be divided for equalising the end thrusts.

16.15.3  Multiflow Turbine If the steam flows only in one direction, then the turbine is called a singleflow turbine. A singleflow type turbine develops high axial thrust. In case of large capacity turbine, it is difficult to control this axial thrust. Another technique is used in large size steam turbines for this. The flow of the steam inside the turbine is split into two directions. Steam from the high pressure turbine enters the centre of the low pressure turbine and flows outward in both directions through two identical sets of turbine staging. Axial thrust is balanced and is very less than a singleflow turbine designed for the same capacity. Increase of steam volume is more at LP section of turbine. A single flow LP turbine would be huge to handle this steam. To limit the diameter, normally double flow method is adopted in LP turbines. This arrangement also limits the centrifugal forces. Figure 16.52 shows a single flow and a double flow turbine.

Figure 16.52  (a) Single flow turbine and (b) Double flow turbine.

Depending upon the design variations, turbine configuration varies from manufacturer to manufacturer. A 500 MW single reheat, double casing, double flow, tandem compound turbine is shown in Figure 16.53.

Figure 16.53  500 MW single reheat, double casing, double flow, tandem compounding turbine.

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16.15.4  Feedwater Heating For increasing the efficiency of Rankine cycle, regenerative cycle is adopted. In large size turbines, a number of LP and HP heaters are used for this. As discussed earlier, feedwater is heated before entering the boiler by using extraction steam from high, intermediate and low pressure sections of the steam turbine. LP heaters use extraction steam from the low pressure turbine. Series of LP heaters are located after the condensate extraction pump. The condensate is routed through these LP heaters to the deaerator. from deaerator, feedwater is sent to the boiler through series of HP heaters with the help of boiler feed pump. Extraction steam from high and intermediate pressure turbines is used at high pressure heaters. Non-return valve (NRV) is installed at the turbine extraction line. This valve permits the flow of extraction steam in the outgoing direction and restrict the flow into the turbine when turbine extraction pressure is lower than the line pressure. The valve is spring-loaded with an air or hydraulically assisted actuator. Malfunctioning of extraction NRV can cause severe damage to the turbine. Cascading heater arrangement is most commonly used in thermal power plants. LP and HP heater arrangement of a 500 MW double casing, double flow, tandem compound turbine is shown in Figure 16.54.

Figure 16.54  Steam and water circuit of a 500 MW turbine set.

Rankine cycle of the above turbine set is shown in Figure 16.55. The condensate formed from the extracted steam after heating action is drained to the downstream heater. The condensate level of heater is maintained through a drain control valve.

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Figure 16.55  Actual Rankine cycle of a 500 MW turbine set.

An emergency heater drain valve is provided to use only during the high condensate level condition. Through this valve, condensate is drained directly to the condenser or flash tank. Steam and condensate arrangement in a feedwater heater is shown in Figure 16.56.

Figure 16.56  Steam and condensate connections in feedwater heater.

EXERCISES

1. What are the two basic types of turbines? 2. Why is compounding done in a turbine?

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3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 21. 22. 23. 24. 25. 26. 27. 28. 29. 30. 31. 32. 33. 34. 35. 36. 37. 38. 39. 40.

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What is the difference between pressure compounding and velocity compounding? What is a reaction turbine? What is the difference between partial condensing turbine and condensing turbine? What is parting plane? Where is the throttle or control valve of the turbine located? What is Willans line of a turbine? What arrangement is done for the expansion of turbine? Why are casing drains provided? Where is the thrust collar provided and why? How is the axial thrust controlled? What is a balancing piston? How are moving blades fixed at the rotor? Why does the size of blade increase gradually towards the exhaust end? Why is the erosion noticed at the last stage blades? Why is shrouding provided on the rotating blades of a steam turbine? Where is the lancing wire used? What is the profile of a blade? What is diaphragm of a steam turbine? What is labyrinth and why is it used? What is interstage sealing and why is it required? What is gland? Why is gland sealing required? What is the function of oil in journal bearing? Why is soft metal or babbit used in journal bearing? What is the main constituent of babbit material? How is the bearing temperature measured? What is the function of thrust bearing? What is gland and why is gland sealing required? What is the function of emergency stop valve and why is steam strainer used? How is the control vale operated? Why is multiple control valve arrangement made and how is it achieved? What is socking of turbine and why is it required? Why is an auxiliary steam used at the gland of turbine? Why is a safety valve provided at the gland steam header? From where this steam is obtained during starting and running condition of a turbine? Why is the gland steam condenser provided? What is barring device and why is it provided? What is the function of jacking oil? What is the main function of a governing system? What is magnetic pickup unit (MPU)?

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41. 42. 43. 44.



45. 46. 47. 48. 49. 50.



51. 52. 53. 54. 55.

Why is breaker contact used in a governing system? What is turbovisory system? How are RTDs fixed into the bearing and where are these placed? What is the difference between controlled extraction system and uncontrolled extraction system? Why are feedwater heaters provided? What is the difference between LP heater and HP heater? Define cold reheat and hot reheat. What are the main functions of turbine bypass system? Why is PRDS required in a turbine bypass system? What is the difference between tandem compound (TC type) turbine and cross compound (CC type) turbine? What are the advantages of multicasing turbine? What is crossover pipe? What is the main advantage of multiflow turbine? Why is NRV provided at the heater extraction steam line? Where is the condensate formed at the heaters drained during normal and abnormal operating conditions?

Chapter

17

Auxiliary System of Steam Turbine

17.1  INTRODUCTION Other than turbine, there are other associated systems in a power plant. These systems are required for running of a turbine. Most of the important components and systems of turbine have been discussed in Chapter 16. Here, we will discuss about auxiliary system which helps to run the turbine. Each system has its own importance and cannot be left alone. Like various systems of boiler, turbine auxiliary systems are discussed in this chapter. This will give a clear idea about functioning of steam turbine as a whole. Some of the important auxiliary systems are as follows:

• • • • • •

Oil system Condensate system Gland sealing system Ejector and vacuum system Cooling water system Condenser

17.2  OIL SYSTEM Oil system of the turbine is an important system. Lubricating oil is supplied to the bearings and used for governing of turbine. The main function of lubricating oil is to

• • • •

Lubricate the bearings Cool bearings Flush out metallic debris from bearings Control speed of the turbine (governing oil)

Heavy shaft of a turbine is supported by journal bearings on a cushion of thin oil film. So, we can understand the importance of lubrication oil. It is the lifeblood of a turbine. Turbine oil family is known as rust and oxidation (R and O) inhibited oils. It is formulated by highly refined or hydro processed petroleum base oil of usually ISO VG 32, 46 or 347

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56 grades. 98% of the oil comprises of API Group II base oil. Remaining 2% are additives like antioxidant, rust inhibiter, corrosion inhibiter, defoamer and demulsifier (to increase water separation property). Oil is subjected to work under higher temperature range. So, oxidation and aging takes place. Oxidation produces organic acids which increase the total acid number (TAN). As oil degrades, its average molecular weight goes up and the viscosity increases. This oil should be free from acid, water, suspended matter and other impurities. This oil is used for lubrication of bearings and gearbox. Some part of this oil is used for governing of turbine. The main components of lubricating oil system are as follows:

• • • • • • •

Oil tank Oil pumps Oil cooler Oil filter Oil centrifuge Oil overhead tank Accumulators

A complete lube oil circuit of a steam turbine is shown in Figure 17.1.

Figure 17.1  Lube oil circuit.

17.2.1  Oil Tank Total oil for the system is stored in this tank. The tank has an adequate capacity to hold sufficient oil during running and stop condition. The tank base is made sloped to one side so

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that the sediments in oil can be collected in the lower area and can be drained out by opening the drain valve. The tank has a level measurement facility to give an alarm for low oil level. Also, a level glass is provided to find out the tank level at any instant. Suitable tapings are provided to facilitate oil suction for oil pumps, draining of return oil from bearings and governing system, connection for oil centrifuge, fill up of fresh oil, etc. Oil mist fan is provided on the tank to vent out any oil vapour and keep the tank slightly below the atmospheric pressure.

17.2.2  Oil Pump To pump oil from the oil tank to various lubrication points and controlling purpose, oil pumps are provided. Normally, three pumps are provided. These pumps are as follows:

• Main oil pump (MOP) • Auxiliary oil pump (AOP) • Emergency oil pump (EOP)

Main Oil Pump (MOP) Main oil pump (MOP) is used during the running of turbine. In some turbines, the main oil pump (MOP) is coupled mechanically to the main shaft of turbine. This is a gear pump which ensures oil supply to the bearings as the long as the shaft rotates. This is useful for safe costing down of turbine in case of failure of emergency oil pump. When turbine is stopped or trips, rotor does not come to standstill immediately from full speed. A rotor requires some time to come standstill, as the mass of the rotating part is high. Slow deacceleration of turbine speed is called coasting down. Failure of oil supply to bearings during coasting down is dangerous. This may damage bearings. A mechanically coupled main oil pump is a safer arrangement from this point of view. In some cases, main oil pump is an ordinary electric motor-driven pump like auxiliary oil pump. In this case, for safe costing down, overhead oil tank provision is made to ensure continuous oil supply to the bearings in case of failure of emergency oil pump. Auxiliary Oil Pump (AOP) Auxiliary oil pump (AOP) is a motor-driven pump. During starting of turbine (in case of mechanically coupled MOP), oil is supplied through AOP. Once the turbine reaches full speed and oil pressure is developed by MOP, AOP is stopped. In case of motor-driven MOP, either AOP or MOP can be used interchangeably. In this case, one pump runs and other one is kept as standby. Emergency Oil Pump (EOP) Emergency oil pump (EOP) is driven by a DC motor. In case of blackout or non-availability of either MOP or AOP, this pump is started automatically to continue the oil supply to the bearings. Normally, this pump is a low capacity pump. So, it supplies oil only for bearing lubrication. Governing oil is not supplied by this pump.

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This pump is required to run during emergency (blackout situation). So, it should be kept available, once the turbine is in operation.

17.2.3  Oil Cooler Normally, two oil coolers of 100% capacity each are provided to cool down the entire oil supplied to the turbine bearings, gearbox and generator bearings for lubrication. The governing oil is not cooled at oil cooler. This oil is taken out before oil cooler. One cooler is put on line and another one is kept as standby. Online changeover facility is provided to take the standby cooler into service while the turbine is running without interruption of oil supply. Before changeover, it is to be ensured that the standby cooler is filled with oil and the air is vented out properly. Otherwise, there will be an air lock and the oil supply to the bearings may get interrupted. Oil cooler is a shell and tube type heat exchanger. Cooling water flows inside the tube bundle and oil flows at the shell side. Cooling water for oil cooler is obtained from the main cooling water system of power plant. Regulating valves are provided at the inlet and outlet of the cooling water supply line. To increase or decrease the oil temperature, cooling water flow is decreased or increased respectively through these regulating valves. The cooling water outlet valve is always regulated to vary the flow of cooling water. In any case, cooling water inlet valve is not to be throttled, as sufficient cooling water is not available inside the tube and the tube may be damaged. Drain point is provided at the cooler to drain out the settled sediment at the bottom of the cooler.

17.2.4  Oil Filter Oil coming out from the cooler is passed through an oil filter to remove any contaminated particle or debris. Filter is normally basket type with removable filter cartridge. Like cooler, there are two filters of 100% capacity each with suitable online changeover arrangement. The oil is filtered upto 20µ–25µ level on these filters before circulating in bearings. Differential pressure across the filter is measured which indicates the chocking condition of filter cartridge. If differential pressure is more, it indicates that the filter is chocked and needs cleaning. Before changeover of oil filter while the turbine is in operation, it is to be ensured that the standby filter is completely filled and no air is trapped inside. The filter cartridge of standby filter is to be kept clean always so that at any moment, this can be made on line, if required.

17.2.5  Oil Centrifuge Oil centrifuge is a machine used to keep lubricating oil clean. This is a separator to separate the liquid mixture having different density or to separate heavier solid particles from the liquid. There is a possibility of leakage of steam into the lubricating oil system at bearings due to the failure of labyrinths. Also, there is a chance of mixing of cooling water in the lubricating



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oil at oil cooler in case of puncture of any tube. If there is a puncture of tube in the running cooler, then water is not mixed with the oil, rather than oil is mixed with the cooling water, as the pressure of oil is more than that of cooling water. But at the standby cooler, leaking tube may lead to the mixing of water into oil. Oil is contaminated with heavier metallic debris, dust and dirt. So, it is required to separate water and solid particles from the oil to keep it clean and increase its life. Centrifuge is a machine which separate water and solid particles from the oil. This is achieved by centrifugal force of a high speed rotating bowl inside the separator. Due to centrifugal force, heavier particles are displaced towards the outer periphery of the bowl and the lighter oil is displaced towards centre of the bowl where it is collected and sent back to the main oil tank. Centrifuge is connected to the main oil tank, as shown in Figure 17.2. Inlet of the centrifuge is connected to the lowest slope of the tank so that dirty oil can be collected for cleaning. Pump of the centrifuge pumps dirty oil and circulates it through an indirect heater. Hot water is used to heat the oil at indirect heater. Also, heater can be bypassed, if required. Oil is passed to the rotating bowl which rotates at high speed.

Figure 17.2  Oil centrifuge.

Bowl of oil centrifuge can be adjusted to perform the following two functions: Purification:  In purification mode, centrifuge is used to separate different density liquid mixtures (oil and water). Simultaneously, this can remove solid particles also. For this purpose, water seal is provided to prevent light density oil to come to the water outlet side. Heavier solid particles separated are collected at the outer surface of the bowl which can be cleaned regularly. Clarification:  In clarification mode, only solid particles are removed. Rotating bowl is adjusted for this. Removed sludge from the oil is collected at the outer periphery of the bowl which is cleaned regularly. Sealing water is not required in this mode of operation. Through centrifuge, oil is circulated to the oil tank again. So, centrifuge can be used to clean certain amount of oil, whether turbine is in operation or not. Centrifuge is having a top up connection through which fresh oil can be transferred through centrifuge to the main oil tank.

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17.2.6  Overhead Tank Lube oil overhead tank is used for the safety of turbine. A tank is placed at a height and oil is always filled in this tank. In case of failure of oil pumps, automatically, the oil from this tank starts flowing by gravity and in this way, the oil is supplied to the bearings. This system ensures supply of oil to the turbine bearings in spite of failure of oil pumps, particularly emergency oil pump during coasting down. General arrangement of overhead tank is shown in Figure 17.3.

Figure 17.3  Lube oil overhead tank arrangement.

Oil after oil filter is taped to the overhead tank. During normal operation, oil enters the overhead tank through the orifice continuously. Oil overflowing from the overhead tank is drained to the main oil tank. In this line, a sight glass is provided to check whether oil is overflowing continuously or not. When oil pump is in running condition, pressure in the main lubricating line is more. So, oil from the overhead tank is not allowed to flow by gravity through NRV. When oil pump fails, oil pressure drops in the line. In this case, oil from the overhead tank starts flowing through NRV by gravity and is supplied to the bearings. Drain oil from bearing is again routed to the main oil tank as usual. So, the main oil tank should have enough capacity to accommodate the entire oil of overhead tank. Overhead tank capacity is so designed that it can supply oil to the bearing for 20–30 minutes. During starting, oil can be filled up in this tank by quickly the opening filling valve. Interlock provision is given so that the turbine cannot be started if this tank is not filled up. Also, a level switch is provided to initiate an alarm if the tank level becomes low. This system is very safe for turbine. So, along with an emergency oil pump, this system is adopted in most of the cases.

17.2.7  Oil Accumulator An oil accumulator is provided on the governing or control oil line of the turbine. This

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accumulator maintains the oil pressure in the line during momentary fluctuation of oil pressure or oil pump changeover or sudden operation of servomotor of governing valve. In the accumulator, an inert gas filled bladder is provided (Figure 17.4). Gas pressure inside the bladder is maintained slightly below the normal oil pressure of the line.

Figure 17.4  Oil accumulator.

During normal operation, oil pressure of the line compresses the bladder and the oil is occupied in the oil space of the accumulator. When pressure at the line drops, the bladder is expanded due to inside gas pressure. So, it pushes out the oil of oil space to the oil line and takes care of momentary oil pressure fluctuation. The pressure of the gas inside the bladder is to be checked regularly and if pressure drops, it is to be refilled.

17.3  CONDENSATE SYSTEM In a steam turbine, steam is passed over sets of fixed and moving blades to rotate the rotor. After doing work, steam is exhausted to the condenser where it is condensed with the help of cooling water. This condensate is collected at the bottom portion of the condenser, known as hotwell. As steam enters the turbine continuously, so condensation also takes place continuously and it is required to evacuate this condensate continuously. Otherwise, the condenser will be filled up. Evacuation of condensate is done with a pump called condensate extraction pump (CEP). Figure 17.5 shows a condensate system. Two condensate pumps of 100% capacity each are used to evacuate this condensate from the hotwell of condenser. One pump is kept in operation and another is kept as standby. Interlock provision is made so that the standby pump starts when the running pump trips, pressure of the condensate discharge line drops or hot well level becomes high. An isolating valve and a strainer are provided at the suction side. To avoid any air lock at the pump or suction line, a vacuum balancing line is provided. During starting of any CEP, this vacuum balance line is opened so that any air present in the line is socked due to the condenser vacuum. After running of the pump, this line can be closed. Non-return valve is provided at discharge of each CEP.

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Figure 17.5  Condensate system.

Condensate discharged from CEP is sent to the deaerator through ejector condenser and gland steam condenser. It absorbs heat of the ejector steam and gland steam respectively and the temperature of condensate increases. This arrangement increases the efficiency of plant. Ejector steam and gland sealing steam are cooled and the condensate formed is discharged to the condenser. Costly DM water is saved which would otherwise be vented to the atmosphere. With the help of two control valves, hotwell level of condenser is maintained. Control valve CV 1 is opened more when hotwell level is high to discharge more condensate to the deaerator. Simultaneously, control valve CV 2 closes. When hotwell level is low, CV 1 closes and CV 2 opens more to recirculate condensate to the condenser. In case, hotwell level is low or during initial start-up, DM water make-up is given to the hotwell from DM tank. Condensate from CEP also passes through LP heater to gain heat from the extraction steam of turbine and finally, sent to the deaerator. From deaerator, this condensate is fed to the boiler through feed pump. In case, there is a leakage in the condenser tube, cooling water may be mixed with the condensate. In this case, hotwell level goes high. Condenser tube leakage can be detected by testing the hardness of condensate. Online hardness monitoring at the condensate line is helpful to detect the condenser tube leakage instantly.

17.4  GLAND SEALING SYSTEM Gland sealing system is already discussed in Chapter 16. For initial charging of the gland, steam from PRDS is obtained. Gland seal condenser is used to increase the plant efficiency and save DM water.



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17.5  STEAM EJECTOR AND VACUUM SYSTEM As discussed earlier, vacuum is maintained in the condenser to facilitate an easy flow of steam from the turbine and condense the exhaust steam easily. Also, steam can be expanded more in the turbine to get more work done. Vacuum is maintained by continuously evacuating noncondensing gases from the condenser with the help of an air pump or a steam ejector. Pressure of non-condensing gases decreases the condenser efficiency and hence, the plant efficiency too. For removing non-condensing gas or to create vacuum in the condenser, normally steam ejector is used. It is also called steam jet ejector or venturi pump. This is like a pump in which venturi effect of a converging and diverging nozzle is used to convert the pressure energy of steam to velocity energy to create suction effect. Steam ejector is not having any moving part. Steam ejector arrangement is shown in Figure 17.6. This is a multistage condensing ejector. It can be seen that there are two ejectors connected back to back. Ejector connected to the condenser air line is called as interstage ejector and the other ejector is called after ejector. One condenser is connected to both the ejectors to condense the motive steam used for the vacuum creation. Condensate produced by this steam is sent to the condenser.

Figure 17.6  Steam ejector system.

When high pressure steam is passed on a convergent–divergent nozzle, a low pressure is created at the throat. So, when steam is passed through ejector 1, it pulls the non-condensing gas from the condenser. Steam along with this gas mixture is passed to the interstage condenser. At this interstage condenser, condensate from CEP flows inside the tube. The motive steam and gas mixture is condensed at this interstage condenser and the condensate so produced is drained to the condenser through a U-loop tube. U-loop is used to maintain some head in the line to avoid air ingress to the condenser. In this way, heat of motive steam is utilised to increase the temperature of main condensate. When vapour load is more, ejectors are connected in stages. In Figure 17.6, a two-stage ejector is shown. Vacuum is again created at the interstage condenser through ejector 2,

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like ejector 1, as discussed earlier. Non-condensing gas and steam mixture of intercondenser is passed to after condenser where it is condensed again with the help of main condensate. Finally, non-condensing gas is vented out to the atmosphere through a vent. A rotameter is fitted at the vent to measure the quantity of non-condensing gas vented to the atmosphere. Condensate produced at the after condenser is sent to the main condenser through a suitable trap. A trap is placed so that only condensate can go to the condenser. Steam ejectors are classified as follows:

• Single stage or multistage ejector • Condensing or non-condensing ejector

During starting of turbine, when more vapour is to be extracted from the condenser, starting ejector is taken into service. Starting ejector or hogger ejector is a single stage noncondensing ejector. Here, air and steam mixture is vented to the atmosphere without condensing. Once the vacuum is obtained, the main ejector is taken into line. Working Principle of Ejector A high pressure motive steam enters the ejector chest through nozzle (Figure 17.7) and then, it is expanded. Pressure energy of steam is converted into velocity. Increased velocity causes reduced pressure which socks vapour. Diffuser section then compresses the steam vapour mixture and is exhausted to the condenser where this mixture is quickly condensed.

Figure 17.7  Ejector.

Merits of Ejector

• • • • •

Simple construction Easy installation No moving parts Long useful operating life Easy to operate

Operating Procedure of Ejector System

• • • •

Circulate condensate through ejector condenser. Open steam of ejector 2. So, it will create vacuum in interejector condenser. Open steam of ejector 1. Open air valve of condenser.

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17.6  CONDENSER Condenser is an important auxiliary equipment of any steam turbine. Exhaust steam of turbine is exhausted into condenser where it is condensed in the vacuum. As discussed earlier, by maintaining vacuum in condenser, maximum energy can be extracted from the steam and the turbine efficiency increases. The condensate obtained is utilised again at the boiler for steam formation. There are different types of condenser. Some of the important types of condensers are listed below:

• Jet type condenser • Surface condenser • Air condenser

Jet Type Condenser In this type of condenser, cooling water comes in direct contact with the steam to be condensed (Figure 17.8).

Figure 17.8  Jet type condenser.

This type of condenser is not used in power plants, as the condensate produced is contaminated with cooling water and cannot be used in the boiler. Surface Condenser Surface condenser is widely used at power plants. Cooling water is not mixed with condensate in this case. Condensate obtained is pure and can be used in the boilers. This is a shell and tube type heat exchanger. Shell of the condenser is closed. Tubes are arranged inside the shell in which cooling water flows. Condenser neck is connected to the exhaust hood of turbine. An expansion joint is provided in between to facilitate thermal expansion. Steam from turbine, flows at the shell side of condenser and the cooling water flows inside the tube. The main components of a surface condenser are shown in Figure 17.9. Details of the main components of a surface condenser are given below: Shell:  Shell is the outer body of the condenser and heat exchanger tubes. It may be cylindrical or rectangular in shape. Shell shape is determined depending upon the size of condenser, plant

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Figure 17.9  Surface condenser.

layout and manufactures design preference. It is fabricated from steel plates. Baffle plates are provided to get the desired flow path of cooling water. Tube sheet and intermediate plates are provided for fitting and they provide support to the long condenser tubes. In some designs, the condenser is partitioned into two halves. Each half is having an independent cooling water inlet and outlet system. In this design, one half of the condenser can be taken out of service for maintenance, keeping other half in operation. In this condition, the load is reduced as the condensing capacity of the condenser reduces. Waterboxes, cooling water inlet and outlet piping, air pipe and steam inlet neck are welded to the shell of condenser. Tube:  Tubes are fixed in the condenser by expanding both ends at both side tube sheets. Normally, tubes are made of stainless steel, brass or bronze. Cooling water flows inside these tubes. If cooling water quality is not maintained properly, there is a chance of scale formation at the waterside of the tube. This scale formation reduces heat transfer and hence, efficiency of the condenser too. So, the tubes are required to be cleaned regularly. Waterbox:  Waterboxes are the end portion of the condenser. In this area, water enters, exits and turns the direction. By opening the waterbox, tube ends are exposed for cleaning. Waterbox cover is tightly fastened with shell to ensure there is no leakage of cooling water. There is a chance of settling of sludge in this area. So, drain points are provided. To vent out any air present in the waterbox, vents are provided. Hotwell:  Bottom portion of the condenser is called hotwell where the condensate is collected. The level of hotwell is maintained with control valves, as discussed earlier. For filling hotwell initially, a make-up point is provided. Level gauge is provided to measure the hotwell level.

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Air outlet:  Close spaced tubes are provided at the air outlet section. By this arrangement, air extracted by the ejector is cooled. This section is called air cooling section. A suitable baffle is provided to ensure that steam is not extracted along with air. In a two-section condenser, two air outlet pipes are connected to two sections of the condenser. These two pipes are connected together before going to the ejector with suitable isolation facility for both the sections. By this arrangement, one section can be isolated during maintenance of that section. Rapture disc:  A rapture disc is provided at the condenser to take care of accidental high pressure in the condenser. In this case, the rapture disc raptures and the pressure is released without causing any harm to the turbine. Vacuum break valve:  In some cases, it is required to stop the turbine as soon as possible (reducing coasting down time). During vacuum condition in condenser, turbine takes longer time to coast down. But if there is no vacuum, coast down time decreases. In some fault condition like high vibration tripping, it is desired to stop the rotor as soon as possible to minimise further damage to the turbine. Some fault conditions on which vacuum breaking is required are listed below:

• • • •

Loss of lubrication High vibration High axial expansion Generator differential protection

In these fault conditions, the vacuum break valve which is normally a solenoid operated valve, opens. Interlocking of opening this valve is made accordingly. Before vacuum build-up for next starting of the turbine, this valve is to be closed. Air-cooled Condenser Waterless dry cooling system or air-cooled condenser (ACC) is installed to reduce water consumption at thermal power plants. This type of condenser is used at the power plants located at low ambient temperature area or where the water is very scarce. Air-cooled condenser is a heat exchanger which condenses the turbine exhaust steam inside the finned tubes by ambient air instead of cooling water. Steam enters the air-cooled condenser at the inlet header and distributed at all A-frame type heat exchanger (Figure 17.10). There are two outlet headers at the bottom of the A-frame connected to the inlet header by finned tube bundle. Finned tubes are used because of their low thermal conductivity and larger surface area. Ambient air is blown over the external finned surface of the tube bundle by mechanical fans located at the bottom of A-frame tube bundle. Variable speed drives or double speed motors are used to drive the fan as per the requirement to supply the required quantity of air. Latent heat of the steam is taken out by this air and the condensate collected at the outlet header is then reused at the boiler for steam generation. The external surface of the finned tubes on air-cooled condenser is very prone to fouling. Heat transfer is affected in this case. So, fin cleaning is done regularly through a high pressure water jet.

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Figure 17.10  Air-cooled condenser.

17.6.1  Dalton’s Law of Partial Pressure In a condenser, mixture of steam and non-condensing air exists. It is required to know the partial pressure of air and steam. From the partial pressure of air, volume of air present in the condenser can be calculated. This is done with the help of Dalton’s partial pressure theory. The law sates that the pressure of a mixture of gases (here, it is air and steam) is equal to the sum of individual gas pressure. Here individual gas pressure means pressure would be exerted if it would occupy the same place by that gas alone. Pc = Pa + Ps where Pc = pressure of air and steam combination Pa = partial pressure of air Ps = partial pressure of steam EXAMPLE 17.1  In a condenser, the vacuum gauge reading is 0.92 kg/cm2(vacuum) and the condensate temperature is 35 °C. Calculate the partial pressure of air and the volume of air present inside the condenser. Solution  Condenser vacuum gauge reading is 0.92 kg/cm2 So, Absolute pressure Pc = Atmospheric pressure – Vacuum gauge pressure = 1.0332 – 0.92 = 0.1132 kg/cm2 From steam table, corresponding to 35 °C, the steam pressure Ps is 0.057 kg/cm2. So,

PA = 0.1132 – 0.562 = 0.0562 kg/cm2

Volume of air per cubic metre of condenser volume can be find out as per Ma = = 0.0562  104 

1 = 0.0623 m3 29.27  (35  273)

here, R is the gas constant. For atmospheric air, it is 29.27 kf-m/kg/K.

PAV RT

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17.6.2  Condenser Efficiency Condenser efficiency is the ratio of temperature raise of cooling water used in the condenser to the difference of vacuum temperature and inlet cooling water temperature. This is represented as follows: Condenser efficiency hcon =

Temperature raise of cooling water Vacuum temperature - Inlet cooling water temperature

Example 17.2  The cooling water inlet temperature is 30 °C and the outlet temperature is 38 °C. The value of condenser vacuum is 0.95 kg/cm2 (gauge). Calculate efficiency of the condenser. Solution  Absolute pressure of condenser = 1.0332 – 0.95 = 0.0832 kg/cm2 From the steam table, corresponding to 0.0832 kg/cm2, the absolute temperature or vacuum temperature is 41.46 °C. Temperature raise of cooling water = 8 °C 8 So, efficiency of condenser hcon = = 69.8% 41.46 - 30

17.7  Cooling water system In a condenser, cooling water is circulated to condense the exhaust steam of the turbine. The exhaust steam is having a considerable amount of heat energy. This heat energy is required to be transferred to the cooling water to condense the steam. So, the cooling water temperature rises. Cooling water is required to be cool down to be used again in the condenser (in case of close loop system). This cooling is done at cooling tower. From cooling tower, the cooling water is circulated through the condenser with the help of a cooling water pump. Suppose the exhaust steam of turbine is having 0.85 dryness fraction and the condenser vacuum is 0.08 kg/cm2 (absolute). From the steam table, enthalpy of steam corresponding to 0.08 kg/cm2 (absolute)

= 41.2 + 0.85  574 = 529.1 kcal/kg

This exhaust steam is to be cooled down to 41.2 °C (corresponding to 0.08 absolute pressure). So, 529.1 – 41.2 = 487.9 kcal/kg So, 487.9 kcal/kg of heat energy is required to be transferred to the cooling water to condense this steam to get the condensate at 41.2 °C. So, huge amount of cooling water is required for this. Weight of cooling water required for the condenser is given below: Ww =

Ws ( H - h1 ) t2 - t1

where Ww = weight of cooling water Ws = weight of steam to be condensed H = total heat of steam entering the condenser h1 = total heat of condensate

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t1 = inlet temperature of cooling water t2 = outlet temperature of cooling water There are two types of cooling water circulation system. These are as follows:



• Open or once through system • Closed system

In open or once through system, cooling water is pumped to the condenser from a river or sea and after cooling, hot water is discharged to the river or sea. This system is used in power plants located close to sea or river. In most of the power plants, closed system is used. In closed system, hot water is cooled at a cooling tower and the cold water so obtained is again sent to the condenser. The arrangement of open and close cooling water system is shown in Figure 17.11.

Figure 17.11  Cooling water circulation system (a) Open cycle system and (b) Closed cycle system.

17.7.1  Cooling Tower Cooling tower is a structure in which hot water droplets are made with the help of nozzles to increase the contact surface of water and are allowed to come in contact with the atmospheric air. Atmospheric air is having certain capacity to absorb the water vapours at a given temperature. Water vapours are created due to evaporation of water droplets. For evaporation of water, heat is required. This heat is obtained from the remaining water. So, the remaining water is cooled, as the heat is removed from it for evaporation. Rate of evaporation and hence, drop in cooling water temperature depends upon the following factors:

• • • • • •

Water surface area exposed to atmospheric air Time of expose Velocity of air flow Relative humidity of atmospheric air or difference between dry and wet bulb temperature Direction of air flow with respect to water flow Inlet water temperature

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Relative humidity is calculated from the difference of dry and wet bulb temperature. This indicates how much water vapours the atmospheric air contains. It is always ideal to cool water upto the wet bulb temperature. But practically, this is not possible. The difference between wet bulb temperature and outgoing cooling water temperature is called cooling tower approach. In a cooling tower, water enters from the top, gets distributed evenly and forms droplets with a suitable nozzle arrangement. Air flows from the bottom of the tower. It passes through louvers to flow in cross or parallel direction to come in contact with the water droplets. Air flow velocity is maintained naturally or through fans. The tower is made from wood, steel or concrete. There are different types of cooling tower. Some of them are listed below:

• • • •

Natural draft cooling tower Hyperbolic cooling tower Induced draft cross flow cooling tower Induced draft counterflow cooling tower

In natural draft cooling tower, air velocity is created naturally. Hyperbolic cooling tower is a natural draft cooling tower. Air velocity is created due to chimney effect. Air flow is due to density difference between the atmospheric air outside the chimney top and that of hot air inside the tower. This density difference creates a pressure difference for the flow of air. In this case, height of the tower is required to be made more to get more pressure difference. Mechanical draft cooling towers are widely used at power plants. The velocity of air is created by a fan. Mostly, induced draft type cooling towers are used. Speed of the fan can be varied to increase or decrease the air velocity. So, the tower can be operated efficiently. Induced draft counterflow and induced draft cross flow type cooling towers are widely used at the power plants. Here, these two induced draft cooling towers are discussed in detail. Induced Draft Counter Flow Cooling Tower In counter flow cooling tower mechanical fan is located at the top of the tower, as shown in Figure 17.12. Water is distributed throughout the area of tower and its droplets are formed with the help of spray nozzles. Mist eliminators are placed above the distributed pipeline and nozzle to restrict the escape of vapour mist to the atmosphere. Hot water is allowed to flow down to the basin by gravity.

Figure 17.12  Induced draft counterflow cooling tower.

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When fan is started, atmospheric air is socked and it enters through the louvers. This air moves up and comes in contact with the downward water droplets. It carries the heat of water and gets discharged to the atmosphere through fan. The flow of air and water is in counterdirection. So, the temperature difference between hot water and cold air remains almost the same throughout the mixing area. So, this type of tower is thermodynamically most suitable. Cold water is collected in a basin from where the water is drawn out for further use in condenser. This complete arrangement is known as cell. Cells are connected side by side in parallel to meet the requirement of plant. In the basin, blowdown points are provided to drain out the settled sludge and debris. Induced Draft Cross Flow Cooling Tower In cross flow cooling tower, air flows over the water droplets in cross direction. Air flows in the horizontal direction, whereas the water droplets flow down into the basin by gravity in vertical direction (Figure 17.13).

Figure 17.13  Induced draft cross flow cooling tower.

The water is converted into droplets with the help of nozzles. It is distributed throughout the mixing area with the help of perforated trays or wooden fills. It falls down to the cold water basin by gravity. When fan is started, air enters through the louvers and flows in cross direction to the falling water droplets. It moves up due to suction of fan through a drift eliminator which helps to separate the water mist. Air velocity and hence, cooling can be increased or decreased by increasing or decreasing the fan speed. Fan blade made of cast aluminum or fibre reinforced plastic (FRP) is attached to a hob and connected to a driving motor through a suitable reducing gear. Variable speed drive can be used to increase or decrease the fan speed as per the requirement. As bigger size fans are used, so there is a chance of heavy vibration. Vibration switches are provided to stop the fan



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in case of excessive vibration. To check the oil level and top up oil in the gearbox, provision is made outside the tower. For bigger capacity plants, a number of cells are connected in line to meet the total cooling water requirement (Figure 17.14).

Figure 17.14  Cooling tower with multicells.

To get proper distribution of water in cooling tower, spray nozzles, fills and distributors are required to be kept clean from scale, algae blockage, etc. Drift eliminators are to be properly checked to minimise the drift loss of water. Basin blowdown is to be given regularly to drain out the settled sludge from the basin. When cooling tower is placed in a dusty atmosphere along with air, a lot of dust particles ingress to the tower and mix with the cooling water. In this case, sand bed type side stream filter is installed. Part of the cooling water from cold water basin is circulated through this sand bed filter. Dust particles are filtered and clean water is sent to the basin. Side stream filter is backwashed regularly. Some terms used in the cooling tower are discussed below: Cooling range:  The difference between the temperatures of hot water entering the tower and cold water leaving the tower is called cooling range. Approach:  The difference between the temperature of cold water leaving the tower and the wet bulb temperature of atmospheric air is known as approach. Wet bulb temperature:  Wet bulb temperature can be measured by using a thermometer with the bulb covered in wet muslin. This is the minimum temperature which can be achieved by purely evaporative cooling. Wet bulb temperature is always lower than the dry bulb temperature. Dry bulb temperature:  Dry bulb temperature refers to the ambient air temperature basically. It is called dry bulb because the air temperature is indicated by a normal thermometer, not affected by the moisture of air. Drift:  Water droplets that are carried out of the cooling tower with the exhaust air are called drift. Drift droplets have the same concentration of impurities as the circulating water of the tower. Drift eliminator:  Drift loss rate is normally reduced by putting a baffle-like device, called drift eliminator, through which air has to pass after leaving the fill and spray nozzle zone of the tower.

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Fill:  Inside the tower, fills are arranged to increase the contact surface as well as the contact time between air and water. It provides better heat transfer and the efficiency of tower increases. Film type and splash type fills are used. Capacity:  The amount of water (m3/hr) that a cooling tower can cool through a specified range at a specified approach and wet bulb temperature is called capacity of that cooling tower. Make-up:  The amount of water required to make up the normal losses caused by blowdown, drift and evaporation is known as make-up. Heat load:  The amount of heat to be removed from the circulating water per hour is called heat load of cooling tower. Heat load is equal to the rate of water flow per hour multiplied by range. Cycle of concentration (COC):  When pure water is evaporated, minerals are left behind in the circulation water. As evaporation continues, the water becomes more concentrated than the original make-up water. The ratio of level of solids of the circulating cooling water to the level of solids of the fresh raw make-up water is called cycle of concentration (COC). Water Balance in Cooling Tower During continuous operation of cooling tower, water is evaporated continuously. As water is evaporated, minerals are left behind in the circulating water. The concentration of solids in water becomes more than the original make-up water. So, blowdown is required to remove a portion of concentrated water which is replaced with fresh make-up water. If the circulating water has five times the solids concentration than that of the make-up water, then the COC is 5. The required make-up is the sum of following three losses: Evaporation loss:  It is given by

Evaporation loss E = C  ΔT 

Cp

Hv where C = circulation rate (m3/hr) DT = temperature difference between hot and cold water (°C) Cp = specific heat of water (1 kcal/kg °C) Hv = latent heat of vaporisation of water (540 kcal/kg). Windage or drift loss:  This is a small amount of water losts as fine droplets in the air that is discharged from a tower. Windage carries solids of circulating water with it and reduces dissolved solids in the circulating water. The approximate drift loss W of different types of cooling tower is given below:

– About 0.3% to 1.0% of circulation for a natural draft cooling tower without drifts eliminators – About 0.1% to 0.3% of circulation for an induced draft cooling tower without drift eliminators – About 0.005% of circulation for an induced draft cooling tower with drift eliminators

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Blowdown loss:  In the evaporation process, dissolved impurities of make-up water are concentrated in the circulating water. To minimise excessive concentration of these impurities, some quantity of circulating water is removed from the system. This is called bleed off or blowdown. Amount of bleed off can be determined from the following: %E COC 1 here, B is the blowdown, W is the windage, E is the evaporation and COC 1 is the cycle of concentration 1.

%B + %W =

17.7.2  Cooling Water Treatment In a power plant, the condenser of a turbine is a critical component. Cooling water is circulated in its tube. Scale deposit in this tube may affect the heat transfer. So, it is very important to avoid scaling of condenser tube. Cooling water circulation may result in the corrosion of waterbox and tube. There may be growth of algae and bacteria in the water. This growth may choke the circulation system. To get an optimum life of the condenser and better efficiency, the quality of cooling water is required to be maintained strictly. For this, various chemical treatments are carried out. Some of the chemical treatments are given below:

• Antiscale and corrosion treatment • Biocide treatment • Acid treatment

Antiscale and Corrosion Treatment Deposition of scale in cooling water system reduces the efficiency of heat transfer and restricts the water distribution pipeline. The scale is deposited on the surface which is contact with water by precipitation and crystal growth. Salts of calcium and magnesium are responsible for scale formation. Suitable antiscaling chemical is added in the cooling water to minimise the scale. Antiscale chemicals prevent the scale forming compounds present in the cooling water from getting precipitated. To avoid corrosion in the cooling water system, corrosion inhibitors are used. Corrosion inhibitor is a chemical which effectively decreases the corrosion rate when added to the cooling water. There are different antiscaling and corrosion inhibitors available in the market supplied by different water treatment companies with different brand names. These chemicals are dosed in the cooling water regularly. Dispersants are used in cooling water to control fouling. Dispersant is a chemical that increases the surface charge of suspended particulates. Electrostatic repulsion between like charged particles prevents agglomeration which reduces the particle growth and makes the particles less sticky. So, a dispersant affects both particle to particle and particle to surface interactions. To measure the corrosion rate of cooling water, corrosion coupon is installed at the cooling water circuit.

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Biocide Treatment To control the growth of slime, organic bacteria and algae, biocide is dosed in the cooling water. This is done mostly by shock dose method. Depending upon the mechanism used to kill the organisms, biocides are grouped into two categories—oxidising and non-oxidising. Oxidising biocide attack cell component and kill the organism while non-oxidising biocides damage the cell wall or interface with the cell metabolic process. Oxidising biocides:  An oxidising biocide attacks microorganisms by oxidising (an electron transfer reaction) the cell structure and disrupting nutrients passing from the cell wall. The most commonly used oxidising biocides are chlorine, bromine (halogen) and chlorine dioxide (ClO2). When chlorine is added to water, it produces hypochlorous acid (HOCl) and hydrochloric acid (HCl). Cl2 + H2O  HCl + HOCl This hypochlorous acid (HOCl) attacks the microorganism. HOCl dissociates into hypochlorite (OCl –), as pH increases. HOCl  H+ + OCl–



Hypochlorite (OCl–) is also an oxidant but is weaker than HOCl. The sum of hypochlorous acid and hypochlorite is called free chlorine. Hypobromous acid (HOBr) is also a effective oxidant. It is formed by the reaction of sodium bromide (NaBr) with hypochlorous acid.

HOCl + NaBr  NaCl + HOBr



Some other oxidising biocides are given below:

• • • •

Sodium hypochlorite or bleach (NaOCl) Calcium hypochlorite or bleaching powder [Ca(OCl)2] Ozone Hydrogen peroxide

Non-oxidising biocides:  A non-oxidising biocide functions by a mechanism other than the oxidation, including interference with the cell metabolism and structure. Non-oxidising biocides are mostly organic-based. Methylene bisthiocyanate (MBT) is a commonly used non-oxidising biocide. There are many water treatment companies supplying non-oxidising biocide on their brand names. The combination of oxidising and non-oxidising biocides is frequently used for effective biological growth control. Acid Treatment pH of cooling water increases due to continuous evaporation and concentration of salts. Particularly, the concentrations of sodium bicarbonate (NaHCO3) and sodium carbonate (Na2CO3) in cooling water are responsible for the increase in pH. When sodium bicarbonate (NaHCO3) is heated, it produces sodium hydroxide or caustic soda (NaOH) and sodium carbonate or soda ash (Na2CO3).

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2Na2CO3 + H2O = 2NaOH + CO2





2NaHCO3   Na2CO3 + H2O + CO2

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D

Both sodium hydroxide (NaOH) and sodium carbonate (Na2CO3) are alkaline in nature. So, pH of the cooling water pH increases. To maintain the pH of cooling water, sulphuric acid is dosed. Blowdown:  Due to continuous evaporation of water, dissolved solid level increases. So, to keep the dissolved solids under control, blowdown is given. Due to the water loss in cooling tower mainly due to evaporation and drift loss, make-up water is required to be added in the system. With efficient antiscale treatment and suitable make-up quality, upto 8 COC are possible.

EXERCISES

1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 21. 22. 23. 24. 25.

What is the function of lube oil in a turbine? Why is the oil tank base is made sloped to one side? What is the function of vapour extraction fan? What is coasting down of turbine? Why is an emergency oil pump provided and when does it operate? How is the temperature of oil controlled? What condition is indicated by the differential pressure across the oil filter? Why is oil centrifuge or oil purifier used? What is the difference between purification and clarification? Why is an overhead oil tank provided and when does it work? How does an oil accumulator work? Why is vacuum balancing line provided at the condensate extraction pump? How is the level of condenser maintained? Why is the gland seal condenser used? Why is vacuum maintained in a condenser? What is the function of an air ejector? When is a multistage ejector used? Why is an erector condenser used? What are interstage and after ejector condenser? What are the functions of U-loop and rotameter in an ejector? What is the merit of a condenser having two halves? Why is an expansion bellow required to connect a condenser to a turbine exhaust hood? How does scale on the condenser tube affect the performance of a steam turbine? Why is rapture disc provided in the condenser? What is the use of vacuum break valve? When is a dry cooling or air-cooled condenser used and how does it work?

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Define approach and range of cooling tower. What is the difference between dry bulb temperature and wet bulb temperature? Why is a drift eliminator used? Why is a side stream filter used? What is evaporation loss and how is it calculated? What is COC of cooling water? How is it controlled? What type of chemical treatment is done at cooling tower and why? How does dispersant work in cooling water? What are the oxidising biocides used in a cooling tower? Why is the acid treatment of cooling water required?

26. 27. 28. 29. 30. 31. 32. 33. 34. 35.

Chapter

18

Operation of Steam Turbine

18.1  INTRODUCTION Operation of steam turbine is a complex process. Before rolling of a turbine, earlier discussed auxiliary systems are properly put in service. Special care is taken for the starting of turbine, particularly during cold start-up. We will discuss about operation of individual systems one by one so that it will be easier to understand the complete system. Normally, for start-up of a turbine, some sequences of operation are followed. We will discuss the operation of different systems as per the sequence in the subsequent sections.

18.2  CHARGING OF STEAM PIPELINE OR HEAT UP The steam is carried from boiler to turbine by the main steam pipeline. In cold condition, special care is to be taken to heat up this steam line and allow thermal expansion gradually before getting full load on the turbine. Condensate is formed in the steam pipeline due to the condensation. Drain points are provided at the steam line to drain out this condensate. First of all, these drains are opened before charging steam on that pipeline. After the condensate is drained out, the main steam stop valve of boiler is opened slowly (most commonly, the bypass valve). Some steam is allowed to flow through the pipe and the temperature of pipe starts increasing. Condensate along with some steam is allowed to come out through drain. Drains are throttled slowly and closed when no more condensate but only dry steam is coming out from the drain. Steam traps provided in the pipeline are kept in line once the drains are closed. If a vent is provided in the pipeline before emergency stop valve of turbine, then this is opened to allow steam to flow so that the pipeline upto ESV can be heated up. The main steam stop valve of boiler is opened slowly to increase the line temperature gradually. It is to be ensured that the expansion is not restricted anywhere. Once the pipeline is heated, stop valve of the boiler can be opened fully.

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18.3  OPERATION OF COOLING WATER SYSTEM Following steps are followed to circulate cooling water in the condenser:

• Ensure the level of cooling tower basin is normal. • Keep suction valve of the pump in open condition and discharge valve in closed condition. • Ensure the inlet and outlet cooling water valves of condenser and the hot water distributor valves of cooling tower are in open condition. • Start the pump. If there is a variable speed drive, then start the pump at lower speed and gradually increase the speed. • Open the discharge valve. • Observe cooling water is falling on the cooling tower. • Open the vents provided at the condenser waterbox to remove the trapped air. • Increase speed or start other pump to get the required amount of cooling water flow at the condenser. • Observe all the cooling water pumps are sharing load. • Once turbine is started and loaded, cooling tower fans can be started one by one as per the requirement to get the desired cooling water temperature.

18.4  OPERATION OF LUBRICATION OIL SYSTEM Before starting the turbine, the lube oil system is to be started. Lube oil is required to flow into each bearing. To start lube oil system following steps are followed:

• • • • • • •



•



• • •

Ensure the lube oil tank level is normal. Check the valves provided at oil line, oil filter and oil cooler are in open condition. Check the cooling water outlet valve of oil cooler is in close condition. Ensure the suction and delivery valve of oil pump are in open condition. Start the oil pump. Adjust the oil pressure by adjusting the recirculation valve, if any. Check the oil filter differential pressure. If it is high, change the filter cartridge or change the filter. Ensure oil is supplied to each bearing and the governing oil is available. Adjust the oil pressure at various bearings. Maintain the oil temperature by adjusting the cooling water outlet valve of oil cooler. Keep the standby oil pump and emergency oil pump ready. Ensure the overhead tank is full.

18.5  BARRING GEAR OPERATION Before rolling, turbine is to be put on barring operation. Following steps are followed for barring operation:

• Ensure the lube oil system is in service and oil is circulating at all the bearings at a desired pressure.

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Start the jacking oil pump, if provided, to lift the rotor. Engage the barring gear clutch. Start the barring gear. Observe the rotor is rotating at barring speed without increase in bearing vibration and temperature and there is no abnormal sound.

18.6  CONDENSATE SYSTEM OPERATION Exhaust steam of turbine is condensed at the condenser with the help of cooling water. The condensate produced is evacuated from the condenser with the help of condensate extraction pump (CEP). This condensate passes through the gland steam condenser and ejector condenser to gain heat from the gland steam and ejector steam respectively. So, the temperature of condensate increases there. Before feeding to the deaerator, this condensate is further heated at LP heater by using LP extraction steam of turbine. To put this condensate system in operation, following steps are followed:

• Ensure the condenser hotwell level is adequate. Otherwise, fill the hotwell with make-up DM water. • Open the suction and discharge valves of the pump. Ensure differential pressure of the strainer is normal. • Open the condensate inlet and outlet valves of gland seal condenser, ejector condenser and LP heater. • Open the pump gland cooling valve and start the pump. • The condensate passes through gland seal condenser and ejector condenser. Through recirculation control valve, it should be recirculated to the condenser again. • If the level of hotwell is more, then the discharge valve can be opened, otherwise the recirculation valve to be kept open for the recirculation of condensate. • Once the steam starts entering the turbine, discharge control valve can be put in automode to maintain the level of hotwell.

If the condensate extraction pump is to be started when there is vacuum inside the condenser, then the vacuum balance valve is to be opened to remove any air trapped inside the pump and pipeline.

18.7  GLAND STEAM CHARGING Once the above systems are in service, gland steam can be charged at gland. Figure 18.1 shows a gland steam system. Proper care is to be taken while charging the gland steam in a cold turbine. As the gland area of turbine is cold, hot gland steam may produce a thermal shock in that area. To avoid this, steam is to be charged slowly and the condensate produced is to be drained out through the gland drain. Following steps are to be followed for the gland steam charging:

• Ensure the auxiliary or motive steam is available from PRDS at a desired pressure and temperature.

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Figure 18.1  Gland steam system.



• • • •

Open the gland steam header and the gland drains. Open the control valve CV 1 slowly. Observe steam is coming out from the gland steam header drain and the front gland vent. When the temperature of gland steam header is reached at the desired level, close the header drains. • Open the control valve CV 1 more to achieve the gland steam header pressure. • Observe the steam is vented out from the rear gland. • Put the control valves in automode with a desired set value.

If there is gland steam condenser, then this condenser is to be charged first before opening the control valve CV 1. To charge the gland, following steps are to be followed:

• Circulate cooling water (discharged condensate from CEP) through the gland steam condenser. • Open the motive steam of gland steam condenser ejector. • Open the gland vent valve.

18.8  VACUUM BUILD-UP Before the main steam enters the turbine, there should be vacuum inside the condenser. As discussed earlier, the starting ejector is used during starting to evacuate air from the condenser. This is a single stage non-condensing type ejector. Following steps are to be followed to build up vacuum with the help of starting ejector:

• Ensure the auxiliary steam is available at a desired pressure and temperature. • Ensure the vacuum break valve of the condenser is closed.

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• Ensure cooling water is circulating in the condenser and the turbine gland is charged fully. • Open the steam valve of the staring ejector. • Observe the steam is vented to the atmosphere. • Open the ejector air valve. • Observe vacuum inside the condenser is increasing slowly.

Through starting ejector, vacuum in the condenser can be obtained faster. But the steam used in this ejector is not utilised. It is vented to the atmosphere. So, the main ejector is to be taken in service, once the turbine is loaded. To put the main ejector on line, following steps are followed:

• Ensure the condensate extraction pump (CEP) is running. • Open the cooling water (discharged condensate from CEP) inlet and outlet valves of the ejector condenser which is put in service. • Vent out air from the waterbox of the ejector condenser. • Open the condensate drain valve of inter ejector condenser and after ejector condenser of that ejector which is connected to the main condenser. • Open the steam valve of after condenser ejector. • Open the steam valve of inter condenser ejector. • Observe the condensate is drained out from both the condensers (drain line is felt warm, if touched) • Slowly open the air valve of the ejector and observe the vacuum is increasing.

When vacuum is stable, then starting ejector can be stopped by closing the air valve first and then, the steam valve of that ejector. To take out the main ejector out of service, following steps are followed:

• • • • •

Stop Stop Stop Stop Stop

the the the the the

air valve of the ejector. steam valve of inter condenser ejector. steam valve of after condenser ejector. drain valve of inter and after condenser. water inlet and outlet valve after the condenser is cooled.

18.9  TURBINE START-UP Once the above discussed systems cone in operation and full vacuum is obtained inside the condenser, the turbine can be started. Like boiler, a turbine is required to be started in following two different conditions:

• Cold start-up • Hot start-up

In cold start-up, turbine is started from cold condition. In this case, special care is taken to heat up the casing and rotor for the proper thermal expansion. As both the rotor and casing are in cold condition, it requires longer time to heat up. But, in case of hot start-up, both the casing and rotor are in hot condition. So, it can be started within a short period.

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Before discussing further, we will discuss about the start-up curve of the turbine. This curve gives an idea how turbine reaches its full speed in cold and hot conditions. Start-up Curve To allow proper thermal expansion of casing and rotor, start-up procedure as advised by the turbine manufacturer is to be followed. We should not enter the steam immediately to the turbine, as it may damage the turbine due to uneven expansion. Turbine shaft material has its own natural frequency. When turbine rotates on such a speed, that frequency of shaft becomes close to its natural frequency, thereby causing noise and high vibration in the machine because of the resonance. Shaft becomes dynamically unstable and large vibration is developed. It occurs at a speed called critical speed. Running of steam turbine at this speed is avoided. Beyond the critical speed, vibration becomes normal. An example of start-up curve of a steam turbine is shown in Figure 18.2. This is the example of a cold start-up curve of a 5500 rpm steam turbine having one critical speed zone. This is given here for discussion purpose only. Exact curve for different steam turbines is different and it is advised by the turbine manufacturer. This start-up procedure is to be followed either manually or by autogoverning system.

Figure 18.2  Turbine start-up curve.

Details about this curve are giver here one by one. O–A:  This is the rate of speed raise upto the low idle speed. After opening the emergency stop valve, control valve is opened slowly to raise the speed of the turbine upto the low idle speed of 1000 rpm at a rate of 20 rpm/s. Steam enters the turbine at a slower rate. A–B:  This is the low idle speed of the turbine. At a speed of 1000 rpm, the control valve opening stops. Turbine continues to run at this speed for 10 minutes. This is called socking time of the turbine. Turbine is allowed to heat up for the thermal expansion. In case of bigger turbine having heavy mass of rotor and casing, more time is required. During hot start-up, less time is required.

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B–C:  This is the rate of speed raise upto the high idle. Turbine is allowed to ramp up at a certain rate, as advised by the turbine manufacturer. In this case, it is 10 rpm/s upto 2700 rpm. C–D:  It is the critical speed zone of the turbine. To avoid this zone, speed of the turbine is raised at a faster rate. In this case, the zone starts from 2700 rpm to 3000 rpm and the rate of raise of speed is 100 rpm/s. D–E:  After passing the critical zone, again the turbine speed is raised at a lower rate upto the high idle speed. In this case, the high idle speed is 3500 rpm and the rate of raise of speed is 10 rpm/s. E–F:  This is called high idle speed. Like low idle speed, turbine is kept at constant speed for some time for socking. In this case, it is 3500 rpm and hold time is 10 minutes. F–G:  From point F, turbine speed raises upto the rated speed at a certain rate. In this case, it is 20 rpm/s. For this starting curve, turbine takes 27 minutes 27 seconds to reach at full speed during the cold start-up. Like this, there is a hot start-up curve also. But the time required to reach at full speed is less in that case. Once the turbine reaches at full speed, it can be loaded gradually. Rolling of Turbine To start rolling of turbine, some steps are followed. Depending upon the mode of starting (auto or manual) and types of governing system (hydraulic or electrohydraulic), there may be some change in the steps. Some basic steps are discussed below:

• Ensure the lube oil and control oil are available, cooling water is flowing in the condenser, the turbine is on barring, the gland is properly charged and the vacuum is available. • Check the steam pressure and temperature are within limit. • Ensure all the turbine tripping interlocks are healthy. • Ensure ESV is in closed position and the control valve is at minimum position. • Reset turbine from remote control desk or local turbine panel. • Open ESV. • Open the control valve gradually in auto or manual mode to follow the start-up curve. • Observe the control valve position, bearing temperature, lube oil pressure at bearings, bearing vibration and any abnormal sound during start-up. • Ensure the barring device is disengaged. • Observe the expansion of casing, rotor and differential expansion. • Maintain the lube oil temperature by adjusting the cooling water at oil cooler. • At critical speed zone, speed is to be raised faster and bearing vibrations should be within limit. • Once turbine reaches its full speed, check all the parameters. • If the main oil pump is mechanically coupled with turbine rotor, then stop AOP and check the oil pressure.

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18.10  TURBINE SHUTDOWN During shutdown of turbine also, proper care is required to be taken. The shutdown may be normal/planned shutdown or emergency shutdown. In planned shutdown, the turbine is stopped in a planned way. But, in case of emergency shutdown, the turbine is required to be stopped immediately or it trips automatically. In emergency shutdown, it is to be ensured that the lube oil supply to all the bearings is available during coasting down. In some emergency situations, the vacuum break valve of condenser can be opened to stop the turbine quickly. For planned shutdown of a turbine, following steps are followed:

• Reduce the load of turbine. If it is a generator, open the generator breaker after reducing the load. • Reduce the speed of turbine upto the minimum governing speed. • Stop ESV. • Ensure the lubrication oil is available during coasting down. • When speed becomes zero, put the turbine on barring operation. • Stop the ejector system. • Continue the cooling water supply to the condenser for 3–4 hours. • Continue the lube oil supply and barring operation till the casing temperature drops to around 90 °C. • Stop the lubrication oil and barring device.

18.11  EMERGENCY SITUATIONS IN TURBINE Steam turbine is a critical rotating equipment. High temperature and pressure steam is used to rotate the turbine at high speed. Mass of the rotating part is more. There is always a chance of severe mishap, leading to a fatal accident and damage to the high cost equipments. Generation of power may be interrupted for a longer period, leading to heavy loss to the plant. So, a power plant engineer should be trained enough to face any emergency situation at any time and properly handle this emergency situations. Some of the emergency situations in a steam turbine are mentioned below: Overspeed:  Due to failure of governing system, the turbine speed may become dangerously high. Rotor is designed to rotate momentarily upto 110% of the rated speed. At higher speed, rotor stress increases. Due to high centrifugal force, the blades which are fixed to the rotor may come out due to the failure of blade root and cause severe accident and damage to the turbine. To avoid dangerous overspeed, a turbine is provided with mechanical and electrical overspeed trip arrangements. Tripping limits are set in such a way so that the turbine speed does not exceed beyond 110% of the rated speed. These overspeed tripping limits are to be checked regularly. Mechanical overspeed device is to be set within the safe limit and checked at suitable intervals. In any circumstances, overspeed tripping limit should not be bypassed. Failure of lubrication oil system:  Lubrication oil is used to lubricate and cool down the bearing metal. In some incidents, lubrication oil supply may be interrupted due to the failure of pumps, leakage in oil line or chocking of oil filter. This condition may damage the bearings and gearbox.



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If such incident happens for any reason, the turbine is required to be stopped as soon as possible. Costing down time can be reduced by opening the vacuum break valve. Oil supply is to be restored as early as possible. After resuming the oil supply, if possible, turbine is to be rotated manually to find out any damage. Bearings are to be inspected. If any damage found, it is to be replaced. High vibration:  Rotor of the turbine rotates at high speed. Any deformation or unbalance in the rotor produces high vibrations. Sometimes, deposit on blades and damage of any rotating part may create heavy vibrations. Damage of journal bearing may also produce vibrations. The moving and rotating parts of turbine are closely spaced. Due to disturbance in rotor shift or differential expansion, there is a chance of rubbing of these parts. Rubbing creates high vibration and abnormal sound. So, in any case, high vibrations of turbine should not be overlooked. In case of high vibrations, the turbine should be stopped immediately and the turbine internal is to be inspected to avoid further damage. High bearing temperature:  High bearing temperature occurs due to inadequate oil flow in the bearing or metal to metal contact in between the bearing and the rotor. High temperature damages babbit material of the bearing. In case of high temperature of bearing, the turbine is required to be stopped. Oil supply to the bearing is to be checked. If required, the bearing should be opened for inspection. In any case, high bearing temperature tripping should not be bypassed. Blackout condition:  Due to disturbance in electrical system or station power system, power to the auxiliary equipments of turbine and the boiler may fail and no power is available at the power plant. This situation is called blackout. In this situation, no power is available to run any equipment. There is no power for plant lighting also. It is to be ensured that the turbine is tripped and DC oil pump is started. After coast down, turbine is to be rotated through hand barring if the power supply of barring device is not available. Once the power is available, oil pump is to be started and turbine may be put on barring. Cooling water supply is to be restored. A power plant should have an emergency power source from an autostart diesel generator set which will start automatically in case of failure of supply mains. Power to emergency equipments like oil pump, barring gear, stop valve, etc. will be obtained from this emergency source. Failure of barring device:  When turbine is stopped in hot condition, it is to be put on barring. In some situations, just after stopping the turbine, barring gear may be found non-working. It is not recommended to keep the rotor at standstill in this situation. By any means, the rotor is to be rotated. The rotor position may be changed by 180° continuously at some intervals. High condenser hotwell level:  Due to the problem in condensate extraction pumps or any other equipment in the condensate system, condensate cannot be evacuated from the hot well. So, the hotwell level becomes high. Also, due to malfunction of level transmitter, the actual level may go high. In this situation, there is a possibility that water level in the condenser will increase and enter the turbine through exhaust hood. The condenser vacuum reduces drastically in this condition. In case, water enters a running turbine, it creates a serious situation and damages the turbine.

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Turbine should not be allowed to run at high hotwell level or when the level transmitter is not showing the actual level. Load is to be reduced from the turbine in this situation. If the situation is not controllable still, the turbine is to be stopped. To avoid this situation, local hotwell gauge glass must be checked regularly. High axial displacement:  There is a very small axial clearance between the rotating part and the stationary part of a turbine. Rotating part of the turbine is supposed to be placed at exact centre of the clearance of stationary parts. When the rotor centre is changed, it is reflected by the axial displacement. At high axial displacement, rotating part of the turbine may come in contact with the stationary part. So, the turbine must be stopped in case, there is a high axial displacement or axial shift. Leakages:  For the operation of turbine there are different pipelines in which different fluids flow. These are given below:

– – – – – –

Main steam line Auxiliary or motive steam line Cooling water line Condensate line Oil line Air line

In case of failure of flange gasket or damage of pipeline, the fluid conveyed may leak, thereby affecting the turbine operation. In some cases, leakage is so severe that an immediate stoppage of turbine is required. In some cases, turbine may be stopped in a planned way to arrest the leakage. Depending upon the severity of leakage and its effect on the plant operation and safety, action is to be taken. Fire:  Fire is always an emergency situation at any plant. But at turbine, this situation is different. High temperature steam is used to drive the steam turbine and also, a large quantity of lubrication oil is handled. So, there is always a chance of fire. Precaution is to be taken to handle this situation to avoid damage to man and machine. Turbine is operated at higher temperature. So, proper grade fire extinguisher and firefighting equipment are to be used so that the turbine does not get damaged further. Operating personnel working at the turbine are to be trained to use an appropriate technique to extinguish the fire. Fire hydrant lines and fire extinguishers are to be kept ready at proper location. Low steam parameters:  Due to some problem at boiler, the low temperature or low pressure steam may enter the turbine. This is to be avoided. In any case, this low temperature and pressure steam below the permissible limit should not be allowed to enter the turbine. This may damage the turbine internals. Due to high water level in the boiler, priming may take place. Priming decreases the steam temperature as the boiler feedwater enters the steam line. If the turbine is allowed to run in this condition, unsaturated steam enters turbine and damages it severely. Low temperature steam is condensed towards the last stage blade of the turbine. It also produces thermal shock on the hot turbine. In this case, turbine should be stopped immediately.



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High steam parameters:  Like low steam temperature and pressure, high temperature and pressure steam is also not desirable in the turbine operation. High steam temperature may damage the turbine, as the metallurgy of the turbine is designed for a particular temperature. High pressure steam may damage the internal sealing fins, etc. Low condenser vacuum:  Due to the vacuum in condenser, the steam from the turbine is easily exhausted into the condenser. If vacuum inside the condenser drops, it restricts the exhaust of steam. Back pressure is created inside the turbine. Vacuum may drop due to the failure of cooling water system and ejector or leakage in the condenser air line. The standby ejector or starting ejector is to be immediately taken into service. Leakage in the air line should be arrested promptly or the cooling water flow should be increased. If the vacuum is not improved, then the turbine should be stopped immediately. Failure of cooling water system:  Due to the failure of cooling water pumps or chocking in the cooling water circuit, cooling water supply may be reduced or interrupted. In this case, turbine exhaust steam cannot be condensed. Pressure of the condenser increases and the rupture disc of the condenser may rupture. Heavy back pressure is created on the turbine. In this case, load should be reduced first and care must be taken to normalise the cooling water supply. If the situation does not improve, then the turbine should be stopped. Failure of plant automation system:  In some incidences, it is experienced that the plant automation system fails due to the failure of control power supply and DCS or due to some other reasons. In this situation, it is difficult to keep the turbine under control. Neither any parameter is visible nor any control system works. In this case, the turbine is required to be stopped in a safer way. An operation engineer should apply his mind to act accordingly. Nowadays, most of the turbines are designed for fail-safe operation. Turbine automatically trips in case of any malfunctioning or fault in any system.

18.12  LOSSES IN STEAM TURBINE In a steam turbine, the total heat energy input is not converted into mechanical energy. Some losses take place during this conversion process. We can classify these losses into various categories, as discussed here. By identifying these losses, one is able to minimise these losses, as much as possible to increase the efficiency of steam turbine.

18.12.1  External Losses These losses occur outside the steam turbine. These include the following losses: ESV and Strainer Loss There is always a pressure drop in the steam at every valve or restriction. Strainer is provided at ESV to restrict any foreign particle entering the turbine along with the steam. As a result, there is a pressure drop at ESV and strainer, resulting in the loss of heat energy of the steam.

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Throttling Loss at Control Valve Control valve throttles the steam flow to the turbine as per the load demand of turbine. So, it results in the pressure drop. To minimise this loss, instead of a single valve, multiple valves are connected to a common operating lever and placed in such a way so that a particular valve opens at a particular position of the operating lever. Steam enters the turbine through these valves. This is taken care during the design stage of turbine. Exhaust Steam Loss This is the major loss in a steam turbine. A major portion of heat energy is wasted in the condenser which is taken out by the cooling water. The exhaust steam carries out huge quantity of latent heat which is then taken out by the cooling water to condense the steam. Radiation Loss Heat always radiates from the outer casing surface of turbine. So, the turbine outer casing is required to be insulated properly to minimise the radiation loss. Damage of insulation or less thickness of insulating material may increase this loss.

18.12.2  Internal Losses These are the losses taking place inside the turbine. These losses include the following losses: Nozzle Loss When steam travels through a nozzle, loss takes place due to the friction and formation of eddies. Blade Friction Loss Steam glides over the blade in a steam turbine. Due to the blade profile surface finish, this loss takes place due to the friction. Disc or Wheel Friction Loss The moving blade wheel is required to rotate inside the steam in the turbine. Presence of steam produces friction and creates resistance to the moving wheel. Partial Admission Loss As discussed earlier, the control valve is connected in such a way so that the valve opens one after the other to increase the load on turbine. Each valve is connected to a set of nozzles. Figure 18.3 shows partial admission. Due to partial admission of steam, only some sets of nozzles are active and the remaining are inactive. Eddies are produced in active blades and more energy is required to flush the steam in the inactive blades when they came to active. Inter Stage Leakage Loss There is a pressure difference in each blade stage of turbine. Due to the leakage of steam

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Figure 18.3  Partial admission.

between these stages, steam passes to the next stage having lower pressure without doing any work. This loss increases due to the damage of fins at the blade tip and interstage seals. Mechanical Friction Loss Due to friction at bearings, this loss takes place. Heat generated due to friction is carried out by the lubrication oil and cooled at the oil cooler. Residual Velocity Loss The steam exiting from one stage carries a lot of kinetic energy and this is carried to the next stage. If the axial clearance between the stages is more, then some part of this kinetic energy is lost. Wetness Loss When steam passes over different stages, energy is extracted from it. Towards the last stage of blade, the steam becomes wet, carrying water particles. The velocity of water particle is less than that of steam. So, the kinetic energy of the steam reduces.

18.13  HEAT RATE Heat rate is a means to express thermal efficiency of a power plant. Normally, it is expressed in kilocalorie per kilowatt hour (kcal/kWh). Less heat rate means the cycle is efficient. As discussed earlier, regenerative and reheat cycles are used to increase the thermal efficiency and decrease the heat rate of a power plant. Turbine heat rate is the ratio of total energy utilised in the turbine (kcal) divided by the electrical energy output (kWh). Energy utilised in turbine is the difference between energy input to turbine and energy extracted from turbine. Energy input is the steam mass flow rate to the turbine multiplied by inlet steam enthalpy. Energy extracted is the enthalpy of total extraction steam plus the heat available in condensate. Sometimes, terms like gross turbine heat rate, net turbine heat rate and plant heat rate are also used to specify the efficiency of power plant. Heat rate is expressed as either gross or net heat rate depending upon whether the electricity output is gross or net generation.

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Gross Turbine Heat Rate It can be determined by dividing the heat added to the boiler between the feedwater inlet and the steam outlet (inlet of turbine) by the kilowatt output of the generator at the generator terminal. The gross heat rate is expressed in kilocalorie per kilowatt hour (kcal/kWh). For reheat cycle, the heat added to the boiler includes the heat added to the main steam and the reheater. Feedwater heating is done through extraction steam to reduce the heat rate. EXAMPLE 18.1  Calculate the gross turbine heat rate with the help of parameters given in Table 18.1. Table 18.1  Power Plant Parameters Parameter Feedwater Inlet Temperature to Boiler Feedwater Flow (Without Considering Make-up) Steam Generation Steam Pressure Steam Temperature Enthalpy of Steam (at 100 kg/cm2 540 °C) Generator Capacity

Value 150 °C 200 t/hr 200 t/hr 100 kg/cm2 540 °C 830 kcal/kg 50 MW

Heat added to the boiler kilowatt output of generator (Enthalpy of steam - Heat in feedwater) = kilowatt output of generator 200 ¥ 1000(830 - 150) = = 2720 kcal/kWh 50 ¥ 1000

Solution  Gross turbine heat rate =

Net Turbine Heat Rate Net turbine heat rate can be determined same as the gross heat rate except that the boiler feedwater pumping power is subtracted from the generator power output before dividing the heat added to the boiler. Gross Plant Heat Rate Gross plant heat rate (kcal/kWh) is determined by dividing the total heat energy (kcal/h) in fuel added to the boiler by the gross kilowatt output of the generator. Net Plant Heat Rate To calculate the net turbine heat rate, the losses in turbine and generator set are considered. Net plant heat rate also considers inefficiencies and losses external to the turbo generator set. Inefficiencies in the boiler and piping systems, power required for pumps and fans, energy uses for soot blowing, air compression and other auxiliary services are considered to calculate the net plant heat rate.

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Example 18.2  Some power plant parameters are given in Table 18.2. Calculate the gross plant heat rate and net plant heat rate. Table 18.2  Power Plant Parameters Parameter Plant Capacity Coal Consumption at Full Load GCV of Coal Used Auxiliary Power Consumption at Full Load

Solution 

Value 100 MW 70 t/hr 3200 kcal /kg 8 MW

70 ¥ 3200 100 = 2240 kcal/kWh 70 ¥ 3200 Net plant heat rate = (100 - 8) = 2435 kcal/kWh

Gross plant heat rate =

18.14 Best available technology for efficient Power Generation using fossil fuel Electric power is the main source of energy for any industry. Fossil fuel-fired thermal power plants meet most of the power demand of the country. Huge quantity of coal is used at the thermal power plants. A lot of carbon dioxide gas is emitted from the power plants during the burning of coal. Reduction in coal consumption can minimise the carbon dioxide emission. Coal consumption can be reduced by using an efficient technology. Some latest techniques are adopted in thermal power generation sector throughout the world. Some of these best available technologies (BAT) are discussed here.

18.14.1 Combined Cycle Technology A combined cycle power plant employs more than one thermodynamic cycle. Mostly Rankine (steam) and Brayton (gas) cycles are used. Both gas turbine (GT) and steam turbine are used for the power generation. The hot exhaust gas of gas turbine is used as the heat source for Rankine cycle. Gas turbine generator generates electricity and the waste heat from the exhaust gas is recovered in a heat recovery steam generator (HRSG) to produce steam and generate additional electricity through a steam turbine. Gas turbine and steam turbine are connected in different configurations. In a single shaft combined cycle plant, gas turbine and steam turbine are connected in a single shaft to drive a common generator. In a multishaft combined cycle plant, gas turbine and steam turbine have their own generators. Normally, natural gas is used as a fuel in the gas turbine. Sometimes, fuel oil or other gaseous fuels are also used.

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Process of Combined Cycle Power Generation In combined cycle, power is produced by the gas turbine and the steam turbine. In the first step, atmospheric air is compressed in a compressor. Heat is added to this compressed air in a combustion chamber where the fuel is fired. This hot compressed air drives the gas turbine and the coupled generator produces electricity. In the second step, hot gas exhausted from the gas turbine passes through a boiler to produce steam. This boiler is the heat recovery steam generator (HRSG). Steam is used to drive a steam turbine which is coupled with a generator to produce the electricity. The hot gas leaves HRSG at around 140 °C and is discharged to the atmosphere. Roughly, the steam turbine produces one-third of the power and gas turbine produces twothird of the power output. General arrangement of a combined cycle power plant is shown in Figure 18.4.

Figure 18.4  General arrangement of a combined cycle power plant.

A combined cycle power plant mainly consists of the following systems:

• Gas turbine (GT) system • Heat recovery steam generator (HRSG) • Steam turbine system

Gas Turbine (GT) System As discussed earlier, gas turbine runs on Brayton cycle. GT has three main sections that are given below:

• Compressor • Combustion chamber • Turbine

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Atmospheric air is socked and compressed in a compressor. The compressor is connected to the gas turbine through a common shaft. Due to compression, the pressure and temperature of air increase. Further heat is added to the compressed air in the combustion chamber where the fuel is fired. Combustion of fuel increases the gas temperature. This hot compressed gas is forced into the turbine section. The high velocity gas flow is directed through a nozzle over the turbine’s blades. Some of the power developed is utilised to drive the compressor and rest is available to drive a generator coupled with the gas turbine. The pressure and temperature of gas get reduced in the turbine and exhausted from the turbine finally. Figure 18.5 shows the gas turbine arrangement.

Figure 18.5  Gas turbine arrangement.

Heat Recovery Steam Generator (HRSG) A heat recovery steam generator (HRSG) is a heat exchanger that recovers heat from the hot exhaust gas of the gas turbine (GT). It produces steam which is used to drive a steam turbine. Steam is produced at HRSG like any other fired-boiler system. HRSG is like a normal boiler but without any firing furnace. Heat transfer surfaces consisting of bundle of water or steam carrying tubes are placed in the hot gas path. Like a normal boiler, HRSG is also having an economiser, evaporator and superheater for the generation of steam. There is a drum for natural circulation of water. Superheated steam produced at HRSG is used in a steam turbine for additional power generation. Sometimes, burners are fixed in the duct of HRSG. These additional burners provide additional energy to HRSG which produces more steam to increase the output of steam turbine. HRSGs are categorised as single pressure or multipressure. A single pressure HRSG has only one steam drum and the steam is generated at a single pressure level. This steam is used

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in a single pressure turbine. Whereas, a multipressure HRSG has two (double pressure) or three (triple pressure) different steam pressures to drive HP, IP and LP turbines. Each section has a steam drum and an evaporator section for steam generation. This steam then passes through the superheaters to raise the temperature and pressure. HRSG has a diverting damper to regulate the inlet gas flow into the HRSG. This arrangement allows the gas turbine to continue to operate when there is no steam demand. Steam Turbine System Steam turbine is already discussed in the earlier chapters. A steam turbine system also serves as a part of a combined cycle power plant.

18.14.2  Supercritical (SC) and Ultra Supercritical (USC) Technologies Efficiency of steam turbine increases by increasing the superheat steam temperature. So, a lot of research and development programs are under progress to use the high temperature steam for thermal power generation. Depending upon the inlet steam condition, thermal power plants are classified as subcritical, supercritical and ultra super critical units. Mostly, the units operated at the steam pressure below 225 kg/cm2 are called subcritical units. The units operated at the steam pressure above 225 kg/cm2 and superheat/reheat temperature upto 593 °C are called supercritical units, whereas the units operated at the pressure above 225 kg/cm2 and superheat/reheat temperature more than 593 °C are called as ultra supercritical units. The net plant efficiencies (LHV basis) of subcritical, supercritical and ultra supercritical units are given below:

• Subcritical units • Supercritical units • Ultrasupercritical units

38%–40% 40%–42% 43%–46%

Now, it is possible to use the high temperature steam upto 620 °C due to availability of modern chromium and nickel-based superalloy material (T91 and P91). Many supercritical units are in operation worldwide for quite a long period. The world’s first supercritical unit [Philo 6 power plant in USA (125 MW)] was commissioned during 1957 and was in operation till 1979. Large supercritical units of 1300 MW capacity are in operation at Japan and USA since 1970 (TVA Cumberland Power Plant). Most of the supercritical and ultra supercritical units are operated on pulverised coal (PC) technology. Also, the supercritical units are available based on CFBC technology. The world’s largest and first once through unit (OTU) supercritical CFBC boiler of 460 MW capacity was commissioned during 2009 at Lagisza power plant in Poland. Supercritical technology is proven internationally for many years. It is experienced that the availability of supercritical units is more than that of subcritical units. With inlet steam pressure of around 250 kg/cm2 and superheat/reheat temperature of 566 °C or 592 °C, heat rate as low as 1815 kcal/kWh is possible in a supercritical unit. Ultra supercritical units are in operation in Japan, Denmark, Germany and China. Efficiency of these units is still higher. So, many 1000 MW ultra supercritical units with steam parameter

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of 260 kg/cm2/600 °C/600 °C and tandem compounding, four-casing, four-flow type turbine are under operation in China. Benefits of supercritical (SC) and ultra supercritical (USC) power plants are as follows:

• • • • •

Less fuel consumption due to higher plant efficiency Less CO2 emission Better availability Less NOx, SOx and particulate emissions Possibility of larger unit size

Some of the well known international suppliers of supercritical/ultra supercritical boiler and turbine sets are listed in Table 18.3. Table 18.3 Some International Suppliers of Supercritical or Ultra Supercritical Boiler and Turbine Sets Supplier Alstom Mitsubishi Hitachi Toshiba Ansaldo Doosan Siemens GE SEC Dongfang Harbin

Country France Japan Japan Japan Italy South Korea Germany USA China China China

18.15 NEXT GENERATION EFFICIENT TECHNOLOGY FOR THERMAL POWER GENERATION Internationally, coal is the main fuel source with around 44% contribution of the total power generation. Despite of the advancement in efficiency in operations, half of the total coal reserve has been consumed in last two decades. We are using coal from the beginning of Industrial revolution and the rate of consumption is growing continuously. The reserve production rate of coal is estimated as 122 years. With the current average, 5% growth in consumption rate per annum would reduce it further. So, it is very essential to adopt a more efficient technology for thermal power generation using fossil fuel. This technology will not only use lesser coal per unit of power but also reduce the green house gas emission. About 0.95 t carbon dioxide gas is emitted per megawatt hour of electricity generation. To cut the greenhouse gas emission, strict emission norms are adopted by the developed countries. As thermal power plants emit a lot of greenhouse gases, so it is focused to minimise the carbon dioxide gas emission from the thermal power plants by using an efficient technology. Following are the two prospective efficient technologies which can resolve the above problems to some extent:

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• Advanced ultra supercritical technology with steam temperature greater than 700 °C (with PC technology and Rankin cycle ) • Integrated gasification combined cycle (IGCC) technology (with combine cycle technology)

18.15.1 Advanced Ultra Supercritical (AUSC) Technology with Steam Temperature Greater than 700 °C The steam temperature in the latest ultra supercritical (USC) power plant is 620 °C with an efficiency of around 46%. So, many power plants are in operation globally with this steam parameter. This is a proven technology now and it has been adopted widely. To minimise the greenhouse gas emission and fuel consumption per unit, the power producers are trying to increase the efficiency further by increasing the steam temperature to the next higher range. After confidence in USC power plants, the next target of the world’s power producers is to develop a 700 °C steam power plant which operates on PC technology with an expected efficiency of around 50%. This technology will not only reduce the coal consumption but also reduce the CO2 emission. The main challenge is to develop heat-resistant steel for the steam turbine components, headers, pipelines and boiler tubes which can withstand 700 °C or higher steam temperature. The new material should demonstrate creep rupture strength of at least 100 N/mm2 over 100,000 hours of operation. The technical feasibility of a 700 °C steam power plant depends on the successful development of advanced alloys. The main prospective material for this is nickel-based alloy, as it possesses high creep rupture strength. Development of new Ni-based superalloys is in final stage and under testing. These materials will be used for the following main components:

• • • • •

Furnace panel Superheater Reheater Header and steam pipelines Turbine rotors, casings, valve and bolts

A lot of research and development works are going on worldwide to take the temperature level of steam more than 700 °C with an efficiency of more than 50% and PC-fired technology. Following projects are under operation for this:

• AD700 and COMET700 project by EU • Green Earth 50 + Project by Japan • DOE initiated project by USA

Advanced (700 °C) PC power plant or AD700 project is financed by European Union and Swiss government. The main target of this project is to develop an advanced supercritical water/ steam cycle to increase the steam temperature from 700 °C to 720 °C range and the main stream pressure from 350 bar to 375 bar range. The net efficiency is expected in the range of 50%–51% for a power plant with a single reheat cycle and 53%–54% for a double reheat cycle. Also, a lot of research work is going on in USA, Japan, China and India to make the dream into reality in the near future.

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Following prospective materials are under development and testing for this project:

• • • •

Inconel® alloy 740 Haynes® 230 alloy and Haynes® 282 alloy CCA617 An alloy named as Super 304H

The pilot plant is under implementation. Very shortly this technology will be commercialised internationally.

18.15.2  Integrated Gasification Combined Cycle (IGCC) Technology IGCC is an alternative technology to generate the power efficiently as compared to the currently available PC-fired technology. IGCC plant uses a gasifier to convert coal or any solid fuel into synthesis gas or syngas which is used for power generation by the combined cycle technology. Biomass fuel can also be used here. Gasification is the process of converting coal to a gaseous fuel through partial oxidation. In gasifier, coal gasification takes place in a controlled, shortage of air/oxygen or oxygen-lean environment. Solid coal is converted into a flammable mixture of carbon monoxide (CO) and hydrogen (H2). Combustion products produced by the main fuel constituents in combustion and gasification are given in Table 18.4. Table 18.4  Combustion Product Produced by Fuel Constituents in Combustion and Gasification Constituent

Combustion Product

Carbon Hydrogen Nitrogen Sulphur Water

CO2 H 2O NO, NO2 SO2, SO3 H 2O

Gasification Product CO H2 HCN, NH3 or N2 H2S or COS H2

Depending upon the oxidant supplied for the gasification of fuel, gasifiers are classified as follows:

• Air-blown gasifier • Oxygen-blown gasifier • Oxygen-enriched air-blown gasifier

In oxygen-blown gasifier, an air separator is used to separate the oxygen from air before feeding to the gasifier. This requires high initial capital and operating cost and it consumes a major portion of auxiliary power. A high calorific value syngas is obtained from this gasifier, as excessive air or nitrogen is not added to the gas. The main advantages of oxygen-blown gasifier are given below:

• The size of gasifier is smaller and hence, the cost is lesser. • Calorific value of syngas is more in this case.

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• The volume of syngas is lesser as compared to an air-blown gasifier for the same amount of coal gasification. • Smaller unit is required for gas handling, cleaning and heat exchanger to recover heat from the syngas before cleanup.

Air is cheaper than oxygen. But, in this case, nitrogen present in the air increases the volume of syngas per ton of the fuel and the calorific value of syngas is less in this case. So, an air-blown gasifier is physically bigger and the calorific value of the produced gas is less. In some gasifiers, oxygen-enriched air is used. A smaller-sized air separation unit is required for this. This unit separates oxygen from the air and mixes it with oxidant air. Steam is added to air/oxygen which also acts as an oxidant at higher temperature. Broadly, IGCC consists of two main systems that are given below:

• Coal gasification system • Combined cycle Of these two systesm, the combined cycle has been already discussed in Section 18.4.1.

Coal Gasification System Coal gasification system has following sections: Coal preparation:  The first process done in a coal gasification system is the coal preparation. Details of this process have been already discussed in Chapter 7. Coal gasification:  In different types of gasifiers, different size of coal is used. So, before feeding the coal into gasifier, a proper size coal is required to be prepared. In entrained flow gasifier, pulverised coal or coal slurry is used, whereas in fluidised bed gasifier, around 6 mm coal is required. So, coal preparation plant is required at upstream of gasifier. There are three types of gasifiers used for the coal gasification in IGCC plants. These are given below: Fixed bed gasifier:  Fixed bed gasifier is like a blast furnace. Coarse coal particles are placed on the top of a bed in a refractory lined vessel. The coal moves down in the vessel by gravity. The oxidant (steam and oxygen/ air) moves in the opposite direction of coal going upward through the bed. On moving downwards, the coal is gradually heated and contacted with an oxygen-enriched gas flowing upwards. The temperature at the top of the bed is around 450 °C and at the bottom, approximately 1200°C. The entire mineral matter of coal melts and is collected as slag. Residence time of fixed bed gasifier is more. Due to more residence, it has lower output and is not suitable for large size IGCC plant. A fixed bed gasifier is shown Figure 18.6  Gas fixed bed gasifier. in Figure 18.6.



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Entrained flow gasifier:  Fine coal either in dry or in slurry form is used in this gasifier. Dry pulverised coal or fuel slurry and the oxidant (air or oxygen) along with the steam are fed into the gasifier vessel at the top. Fuel and oxidising gas flow co-currently. Coal particles are surrounded or entrained by the oxidant as flow through the gasifier. Residence time is short and high output is possible in this gasifier. Gasification takes place at a temperature range of 1400 °C–1500 °C. Major part of the ash is removed as slag, as the operating temperature is more than the ash fusion temperature. This gasifier can either be oxygen or air-blown. Figure  18.7 shows an entrained flow gasifier.

Figure 18.7  Entrained flow gasifier.

Fluidised bed gasifier:  A fluidised bed gasifier works on the principle of fluidisation. Small particle size (< 6 mm) coal is normally fed to the vessel from the side. Steam and oxidant enter from the bottom with sufficient velocity to fluidise the bed. The whole bed exhibits fluid-like behaviour. In this gasifier, the rising oxygen-enriched gas reacts with the suspended coal at a temperature of 950 °C–1100°C. The operating temperature is usually less than the ash fusion temperature. So, clinker formation and the possibility of defluidisation of the bed are avoided. Figure 18.8 shows a fluidised bed gasifier.

Figure 18.8  Fluidised bed gasifier.

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Gas cooling:  It is difficult to clean the hot gas. So, before entering the cleaning and purification section, the gas is required to be cleaned. For cooling of the hot syngas, gas cooler is used where heat is recovered from the hot syngas. Raw hot gas leaving the gasifier is cooled in a membrane water wall type heat exchanger and saturated steam is generated. This steam is sent to the HRSG of combined cycle for superheating and reheating. Gas purification/cleaning:  For using syngas in a gas turbine, it should be thoroughly cleaned in a series of cleanup steps. Particulates are removed by dry processes such as a cyclone and rigid barrier filter or by wet processes such as a venturi scrubber. Other undesirable particles like H2S, COS, HCN, NH3, HCl and mercury vapour are removed from the gas by adopting suitable technologies. Process of IGCC Power Generation Integrated coal gasification combined cycle (IGCC) power plant is the most environment friendly coal-fired power generation technology. It also produces power efficiently. So, the development of this technology will provide an efficient power generation in an environment-friendly way. Greenhouse gas emission can be minimised by adopting the carbon capture technology. The entire process of IGCC (Figure 18.9) is summarised below:

  Figure 18.9  Process of IGCC power generation.

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• Coal is fed into a gasifier along with the steam and limited amount of oxygen where it is partially oxidised and gas is produced. The gas is known as synthesis gas or syngas and mainly consists of carbon monoxide and hydrogen. Temperature of this gas is between 500 °C to 1500 °C depending on the type of gasifier used. • This hot and unclean gas leaving the gasifier is cooled in a syngas cooler. The heat is recovered by water circuit. • Undesirable components like sulphide, nitride, tar, ammonia, halogen, alkalis, particulates and other pollutants are removed by various technologies. • The clean gas is used in a gas turbine to generate power as per the process discussed earlier. • Waste heat from the gas turbine is recovered in a HRSG to produce steam. • The steam produced at HRSG is used to drive a steam turbine for additional power generation.

Advantages of IGCC

• Thermal efficiency is higher as compared to the conventional coal-fired thermal power plants and is more than 50%. • It can utilise a variety of fuels like heavy oil, petroleum coke, coal and biomass. • Upto 100% of the carbon dioxide can be captured from IGCC. • Nitrogen oxide (NOx) emission is lower than that of the conventional coal-fired power plant. • It is much easier to remove sulphur and mercury.

18.16  SCENARIO OF POWER GENERATION INDUSTRY IN INDIA The installed capacity of coal-fired thermal power plants in India is 98403.38 MW (as on 31 July 2011) which is around 54.55% of the total installed capacity. Per capita power consumption in India is 733.54 kWh per year which is very less as compared to the global average of 2340 kWh per year. Still, the power demand is not fulfilled and a lot of initiatives are taken by the government of India to add more power generating facilities in the coming days. So, many single reheat type subcritical units upto 500 MW are in operation in India with steam parameters of 170 kg/cm2/537 °C/565 °C [inlet pressure (kg/cm2)]/superheated temperature (°C)/reheat temperature (°C)]. To operate Indian thermal power plants at higher efficiency, supercritical units are planned. India’s first supercritical unit (660 MW) was commissioned during December 2010 by Adani power at Mundra (Gujrat) with steam parameter of 25.4 Mpa (259 kg/cm2/571 °C/569 °C). So, many 660 MW supercritical units are commissioned after that. First 800 MW supercritical unit was commissioned in India by TATA Power during March 2012. India is planning to adopt ultra supercritical units (280 kg/cm2/600 °C/620 °C) of 660 MW and 800 MW. In India, following suppliers/joint ventures (JV) have planned to set up supercritical boiler and turbine manufacturing facilities in the country:

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Bharat Heavy Electricals Ltd (BHEL) L&T-MHI Boilers Pvt. Ltd. Alstom Bharat Forge-Power Ltd. (ABFPL) Gammon India - Ansaldo Toshiba JSW Turbine and Generator Pvt. Ltd. Thermax- Babcok & Wilcox Energy Solutions

For efficient and environment-friendly operation of Indian thermal power plants, initiative has been taken by the government of India to increase the operating steam temperature more than 700 °C. To achieve this, BHEL, NTPC and Indira Gandhi Centre for Atomic Research are jointly working to develop an advanced ultra supercritical boiler for coal-fired power plant to operate at a steam temperature of 700 °C. It is expected that India can have this technology by 2017. BHEL commissioned a demonstration coal-based IGCC power plant in 1982. One 125 MW IGCC plant is proposed by Andhra Pradesh Power Generation Corporation Ltd in association with BHEL. NTPC is also planning for IGCC plants. Very shortly, some IGCC plant will be in operation in India.

18.17  CAPACITY SELECTION OF GENERATING SETS Other than IPP surplus power of captive power plants (CPPs) is used to meet the energy demand of a country. Small unit size captive thermal power plants are installed in industries which supply power for captive use. These units are small in capacity and mostly, the unit capacity is selected depending upon the power demand of the industry. Government has taken initiatives for trading of power by CPP’S through open access. Electricity act 2003 and Electricity rule 2005 are made accordingly. For sale of excess power of captive power plants, power trading exchange (PXI) is providing platform for online trading of power of CPPs. So, many CPPs are coming forward and increasing their generation capacity to earn revenue in the power market. Selection of the unit capacity of a power plant (IPP or CPP) is very critical. Project cost of thermal power plant is very high. So, capacity of the plant should be selected carefully. Following cases can be considered while selecting the unit size of any power plant. Case 1:  Economical Maximum Continuous Rating (EMCR) This is the design rating of the set on which an optimum heat rate of the set is obtained. EMCR of the generating set is decided based on the continuous load demand. Normally a turbine is designed to deliver guaranteed performance at the designed parameters on continuous basis at EMCR. Heat rate in this case is lowest. This is also called rated capacity. In most of the cases, the set is operated at this load. Case 2:  VWO-Normal Pressure (VWO-NP) Rating Each turbine is designed with some inherent margin to take care of future degradation. The inherent design margin should not remain unutilised throughout the life of a plant. To get

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a better payback and to have some additional power generation, this inherent design margin can be utilised to generate some additional power with very little additional investments. Around 5% design margin is kept to allow some extra steam to flow through the turbine when the control valve is fully opened. This extra flow is called valve wide open (VWO) flow. At design steam parameters, this 5% VWO flow can be utilised to generate approximately 105% of the EMCR power. In this condition, a turbine may be designed for continuous operation to meet any additional power requirement in future or during peak load hours. At this generation level, set performance is predicted but it is not guaranteed. Normally, the boiler maximum continuous rating (BMCR) is designed to support VWO flow of the turbine. In normal engineering practice, 2% margin above VWO flow of TG is considered for BMCR. Case 3:  VWO–Over Pressure (VWO-OP) Rating A turbine is designed to operate at approximately 105% of the normal pressure. This inherent design margin can further be used to generate around 5% more power at VWO flow. So, around 110% of the rated power can be generated at VWO-OP condition. Set can be design to run on this load for short duration during emergency. Performance of the set is predicted at this load. To meet this load, boiler BMCR is not required to be increased, as VWO flow is not changed. Normally, inherent boiler margin can be used so that the boiler is able to generate steam at 5% overpressure. CHP, AHP and other auxiliary systems may be designed to support VWO-OP condition considering the worst coal.

EXERCISES

1. What care is taken while charging a steam pipeline and why? 2. What precaution is to be taken to start barring operation of a turbine? 3. What is the function of hogger ejector and what sequence is to be followed to charge the main ejector? 4. Define cold start-up and hot start-up of a turbine. 5. What is a turbine start-up curve? 6. What is the critical speed of a turbine? 7. What are the main emergency conditions of a steam turbine? 8. Why is low inlet stem temperature not recommended in a steam turbine? 9. Why is the overspeed of steam turbine so dangerous? 10. What action should be taken when the barring device fails? 11. Why should the turbine be stopped in case of low vacuum? 12. Why is the high condenser hotwell level so dangerous? 13. What precaution is taken to reduce the throttling loss at control valve? 14. What is interstage leakage loss and when does it happen? 15. What is gross turbine heat rate and how is it calculated?

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16. What is gross plant heat rate and how is it calculated? 17. What is combined cycle technology? 18. What is the function of heat recovery steam generator (HRSG) in a combined cycle power plant? 19. What are the three sections of a gas turbine (GT)? 20. What is the function of HRSG in a combined cycle power plant? 21. What are the approximate efficiencies of subcritical, supercritical and ultra supercritical power plants on LHV basis? 22. What is the difference between supercritical power plant and ultra supercritical power plant? 23. What are the benefits of SC and USC power plants? 24. How much carbon dioxide gas is generated per megawatt hour of power generation in thermal power plants? 25. What is the process of IGCC power generation? 26. What is steam turbine VWO condition? 27. What do you understand by BMCR and EMCR?

Chapter

19

Generator

19.1  INTRODUCTION Generator is an important machine for power generation. The main aim of any power plant is to generate power. Boiler and turbine are used ultimately to drive the generator and generate power. A generator is coupled with turbine and converts mechanical energy of turbine into electrical energy. This electrical energy is distributed to various load points through transmission and distribution network. Generator works on a very fundamental electrical principle called Faraday’s law of electromagnetic induction, discovered by Michael Faraday in 1831. When a stationary coil is placed in a rotating magnetic field, the magnetic flux produced by the magnet is cut by the coil and an electromotive force (EMF) is induced in that coil. As per this law, d FB dt here, E is the electromotive force (EMF) in volts and FB is the magnetic flux in webers. Direction of electromotive force (negative sign in the above formula) is given by Lenz’s law. In a generator, rotating field magnet is created at the rotor through DC power source. The rotor is coupled to the shaft of the turbine. So, voltage is induced in the stationary coils placed at the stator of the generator. The stationary coil is wound to generate three-phase power. The schematic diagram of a simple generator is shown in Figure 19.1. E=-

Figure 19.1  Sunoke generator. 399

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19.2  IMPORTANT PARTS OF A GENERATOR Like any other equipment, generator has some important parts. Each part performs a specific function. Some of the important parts of a generator are cylindrical rotor, stator, bearings and enclosure. These are discussed here.

19.2.1  Cylindrical Rotor Rotor and stator are the main parts of a generator. Rotor is placed inside the stator. The air gap in between stator and rotor is very less. In power generators of thermal power plants, cylindrical rotor is used. This type of rotor is also called non-salient or drum type rotor. Rotor of the generator carries field winding. When DC power supply is applied to this winding, it becomes magnetic. Rotor also carries a fan which circulates cooling medium inside the generator to cool down the generator. The design of a rotor is critical, as the field winding is put inside the slots provided and it has to rotate at a speed of normally 1500 rpm or 3000 rpm. Also, the mass of a rotor is high. Normally, cylindrical rotors for two or four-magnetic pole design are used for the generation of power at power plants. The number of poles of a rotor depends upon the speed of the generator. P = 120 f /N

where P = number of poles f = frequency N = Speed of the generator (rpm)

In India, the frequency of power generation is 50 Hz. So, for 1500 rpm generator, there are four poles and for 3000 rpm generator, there are two poles in the generator rotor. The main components of the rotor are listed below:

• • • • • •

Shaft Rotor core Field winding Damper winding Fan Slip ring

Shaft The shaft of rotor is so designed that it can carry both static and dynamic load of the total rotor unit. Shaft is coupled to the turbine shaft directly or through a reduction gear. It also carries slip ring or exciter unit (in case of brushless excitation). Permanent magnet generator (PMG) is also coupled to the rotor shaft. This heavy rotor is supported at both the ends through journal bearings. Rotor shaft is designed to carry a rotor core and a fan.

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Rotor Core The core of the rotor is made of low loss dynamo grade laminated steel sheet. The laminations are insulated to minimise the circulation of eddy current produced in the rotor body. Core is made by stacking circular sheets. Slots are made on this sheet to accommodate the field winding and the damper winding. Holes are made for ventilation of the rotor core (Figure 19.2). Core is magnetised when DC supply flows in the field winding.

Figure 19.2  Rotor core.

When rotor rotates, then due to the centrifugal force, stress is developed on the core. So, the core laminations are properly fitted to the shaft. The insulated laminated core sheets are stacked properly and fastened rigidly. Field Winding Prefabricated and properly shaped field coils are inserted into the slots provided at the rotor core. Windings are placed rigidly in the slots with suitable wedge packing so that during rotation, the winding would not come out due to centrifugal force. Field winding is properly insulated with suitable grade of insulation to have a better insulation between the interturns of field winding as well as between the winding to the rotor body. End terminals of the winding are connected to get a desired number of poles and brazed properly. Two terminals are taken out from the winding for DC supply. In case of brushless excitation system, these terminals are connected directly to the rotating diodes. Otherwise, these are connected to the collecting slip rings mounted on the rotor. The overhang portion of the winding at both ends are supported strongly to have enough mechanical strength to avoid distortion. Damper Winding Damper winding is provided to minimise the oscillation effect of a rotor in case of load change on the generator. Solid bars are placed at the damper winding slots. This winding dampens out any oscillation that might be caused by a sudden change in the load. Fan To circulate cooling air or cooling medium (hydrogen) inside the generator, two fans are provided at both ends of a rotor. Profile of the blade is so made that it sucks cold air when

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rotates. This cold air enters from both ends and exhaust from the middle of the generator to avoid any hot zone. Slip Ring To supply field current to the field winding, slip rings are provided. Slip rings are mounted on the rotor. Field winding terminals are connected to these slip rings. DC supply is given to these slip rings through a set of carbon brush. In brushless excitation system, slip rings are not provided. Field supply is given through rotating diodes in this case.

19.2.2  Stator Stator is a critical part of a generator which carries the main winding in which voltage is generated. As this winding is stationary, so it is easier to insulate. High voltage upto 33 kV can be generated in this stator winding. Like rotor, stator has also some important components that are as follows:

• • • •

Yoke Stator core Stator winding Terminals

Yoke Yoke serves as a frame on which the stator core is fitted. It provides support to the stator core and is fixed to the base frame. Stator Core Like rotor core, stator core is also made from laminated low loss dynamo grade steel. Laminated sheets are cut in the required shape to form a circular core. Like rotor, this is not a single piece. Slots are cut in these sheets to accommodate the stator coil (Figure 19.3). A suitable opening is made in the core for free circulation of cooling medium.

Figure 19.3  Stator core.

Stator Winding This is the winding on which power is generated. So, heavy thick prefabricated and preshaped copper windings are placed in the stator core for three-phase power generation. As heavy current



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flows, so stator winding is made of thick copper flats and are connected in parallel. Still, a lot of heat is produced due to losses (I2R or copper loss) in the winding. It is required to cool the winding with the help of cooling medium. Mainly, the close circuit air or hydrogen system is used for cooling. Overhang portion of the winding at both ends are rigidly supported with the help of insulated spacers to avoid deformation in case of heavy fault condition. Stator coil is properly insulated with suitable grade of insulating material and the coil is rigidly placed with the help of wedges on the slot. RTD sensors are placed at different locations inside the stator winding to measure the winding temperature. End connections of stator winding are suitably brazed to get three-phase output. Terminals All the six terminals of the winding (two for each phase) are obtained by suitable connection. These six terminals are placed in a separate terminal box from where it can be taken out further.

19.2.3  Bearings The heavy rotor of the generator is supported by two journal bearings. These bearings have to carry the total load of the rotor at static and dynamic condition. So, the bearings are designed accordingly. Oil is supplied to the journal bearings through lubrication oil supply line like turbine bearings. A thin oil film is created when the rotor rotates. To avoid oil leakage from the bearings, metallic labyrinths are provided. The bearings are fitted at two bearing pedestals. While rotating inside a magnetic field, eddy current is produced on the shaft. If this current is allowed to flow through the bearings, it will damage the soft babbit material of the bearings. To avoid this situation, one bearing is completely electrically isolated from the earth. Oil pipeline, fixing bolts and bearing pedestal of that bearing is insulated suitably by placing an insulating material in between. Other end of the shaft is earthed through a carbon brush. RTDs are fitted in the bearings to measure the bearing temperature and vibration probes are fixed to monitor the vibration.

19.2.4  Enclosure The generator is enclosed properly to protect against live and rotating parts, ingress of foreign bodies as well as to guide cooling medium and minimise the noise. This enclosure is made of rolled steel plates. It is fitted to the base frame and covers the entire stator of the generator. A suitable arrangement is made in the enclosure to guide the cooling medium to get an efficient cooling of the generator without any hot spot. In case of spark or flashover inside the generator, there is a chance of fire, as some combustible insulating material is used in the generator. In bigger size generators, smoke detectors are provided to detect any smoke inside the generator to avoid damage of generator due to fire. Signal from smoke detector is used to open a carbon dioxide line valve so that CO2 would be flooded inside the generator to extinguish the fire, if any.

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19.3  COOLING SYSTEM OF GENERATOR As high current flows in the stator winding and rotor winding, losses take place in the generator. These losses vary with the load and hence, the current of the generator. A major contributor of the heat produced is copper loss and is equal to I2R. Here, I is the current and R is the resistance of winding. This loss is converted into heat. Also, loss due to mechanical friction and windage takes place. Eddy current loss also contributes towards the heating of generator. To run the generator continuously at higher load, this heat is required to be taken out to save the generator from overheating. Insulation of generator is designed to withstand some limited temperature. Maximum withstanding temperature of some of the widely used class of insulation, as specified by National Electrical Manufacturers Association (NEMA) considering ambient temperature as 40 °C, are mentioned below: Class Class Class Class

A B F H

105 130 155 180

°C °C °C °C

Cooling of generator is an important function. If the generator efficiency is 99%, then balance one percent loss contributes to produce a significant amount of heat. For cooling of generator, closed system cooling method is adopted. The cooling medium may be air or hydrogen depending upon the size of generator. Here, the closed system air cooling and the closed system hydrogen cooling are discussed which are mostly used in the power plants.

19.3.1  Closed System Air Cooling In this system, fixed volume of air is circulated inside the generator. Fans fitted at the rotor sucks air from a closed system. This air is canalised through the air gap, rotor air path and stator air passages, thereby gaining the heat. It is guided in such a way so that the hot air coming out is passed over a cooling coil. Again, this cold air is circulated in the generator with the help of a rotor fan. Cooling water is circulated in these cooling coils. Cooling water flow in these coils is regulated depending upon the temperature of the stator coil. In this system, air is circulated in the closed system. Hence, dirty atmospheric air is not allowed inside the system. So, deposition of dust inside the generator is avoided. The generator internal remains clean. As moist air is not used, so insulation level of generator is maintained high. Depending upon the size of generator and the volume of air to be circulated, this cooling system is designed.

19.3.2  Closed System Hydrogen Cooling Heat produced due to I2R loss is more in bigger size generators. To take out so much heat, huge volume of air circulation is required and thus, the system becomes uneconomical. So, for large size turbo generators, hydrogen is commonly used as a cooling medium in a closed circuit rather than air.

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Due to following advantages, it is suitable to use hydrogen in place of air for cooling of bigger size generator:

• The heat transfer capability of hydrogen is seven times that of air. • Lesser amount of hydrogen is required to cool the generator. So, hydrogen cooling system is very compact. • Hydrogen has a density of 1/14 of that of air. So, less energy is required to circulate hydrogen. • In hydrogen environment, the life of insulation increases and the maintenance cost goes down because of the absence of dirt, moisture and oxygen. • It is easy to detect by hydrogen sensors. • The hydrogen–air mixture does not explode so long, as the air contents are less than 30%.

Hydrogen gas is circulated inside the generator in a closed loop by fans at the ends of the generator rotor to absorb heat from the stator and rotor. Then, it is cooled in a gas to water heat exchanger. The heat absorbed by hydrogen gas is transferred to water in the cooler. Cooled hydrogen is recirculated back to the generator in a continuous cycle. Presence of moisture is not desired in hydrogen. It causes deterioration in hydrogen cooling properties, corrosion of the generator parts, arcing in the high voltage windings and reduces life of the generator. A desiccant type dryer is usually installed in the gas circulation loop to keep the hydrogen dry. A probe is installed at the dryer’s outlet to measure the moisture level. Though hydrogen does not support combustion, still explosion may took place when mixed with air and exposed to an ignition source. If the purity of hydrogen is maintained at a very high level or there is very little or no air in the generator casing to mix with the hydrogen, then this problem can be avoided. It is required to prevent the contamination of highly pure hydrogen with the air. So, air is displaced from the generator casing before filling it with highly pure hydrogen. While filling the generator with hydrogen, air is first purged from the generator by CO2 and then, CO2 is purged by hydrogen. For degassing the generator for shutdown, hydrogen is first displaced by CO2 and then, CO2 is purged by air. A hydrogen gas analyser is usually installed to monitor the hydrogen purity. Hydrogen pressure inside the generator is kept higher than the atmospheric pressure so that the atmospheric air cannot ingress into the hydrogen cooling system. The frame of the generator is tightly sealed to prevent hydrogen leakage. Oil seals are installed on the shaft at each end of a hydrogen-cooled generator to keep the hydrogen gas inside the generator. Oil is used as the sealing medium. The seal oil is at a higher pressure than the hydrogen inside the generator casing. Lubricating oil that is used for the bearings is used as a seal oil. There is always a small amount of hydrogen loss in the seal oil through minute leaks. A pressure regulator is used to admit some additional hydrogen from the supply system to maintain the hydrogen pressure. Hydrogen is often produced at the plant site. It is a very safe practice, as the storage of compressed hydrogen is not required.

19.4  EXCITATION SYSTEM As discussed earlier, DC supply is required to be given to the field winding of a generator. This DC supply is obtained from various sources. Supply of DC power to the field is called excitation. Depending upon the sources of supply, generators are classified as folllows:

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• Separately excited generator • Self-excited generator

In a separately excited generator, DC supply to the generator field is obtained from a separate source which has no connection with the generator’s own generated supply. This type of generator is not used in the power plants. In a self-excited generator, DC supply to the field is temporarily given from the other source. Once the voltage is built up in the generator, this source is changed into the generator’s own generating supply. In this system, field supply is obtained either from an excitation transformer or from an exciter mounted on the generator shaft. In the subsequent sections, these two methods of excitation for self-excited generators are discussed.

19.4.1  Field Supply from Excitation Transformer or Static Excitation System In static excitation system, a temporary DC supply is given to the generator field. It is called field flushing. Normally, this supply is obtained from an external battery bank. Once some voltage is generated in the generator, this source is cut off automatically and the field supply is changed to own generation of the generator. The main supply for excitation is obtained from an excitation transformer which steps down the generated voltage to the field voltage level. Then, it is rectified with the help of a thyristor bridge and supplied to the field winding of generator for excitation. This excitation transformer is connected to three-phase outgoing bus of the generator and located before the generator circuit breaker. So, field supply is available even if the generator breaker is in off condition. Thyristor output is supplied to the rotor through a set of slip ring and carbon brush. Figure 19.4 shows a static excitation system.

Figure 19.4  Static excitation system.

Excitation transformer is normally an air-cooled transformer connected to each phase. This type of design was used few years back. Nowadays, exciter is widely used in place of exciter transformer.

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19.4.2  Excitation Through Exciter Generator or Brushless Excitation System In this system, a small generator, called exciter, is mounted on the generator shaft. Exciter generator arrangement may be with brush-like static excitation system or brushless. In some designs, the output of the exciter generator is rectified like static excitation system and power is supplied to the field winding through slip rings. Nowadays, mostly, brushless excitation of system is used. In this arrangement, exciter generator is used which is a small generator having rotating coil and stationary field. This arrangement makes the excitation system brushless. No brush is required to feed the field current to the main generator. So, it is maintenance-free and more reliable. As discussed earlier, field of the exciter generator is stationary and the coil is rotating. Voltage generated in the rotating coil is rectified through a set of rotating diode bridge. Rotating diodes are mounted on an insulated base. Rectified output of this rotating diode bridge is connected to the field winding of the main generator (rotating) through cable which passes through drill way made in the shaft of generator. Supply to the stationary field of the exciter generator is obtained from an automatic voltage regulator (AVR). A separate source or a permanent magnet generator (PMG) is used for obtaining power supply for AVR. For cooling of this exciter, cooling medium of the main generator is used. Figure 19.5 shows a brushless excitation system.

Figure 19.5  Brushless excitation system.

19.5  Automatic voltage regulator (AVR) AVR system of a generator controls the output voltage of the generator automatically, irrespective of any load on the generator. By raising or lowering the field current (excitation), the output voltage of the generator can be raised or lowered respectively. Raising or lowering of field current is done with the help of an AVR. When load on a generator increases, its output voltage drops. By raising the field current, voltage can be raised to the normal level. Like this when,

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the load on generator reduces, the voltage of generator increases. In this case, field current is required to be reduced. AVR controls voltage of the generator in the same way as governor controls the speed of turbine. AVR is a PID controller which gets feedback from the generator output voltage through a potential transformer (PT) and generator current through a current transformer (CT). Accordingly, an error signal is produced which controls the firing of thyristor to control the field voltage. Simple block diagram of an AVR with exciter transformer is shown in Figure 19.6.

Figure 19.6  AVR arrangement in static excitation system.

Here, output of the excitation transformer is used for supplying the field current of generator through a thyristor bridge. Output voltage of the generator is continuously measured through a PT. This output voltage is compared with the voltage set point at AVR. If this does not match with the set point, then an error signal is generated. This signal changes the firing angle of thyristor. Accordingly, the field current is changed to get a desired voltage. In this case, the thyristor bridge has to conduct the total field current. So, the size of thyristor is large and a large amount of heat is produced at the thyristor panel. Figure 19.7 shows simple block diagram for a brushless excitation system with exciter and permanent magnet generator (PMG). Here, AVR is connected to the control field current of the exciter, not with the main field current of the generator. So, the thyristor is smaller in capacity. Like previous case, at AVR, PT supply is compared with the set voltage and accordingly, the firing signal of thyristor is changed. Here, the thyristor bridge is connected at the supply obtained from PMG which is mounted on the generator shaft. As this is a permanent magnet generator, so field flushing is not required in this case. The voltage is built up without any external supply. The output of thyristor is changed according to the AVR signal and supplied to the stationary field winding of the exciter unit. No brush is required here, as the field is stationary.

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Figure 19.7  AVR arrangement in brushless excitation system.

Exciter is mounted in the same shaft of generator. Coil of the exciter rotates with the generator shaft. So, voltage is generated in this coil according to the field current. This generated voltage of exciter is rectified in a diode bridge which is fixed to the rotating shaft. Diode output is supplied to the field winding of the main generator. For this, load is connected from the rotating diode output to the field winding through a hole machined at the generator shaft. Here also, the brush is not required. So, the total excitation is brushless. Other than voltage regulation, AVR also perform the following functions in the modern power plants:

• • • • • •

It controls the power factor of generator. It limits the stator current and rotor current. It also limits the load angle. It controls the flux rate (V/F) of the generator and hence, the eddy current loss too. It detects failure of any diode. This follows up the manual channel signal with that of auto channel for bumpless changeover. • It carries out changeover from auto to manual mode. • It performs field flushing. • It performs field suppression.

Normally, AVR is having two modes of operation—auto mode and manual mode. In auto mode, AVR controls the voltage automatically along with the above functions. Whereas, in manual mode, voltage is controlled by adjusting the raise and lower command manually. So, there are two separate control circuits in an AVR. AVR changes automatically from auto mode to manual mode, in case there is a problem in auto control circuit. The manual control signal is always adjusted with the auto control signal through the follow up circuit so that the changeover of control mode is bumpless without any significant effect on the generator voltage. When generator is stopped during any fault, field breaker is opened along with the main generator breaker. Energy is stored in the inductive field winding. This stored energy continues to magnetise the field for some time and the generator continues to generate the voltage for some

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time till the field energy is discharged. To avoid this situation, field suppression arrangement is done. When field breaker is opened, a highly resistive load is connected across the field coil so that the stored energy can be dissipated shortly. This is called field suppression.

19.6  VOLTAGE BUILD-UP Before the synchronisation of generator for loading, generator voltage is to be built up. Once the turbine attains its full speed, voltage of the generator can be built up by closing the field breaker of generator. In a generator having PMG, field flashing is not required. Otherwise, a separate DC supply is given to the field of the main generator or an excitation generator field for the initial voltage build-up, as there may not be residual magnet in the field. When some voltage is generated at the generator terminal, then this external supply is switched off and the voltage is built up by its own supply. This activity is performed automatically in an AVR. Before closing the field breaker, it is to be ensured that the manual voltage set point is at minimum position. Once the voltage is built up, the voltage can be adjusted to the rated voltage by adjusting the manual set point. In an AVR, a null voltmeter is provided. This null voltmeter shows the voltage difference between the auto and manual channel of AVR. After obtaining the rated voltage by adjusting the manual setpoint, auto setpoint is to be adjusted till this null voltmeter reads zero. In this condition, the output of auto and manual control channel is the same. Now, the AVR can be put in auto control mode. Voltage of the generator is maintained by the auto channel and the follow up circuit adjusts the output of manual channel accordingly. Null voltmeter should read zero always.

19.7  SYNCHRONISATION enerator is required to run in parallel with the other generator or with energy supply grid. Auxiliary power for the generator is obtained from an other source during starting. So, to transfer this auxiliary load to the generator itself, synchronisation is required. To run the generator in parallel with the other generating source to share load, synchronisation is made as shown in Figure 19.8. For the synchronisation of the incoming generator, following three parameters are required to be matched with the existing power source or bus:

• Phase sequence • Voltage • Frequency

Double frequency, double voltage measuring device and a synchronoscope are commonly used for the synchronisation of generator. Double voltmeter has two instruments independent of one another which indicate voltage of the bus and that of the incoming generator. The voltage of incoming machine (generator) is adjusted with the voltage of bus (other generator or grid) by adjusting the field current of the generator or voltage set point at AVR. Both the voltages should be equal before synchronisation.

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Figure 19.8  Generator connection arrangement.

Double frequency meter contains two frequency measuring instruments which indicate frequency of the bus and that of the incoming generator to be switched on. Both frequencies can be measured simultaneously. Frequency is matched by adjusting the speed of turbine of the incoming generator. The generator is to be synchronised when both frequencies are same. Phase sequence of the incoming generator and that of the bus are checked by the phase sequence meter and the bus bars and cables are connected accordingly during the erection of generator. If the connection is not disturbed, phase sequence is not required to be matched during every synchronisation. There are two methods to check the phase and frequency for synchronisation. They are given below:

• Lamp method—Dark lamp method, bright lamp method • Synchronoscope method

In dark lamp method, three lamps are connected across the three phases of incoming machine and bus. When the phase and frequency of both bus and incoming generator become same, then there is no voltage difference across the lamps. So, the lamps remain dark. Synchronisation is done at the middle of darkness. In bright lamp method, the connection of the light is changed. It is connected across different phases of the incoming machine and bus. In power plants, synchronoscope is widely used for synchronisation. Synchronoscope is an instrument which shows the phase relation of incoming generator voltage and that of the bus and indicates whether it is running slow or fast. It works on the principle of rotating the magnetic field. It is a small motor having a pointer fixed at one end of the rotating shaft which rotates over a circular scale. It has windings at the stator and the rotor connected to two phases of the bus and the generator respectively. These two windings produce two different rotating fields.

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If there is a difference in frequency of these two sources, then speed of these two rotating fields also varies, producing a resultant flux which rotates the shaft. The speed of rotation of the pointer depends upon the difference in frequency. The flux varies in proportion to the difference between the frequencies of these two sources. So, when there is more difference in frequencies, then the speed of the pointer is more. If the difference in frequencies is less, then the speed of the pointer is less. If the speed and hence, the frequency of the generator is higher than bus speed, then the pointer moves clockwise. When the speed and hence, the frequency of the generator is lower than bus speed, then the pointer moves anticlockwise. When frequency of both these sources is same, then the speed of both the rotating fields is the same and no flux is produced. The pointer remains standstill in this situation and the generator breaker may be closed for synchronisation. The frequency of a generator is adjusted by adjusting the speed of turbine. After synchronisation, the generator’s speed is to be raised to increase load on the generator. Nowadays, auto synchronisation system is used in the power plant which matches the above parameters automatically and synchronises the generator.

19.8  DESYNCHRONISATION OR ISLANDING In case of any fault at the outside source, synchronised generator is to be isolated to save the generator and avoid tripping. Otherwise, the generator will supply fault current which is dangerous for the generator. Also, in case of failure of grid, the total outside connected load comes upon the generator which is beyond the capacity of generator. So, in that case, the generator is to be isolated from the system immediately and continue to operate at its own capacity. For this, desynchronisation or islanding scheme or grid islanding scheme is adopted at the power plants. Grid islanding scheme is a set of protective relays connected at the bus. These relays sense any disturbance at the grid and give a trip command to the grid breaker whenever the grid disturbance exceeds a set limit. By opening the breaker, generator is disconnected from the disturbed grid. The process of disconnecting the generator from grid is called islanding of the generator. A grid is said to be disturbed during the following situations:

• • • • • • •

Undervoltage (U/V) Overvoltage (O/V) Underfrequency (U/F) Overfrequency (O/F) Rapid fall or rise in frequency ( df /dt) Power failure in the grid Fault in the grid

Following relays are connected to take care this situation and for successful islanding:

• • • • •

Overvoltage (O/V) and undervoltage (U/V) relay Overfrequency (O/F) and underfrequency (U/F) relay df/dt relay Vector surge relay Reverse power relay

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Undervoltage (U/V) and overvoltage (O/V) faults are taken care by simple voltage operated relays. For the detection of other faults, following relays are used: df/dt and Frequency Relay This relay is a frequency operated relay. This relay can measure the rate of change of frequency as well as high or low frequency in the system. When there is a fault anywhere in the system, the generator tries to supply fault current which is beyond its capacity. So, the turbine speed decreases. The frequency of generator falls and the rate of change of frequency is high in this situation. If this rate of change is more than the set value, then the relay is operated and opens the breaker to isolate the generator from faulty system. Vector Surge Relay Vector surge relay is very effective for islanding of generator. This relay measures the vector angle of the voltage wave. The wave of generated voltage is sinusoidal. When there is a fault in the system or the grid supply fails, a sudden jump of this wave takes place and the phase position changes. The relay measures the cycle duration continuously. Measurement is started after each voltage zero. As shown in Figure 19.9 (in dotted line), the wave is shifted by some phase. So, the cycle duration increases. The deviation of cycle duration indicates the vector surge angle. If this angle is more than the preset value, then the relay is operated and opens the tiebreaker. So, the generator is isolated and continues to run on its own capacity. The vector surge relay is very first and reliable.

Figure 19.9  Vector surge relay.

Reverse Power Relay Reverse power relay is a directional power relay. Mostly, this relay is used in small captive power plants where no power is supposed to be supplied to the grid. When there is a fault in the grid system, the generator tries to supply the fault load. So, power from the generator flows in the reverse direction towards the grid. In this case, the relay operates and isolates the tiebreaker to avoid the reverse flow of power. Figure 19.10 shows the connection of these three islanding relays.

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Figure 19.10  Connection of islanding relays.

19.9  GENERATOR PROTECTION Generator is a critical machine in any power plant. So, it is required to operate this machine within the specified limits. But as the generator is connected to different sources, any fault outside the generator affects the loading condition of the generator. Also, there is always a chance of internal fault inside the generator. These faults are to be detected immediately and the generator is to be stopped to avoid further damage to the machine. Otherwise, the generator may be damaged seriously and will take longer time to repair, causing heavy loss due to the stoppage in generation. Different protective relays are connected to take care of different fault conditions and stop the generator to avoid damage. The function of protection scheme of generator is to detect and remove the faulty parts as quick as possible. A protective system should be

• • • • •

Reliable (capable of detecting all types of faults) Selective (isolating only the faulty parts of the system) Quick in operation Economical Simple in construction

Some important and mostly used relays in a power plant for the protection of generator are discussed below: Generator Overcurrent Protection Overcurrent is a condition when the current supplied is greater than the rated current of the generator and occurs due to overload, short circuit or ground fault. An overcurrent protection relay protects the generator by opening the generator breaker when the current reaches an undesirable value. Overcurrent relay is used to protect the generator from overcurrent. There are two types of overcurrent relays:

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• Instantaneous overcurrent relay • Time lag overcurrent relay

Instantaneous overcurrent relay operates instantly when the magnitude of stator current increases beyond a certain predetermined value. This relay operates without intentional time delay when the fault current is very high. Time lag overcurrent relay operates with a time delay. The time delay for operation of this relay is adjustable. For a given setting, the actual time delay depends on the current through the relay coil. In general, higher current causes a faster operation of the relay. The minimum current at which the relay operates (pickup current) is also adjustable. Time lag overcurrent relay is having various characteristic depending upon the steepness of the time–overcurrent characteristic. These are as follows:

• Definite time • Inverse time

Definite time overcurrent relay is a simple instantaneous overcurrent relay with specific current setting and controlled by a timer set to operate at a delay time. In inverse time over current relay, operating time of the relay is inversely proportional to the current. When the current is more, then the operating time is less and when the current is less, then the operating time is more. This relay starts operating once the current increases beyond a preset value. These relays are connected at two or three phases. Earth Fault Protection Most of the time, single phase earth faults are experienced in the power distribution network. In this condition, one phase is short circuited to ground, resulting in higher current in that particular phase and in the neutral of the generator. Earth fault protection relay is connected to detect and trip the generator in case of any fault that short circuits any phase with the earth or leakage current to the earth due to the failure of insulation. To limit the earth fault current of the generator, neutral point of the generator is earthed through a neutral grounding resister (NGR). Generator Differential Protection Differential protection is employed to detect any fault inside the generator winding and stop the generator. This relay can sense any phase to phase or phase to earth fault inside a generator. If a fault takes place outside the generator, then the relay remains non-operative. Differential protection is a very reliable method of protecting generator from the effect of internal faults. In a differential protection scheme, current on both sides of the generator winding are compared. Under normal condition or during fault outside the generator, current on both sides are equal, so the relay does not operate. In case a fault develops inside the generator winding, these currents are no longer equal. In this condition only, the relay operates. Reverse Power Protection As the generator is required to run in parallel with the other source, power may flow in the reverse direction and start to rotate the generator as a motor with the turbine as a load on it. This condition is called as motoring of generator and this may happen due to decrease or

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stop of steam supply. This is very dangerous condition, as it may damage the turbine. In any condition, the generator is not allowed for motoring action. To protect the generator from this situation, reverse power relay is used. Reverse power relay is a directional power relay. It is operated when the power flows in reverse direction. Low Forward Power Protection This is a power relay which ensures the generator to supply certain minimum power. When the generator load falls below this specified limit, then this relay operates to isolate the generator from the circuit by opening the generator breaker. Negative Phase Sequence Protection Due to unbalance loading in three phases of a generator or during fault condition, negative phase sequence component is produced which in turn, produces a magnetic field that rotates in opposite direction to that of the main magnetic field. Due to this double frequency, the rotor is overheated. Negative phase sequence relay is used to detect and stop the generator in case of this type of fault. Overvoltage and Undervoltage Protection The generator output voltage should be within the specified limit. The output voltage may increase due to the failure of AVR system. This overvoltage may damage the insulation of generator. Due to problem in AVR or heavy fault condition in the system, generator output voltage may drop. Overvoltage and undervoltage protection relays are used to take care of overvoltage and undervoltage respectively. Overfrequency and Underfrequency Protection The generator is required to run at a specified speed to generate voltage at 50 cycles. This frequency depends upon the turbine speed. When speed of the turbine increases, frequency increases and vice versa. When generator supplies fault current to the faulty source, then the speed of turbine and hence, the frequency drops. In this condition, the generator breaker should open to protect the generator. Sudden load through or any problem in the governing system may raise the speed of turbine and hence, the frequency too. To take care of this type of fault and to protect the generator and turbine, overfrequency and underfrequency relays are used. Rotor Earth Fault Protection Field coil of the generator is inserted into the rotor slots and DC current is supplied for excitation. This field winding is exposed to an abnormal mechanical or thermal stress due to vibrations, overcurrent, choked cooling medium flow, etc. This may result in breakdown of insulation between the field winding and the rotor body. The purpose of the rotor earth fault protection is to detect an earth fault in the field winding of generator. Failure of insulation of rotor coil in one location is called first stage rotor earth fault or single earth fault. It is not very dangerous and does not cause immediate damage because the fault current is small due to low voltage. In this condition, the generator may be allowed to run.



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But, if further earth fault occurs at a second location, it is more dangerous and appears as a rotor winding interturn fault and causes severe magnetic unbalance and heavy rotor vibrations, leading to severe damage. This condition is called second stage rotor earth fault. In this condition, generator is stopped as soon as possible. Normally, generator trips after a short time delay if any second stage rotor earth fault is detected. Rotor earth fault relay is used to detect first stage rotor earth fault to initiate an alarm and the second stage earth fault to trip the generator. Field Failure or Loss of Excitation Protection Loss of field supply or loss of excitation may occur due to the opening of field terminal or blown of field fuse or failure of diode. This condition is detected by field failure relay to stop the generator. Stator Overheating Protection If the generator is not cooled properly or due to high current flow in the generator, temperature of stator winding increases. To protect the winding from overheating, resistance temperature detectors (RTDs) are used in the slots below the stator coil. These detectors are placed at different locations in the winding to detect the temperature throughout the stator. Alarm and trip signal are produced by these RTDs when the temperature of any RTD exceeds a set value.

19.10  DIFFERENT OPERATING CONDITIONS OF GENERATOR As discussed earlier, a generator is required to operate in parallel with the other generator or grid as well as it may supply load in an isolated condition. This isolated condition of operation is called islanding or solo mode of operation. In isolated operation mode, the frequency of generator is maintained 50 Hz, irrespective of any connected load on the generator. This mode of operation is also called auto frequency regulation (AFR) mode or speed mode of operation. In parallel operation, the generator is operated in auto power mode. The output power of generator is controlled where the frequency of generator depends upon the frequency of the connected grid system. This operating condition is called auto power regulation (APR) mode or load mode of operation.

19.10.1  Parallel Mode of Operation In parallel mode of operation, voltage and frequency of the generator depends upon that of the connected grid. Load shared by the generator depends upon the load setting on the governor or the steam input to the turbine. The load is maintained constant according to the load set point on the governor. To increase the load on a generator, set point on the governor is raised which ultimately increases the governing valve opening to increase the steam input to turbine. This mode of operation is also called auto power regulation (APR) or load mode operation. In this case, increasing steam into the turbine does not increase the speed of the turbine and hence, the frequency does not increase. Rather, it increases the load on the generator.

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19.10.2  Isolated Mode of Operation Sometimes, a generator is required to run in a isolated mode. In this condition, the generator runs in an isolated condition without being parallel with the other generator or grid system to supply load upto its own capacity. This mode of operation is also called solo operation or auto frequency regulation (AFR) or speed mode operation. In this case, speed of the turbine is maintained constant by the governor to generate power at a frequency of 50 Hz. Any variation in the load is taken care by increasing the required amount of steam and opening the governing valve. When load increases, speed of the turbine reduces. The governor acts promptly to bring back the required speed to maintain the frequency of 50 Hz. In this case, voltage and frequency of the supply are maintained constant with the help of AVR and governor respectively. As the machine is not tied electrically to the other generating source, so its parameters are not dependant upon the external fluctuations. This mode of operation is very simple.

EXERCISES

1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13.

What is the relation of frequency with the speed and number of poles of a generator? Why is damper winding provided? Why is the rotor and stator core made of laminated steel? Why is generator bearing kept isolated from the earth? How is the winding temperature controlled in a closed cycle air cooler? Why is hydrogen suitable for generator cooling? What is the difference between static excitation system and brushless excitation system? What are the functions of AVR other than voltage regulation? What are the three parameters to be matched for generator synchronisation? What is desynchronisation or islanding and when is it required? What are the relays used for islanding? What are the main relays used for protection of generator? What is the difference between parallel mode of operation and isolate mode of operation?

Chapter

20

Commissioning of Power Plant

20.1  INTRODUCTION Commissioning of power plant is a complex activity. A plant is started first time after erection. As a lot of activities are involved during erection and the prime focus is to complete the project within the scheduled time as well as within the budget, so some problems may come during the initial start-up or commissioning. Special care is required to be taken during commissioning. Experienced manpower guided by original equipment manufacturers’ specialists can make commissioning easier. The commissioning personnel should be associated during the plant erection to have a clear idea about the system of the plant. They should be familiar with the piping and instrumentation (P and I) diagram as well as with the machine manuals. Before commissioning, they should go through the commissioning and operation instructions supplied by the equipment manufacturer. The commissioning team should work under leadership of a particular responsible person. All the activities of commissioning should be well documented and well communicated to all the team members. There is always a risk during commissioning. So, proper safety precautions are to be taken during commissioning. Commissioning of power plant, as a whole, is the commissioning of all the individual systems of a power plant. Once all individual systems are commissioned, all the systems can be put in service to finally run the turbine and start the generation. In the subsequent sections, the precommissioning and commissioning activities of individual systems are discussed. Depending upon the type of a boiler and the size of a plant, there may be variation in the commissioning methods. But, in general, there are some common activities which are mostly carried out during commissioning. The main aim of this chapter is to give some basic idea about the power plant commissioning and some major activities involved. However, for practical commissioning of any power plant, instructions given by the equipment manufacturer are to be followed.

20.2  COMMISSIONING OF BOILER Commissioning of boiler is a critical activity. It involves some statutory (IBR) requirements 419

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also like hydro test, safety valve setting, etc. Total boiler commissioning may be divided into some activities that are described here separately for better understanding.

20.2.1  Leakage Test of Pressure Parts and Flushing A lot of welding work is carried out during the erection of a boiler pressure parts. X-ray tests of some welding joints are carried out to examine the quality of welding. X-ray testing is also a statutory requirement. Some percentage of the total welding joints is tested by X-ray. As all welding joints cannot be tested through X-ray, so there is a chance of welding defects in these joints. Initially, these leakages can be detected by filling the pressure parts with water. A small capacity pump is used to fill up the pressure parts. DM water is used for initial fill up. Leakage from the defective joints can be detected and rectified easily. During transportation, storage and erection, some foreign particles may go inside the pressure parts. So, the pressure parts are required to be flushed thoroughly to remove any dust, dirt or foreign particle. All individual drain points are to be opened to find out chocking, if any.

20.2.2  Hydrostatic Pressure Test of Pressure Parts Hydro test of a newly erected boiler is a statutory requirement. Also, any minor leakage present in the pressure part can be detected by hydro test. Procedure of hydro test is already discussed in the earlier chapters. In case of a new boiler, hydro test is to be carried out carefully. The pressure is to be raised slowly and if any leakage is found, this is to be arrested.

20.2.3  Furnace Leakage Test Boiler furnace is made of water walls, castable, refractories and solid plates. Flue gas should not leak from the furnace or atmospheric air should not ingress into the boiler. A lot of welding work is done in this area and a chance of leakage is there. So, before initial firing of the boiler, it is to be ensured that there is no leakage at the furnace and flue gas path of the boiler. For this, a simple test is carried out. All the door and dampers are closed and smoke is created inside the furnace. After some time, smoke comes out from the leakage point of the flue gas path which can be detected easily and sealed. Sometimes, a light is put inside the furnace and flue gas path and the outside of the boiler area is made dark. If there is any leakage, then light comes out. This test is carried out before applying insulation at the outside of the boiler furnace.

20.2.4  Chemical Cleaning of Pressure Parts Oil, grease, iron oxide (rust) and mill scale are present in the pressure parts of a newly erected boiler. Pressure parts are to be cleaned thoroughly before putting the boiler in service. Otherwise, these particles will affect the heat transfer and create problem in the circulation of feedwater inside the boiler. For this purpose, chemical cleaning of the boiler pressure parts is carried out. Acid or EDTA cleaning and alkali boil-out is carried out for cleaning of the boiler tubes.



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Chemical cleaning procedure is discussed here in detail. Acid cleaning process involves acid cleaning, neutralisation and passivation Acid Cleaning Acid cleaning is done by either circulation or fill and soak method. Circulation method is preferred to clean the pressure parts of natural or forced circulation boilers. Details of acid cleaning are already discussed in Chapter 9 for the removal of waterside scale. Here, we will discuss about the acid cleaning and passivation procedure of a new boiler. The procedure is almost same in both the cases with a little difference in the monitoring parameters. In a new boiler, mostly, all the pressure parts are connected for acid cleaning. Circulation type acid cleaning arrangement is shown in Figure 20.1. Acid solution is prepared in the acid solution tank. Temporary pipeline is fabricated to circulate the acid in the boiler pressure parts. The arrangement is so made that all the drainable pressure parts are connected for the acid circulation. Sometimes, the main steam pipeline is also included in the loop.

Figure 20.1  Acid circulation arrangement.

The main purpose is to remove iron oxide from the boiler tube and protect the tube metal. As discussed earlier, an inhibitor is added to the acid solution to protect the tube metal from the corrosive action of acid. This inhibitor reduces the corrosion rate. The inhibited acid solution is circulated through the unit at a correct temperature by a pump. The circulating acid reacts with the iron oxide and mill scale of the inner surface of the boiler tube. So, the concentration of iron in the solution increases. Iron concentration in the return acid solution from the boiler is measured frequently so that the cleaning progress can be monitored. The cleaning procedure completes when all the iron oxide is removed and no further reaction with the deposits is taking place, acid strength has reached a balance and iron concentration in the solution has got stabilised. After the completion of cleaning process, the solution is drained out carefully after neutralisation. Normally, acid cleaning is not done for non-drainable superheater coils. Typical iron concentration of a new boiler is shown in Figure 20.2.

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Figure 20.2  Iron concentration with cleaning time.

After acid cleaning, the solution is drained out and then, the pressure part loop is flushed with clean water until the flushing water effluent is free from acid and soluble iron salts. Some alkaline solution (ammonia, sodium hydroxide or trisodium phosphate) is circulated to neutralise any residual acid inside the boiler tube. Acid clean surface is very reactive. So, the formation of protective layer is required after acid cleaning. This process is known as passivation. Passivation agents like sodium phosphate, hydrazine or nitrite is circulated for the formation of a passive cohesive iron oxide (Fe2O3) protective layer. After passivation, temporary piping is removed and the boiler is made ready for steaming.

20.2.5  Alkali Boil-out For alkali boil-out boiler is filled with normal DM water. Alkali solution, particularly soda ash or caustic soda, is added to the boiler drum. Normally, the steam drum internals are removed and a temporary gauge glass is fitted to the boiler drum to avoid damage of original gauge glass due to chemical action. All the instrumentation tapings are isolated. As per the cold start-up procedure, boiler is lighted up. Some time is allowed to dry out the newly applied refractory at the boiler furnace. After refractory dry out, pressure of the boiler is increased in a controlled way to get sufficient circulation of water inside the boiler. Water sample is tested on regular intervals. Boil-out is completed when phosphate, oil particle and pH of the water stabilise. After alkali boil-out, boiler is cooled down and the water is drained out. Boiler internal is rinsed with the fresh DM water.

20.2.6  EDTA Cleaning Ethylenediaminetetraacetic acid (EDTA) is nowadays used, extensively for the cleaning of boiler. EDTA is circulated in the boiler pressure parts to clean the boiler tube’s inside surface. Circulation of the solution takes place due to natural circulation of water during the controlled operation of boiler like alkali boil-out. Cleaning, neutralisation and passivation can be achieved sequentially with the single solution under controlled condition. Hence, the cleaning and passivation time reduces drastically.



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20.2.7  Safety Valve Setting Safety valve setting is a statutory requirement. As discussed earlier, there are three safety valves. One is installed at superheater outlet and other two are placed at the steam drum. Superheater safety valve is set at a lower pressure than that of the drum safety valves. To set these safety valves, the boiler is lighted up. The safety valve to be set is kept on service and the other two are gagged. Pressure on the boiler is raised slowly as per the normal operation procedure of a boiler. Fuel feeding rate is kept at minimum. The safety valve is required to lift and reset at a desired pressure as per the boiler pressure rating. Accordingly, it is adjusted to get the lift and reset pressure. Like this, all the three safety valves are set. All the gagging are removed. Percussion is to be taken during initial pressure build-up. The drum pressure gauge should be perfect and calibrated. If the safety valve does not lift beyond the set pressure, then the pressure of the boiler is to be reduced and setting is to be done again.

20.2.8  Commissioning of Boiler Feed Pump Before commissioning of any equipment in a power plant, electric motor of that equipment should be commissioned first. Direction of rotation and current drawn should be checked. The motor should be left to run on no-load for some time in decouple condition. Then only, coupling is to be done. Special care should be taken while commissioning a boiler feed pump. The deaerator should be inspected and cleaned thoroughly to avoid any foreign particle on the feed pump suction line. Suction strainer of the pump should be cleaned. Cooling water should flow freely for gland and bearing cooling. Bearing should be properly lubricated and the pump is properly aligned with the motor. Feed pump is to be started from local for the first time. Pump body temperature and any abnormal sound, bearing temperature, motor current, discharge pressure, balancing pressure, etc. are to be checked regularly.

20.2.9  Commissioning of Fans There are various fans used in a boiler. These are ID, FD and PA fans. Before commissioning of these fans, the driving motors are to be commissioned first (before coupling). Individual fans are to be started from local, keeping dampers on the required position. Proper care is to be taken to remove any foreign particle at the suction and discharge ducts of the fan. It is to be kept running for some period before putting into normal operation on load. Then, interlocks of these fans are to be checked.

20.2.10  Commissioning of Fuel Handling System Like other drives of a power plant, drives used for the fuel handling system like belts, crusher, screen, oil pumps, etc. are also to be commissioned one by one. The safety interlocks are to

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be checked. There should not be any oil/gas leakage from the fuel pipeline. For a coal-fired boiler, the system, as a whole, should run perfectly with all the interlocks. Weigh feeder should indicate the accurate weight. Crusher, screen, elevator, etc. are to be commissioned one by one. Other auxiliary system of the boiler like ash handing system, ESP, etc. are to be commissioned before putting the boiler into operation.

20.3  COMMISSIONING OF TURBINE Like a boiler, commissioning of a turbine comprises of a different steps. These steps are discussed here to give a little idea about the commissioning activity. The activity may vary from plant to plant depending upon the size and the type of turbine. Still, some common activities are discussed here for understanding.

20.3.1  Lube Oil Flushing Lube oil is the lifeblood of any turbine. It lubricates the bearings. This oil is required to be very clean and free from any suspended foreign particle and contamination. Rust and dust particles are there in the pipeline before fabrication. During fabrication of lubrication pipe, welding debris may enter the pipeline. These particles can damage the turbine bearings. So, the pipeline, storage tank and other connected systems of the lube oil system are to be cleaned properly by circulating and filtering the oil before putting the turbine on line. Oil flushing is an important task of turbine commissioning. Mostly, the lube oil line is soaked in acid solution for internal cleaning. Fabricated pipeline is removed from the position for this. After acid cleaning and thoroughly rinsing with fresh water, it is fitted again. The dust, rust and scale present in the pipeline are removed. The lube oil tank is cleaned properly and recommended grade of the lube oil is filled in it. During the initial circulation of lube oil, oil is not permitted to enter the turbine bearings. Suitable temporary arrangement is made for shorting the pipelines for looping so that the oil can be circulated through the entire part of the pipeline without entering the bearings. The filter cartridge of lube oil filter is removed and oil pump is started for the circulation of oil in the pipeline. Any foreign particle in the pipeline is flushed out and returned to the lube oil tank through a return oil pipeline. Any leakage noticed in the line is arrested. A wire mesh of higher size is put at a suitable location on the return oil line connected to the tank. The debris is collected here and this mesh is cleaned regularly. When no debris is found in the mesh, it indicates that there is no foreign particle in the oil line above that mesh size. Like this, gradually, the smaller mesh size wire meshes are fitted on the return oil line and the circulation of oil is continued till no debris is found. Circulation is carried out till 25µ mesh is cleared. Both the oil filters and oil coolers are put into service interchangeably to flush both the oil filters and coolers. Then, the temporary pipeline is removed and oil is allowed to flow through the bearings as per the normal system. Oil flushing may require more time depending upon the pipeline condition and effectiveness of acid cleaning. Once 25µ mesh is cleared, the circulation is stopped. All the oil in the lube oil tank is drained out. Oil tank is thoroughly cleaned and fresh new oil is filled in the tank.

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New filter cartridge is placed in the oil filter. Oil can be circulated as per the normal practice. Sufficient quantity of oil filter cartridge is to be kept ready, as there is a chance of frequent filter chocking. Once the system is stabilised, new filter is to be put at both the filters.

20.3.2  Steam Blowing To clean the main steam pipeline connected to the turbine, steam blowing is carried out. By blowing the steam, any particle in the boiler and piping system that may damage the turbine internal, is dislodged and blown out. Thermal cycling (heating/cooling) and high velocity steam flowing through the pipeline shock the pipe and tend to break the mill scale and weld slag away from the pipe wall. Steam blowing should be done prior to the pipeline insulation to maximise the thermal cycling.  Ideally, to obtain an optimum cleaning, flow conditions in the pipeline during steam blowing should be same or more than that of a normal operation at the maximum load. Steam blowing creates abnormal and severe conditions on the boiler and steam piping. Large and rapid temperature changes occur during each blowing cycle. This cycling of temperature is more severe than that of a normal operation. Thermal stresses may be excessive in the heavy wall portions of the system such as steam drums, headers and piping. So, proper care is to be taken during steam blowing Before steam blowing, the pipeline is flushed with water. Normally, hydraulic test is carried out as per the statutory requirement. After hydraulic test, this water is flushed out. In some cases, chemical cleaning of this pipeline is also done by circulating an acid solution, as discussed earlier. After acid cleaning, the line is rinsed thoroughly with fresh water. Pipeline upto turbine ESV is connected for steam blowing. ESV is removed and one temporary pipe is connected there. This pipeline is open to the atmosphere. Provision is made at suitable locations to fix a target plate in this temporary pipeline. Figure 20.3 shows the arrangement for steam blowing.

Figure 20.3  Arrangement for steam blowing.

During steam blowing, following precautions are to be taken:

• Check all pipe supports hangers including that of temporary blow pipe.

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• Ensure that the pipeline has been inspected and hydro tested. • Remove all the control and instrumentation equipments like control valves, desuperheater nozzles, flow elements, thermo wells, pressure gauges, orifice plates, safety valves and instruments, as these may be damaged during steam blow. • Use visual communication such as lights or flags, since audio communication may be difficult due to high noise level during blowing. • Ensure personnel movement is controlled in area during steam blow. • Individuals involved in steam blowing should use ear plug.

For steam blowing, a boiler is allowed to generate steam as per the normal operation. When drum pressure reaches the value calculated to produce the desired blowing flow quantity, blowing procedure can be started. Now, the main steam stop valve or the blow off valve fixed at the temporary blowing pipeline, is to be opened to allow steam to flow through the pipeline and vent to the atmosphere. Drum level extremely fluctuates during the blow. As the blowing starts, the drum level rises rapidly and may go out of sight in the gauge glass. After some time, as blow progresses, drum water level reappears and may drop out of sight. Therefore, it is important that the drum level is maintained slightly above the normal operating level and small amount of feedwater is supplied before the start of each blow. Feedwater flow should be increased as soon as the water level drops back in sight to prevent an excessive low water level. It is difficult to avoid carryover from the steam drum to the superheater during blowing operation. Therefore, boiler water should not be treated with non-volatile chemicals during this process to avoid deposits at the superheater. Fuel feeding is to be stopped during all blows. This can be started again for the next blowing. Steam line is allowed to cool down before starting the next blow. The heating and cooling cycle detaches any scale and rust from the pipeline so that these are blown out. Target plate is used to find out the cleanliness of pipeline. Highly clean and polished metal plates (mild steel or aluminum) are used as target plate. These plates are placed at the temporary blow pipe. To fix the target plate, a suitable arrangement is made. When steam blowing is started, the particle removed, moves with high velocity and makes impact on the target plate. So, impressions are created on the target plate. This plate is not fixed during first few blows. During initial blowing, a lot of particles are removed from the pipeline and a lot of impressions are created on the plate. After few blows, the target plate is placed. Cleanliness of the pipe can be judged by observing the impressions on the target plate. Normally the blowing is completed in following situations:

• No impression exceeding 0.8 mm diameter • Impression exceeding 0.4 mm diameter, not more than 2 numbers per 2500 mm² of the target plate surface • Impression exceeding 0.2 mm, not more than 10 numbers per 2500 mm² of the target plate surface • Impressions less than 0.2 mm • As per the requirement of a turbine supplier



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The above discussed method of steam blowing is known as puffing method. Sometimes, another method known as continuous blowing method is also adopted. The procedure is same as the puffing method but the pressure is maintained constant during blowing. Stress on the boiler is lower in this case. Once steam blowing is completed, the temporary pipeline is removed and the main steam line is connected to ESV. All auxiliary pipelines like ejector steam line, gland steam line, extraction line, etc. are also blown with the steam to clean. For this, a suitable looping is made and low pressure steam is used.

20.3.3  Turbine on Barring Special care is required to be taken while rotating a turbine first time through the barring device. As discussed earlier, the clearance of internal parts of a steam turbine is very less. If the turbine is not properly aligned with the gearbox or generator, then there is a chance of damage during the barring operation. The turbine internals’ clearance and alignment should be within the limit, as advised by the turbine manufacturer. Before putting the turbine on barring, lube oil circulation is to be started. If hand barring provision is there, then the rotor should be rotated manually first. Barring gear motor should be started in decouple condition to check its rotation. If barring is done hydraulically, then the oil supply line is to be made ready. Bearing oil pressure at different Barrings is to be set as per the requirement. After the coupling of barring gear motor, the device is to be started. Then, it rotates the shaft at barring speed. Now, check for any abnormal sound, vibration or rise in any bearing temperature at suitable interval. If these are normal, then the turbine can be put on barring for some time before the starting of turbine.

20.3.4  Commissioning of Condensate System During erection, some foreign particles like dust, welding debris, even if left out hand gloves and tools are found at the condenser, condensate pipeline and deaerator. So, proper flushing and cleaning of this system is required before putting it on line. Condenser is filled with DM water upto the neck in the shell side to check any leakage. Sometimes, the shell side is hydro tested by inserting a blind plate at the neck flange of the condenser. After proper flushing of the condensate system, water is circulated through the condensate extraction pump, putting all the systems connected to condensate system like (such as LP heater, gland steam condenser and the main ejector condenser) on line. Both the CEPs are kept on service one by one. All the interlocks of the condensate system are checked. During initial running of turbine some dislodged scale and rust from the condenser and pipeline choke the suction filter of CEP. So, differential pressure across the suction strainer is to be monitored regularly till the system is stabilised.

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20.3.5  Rolling of Turbine Before rolling of turbine, barring gear is to be put on service. All the auxiliary systems are to be commissioned and put into service. Once all these systems are stabilised, turbine heating is started. All casing drains are kept open. Steam can be charged upto ESV after ensuring proper line heating and drain out of the condensate. Position of all support hangers of the main steam line is to be noted in cold and hot condition. After heating of steam line, some adjustment may be required to adjust the loading of hangers. Once all the auxiliary systems are put into service, the turbine can be rolled preferably on manual or semi-auto mode. Sufficient time is allowed for the socking of turbine. Casing and rotor expansion is measured. It is to be ensured that the casing is expanded freely. At lower speed, parameters like bearing temperature, vibration, exhaust pressure and temperature, etc. are to be measured and monitored regularly. If everything is normal, the speed may be raised slowly. As per the practice, special care is to be taken during critical speed band.

20.3.6  Overspeed Test After rolling of turbine, it is required to set the overspeed trip limit of the turbine. As discussed earlier, mechanical overspeed tripping arrangement is provided in some turbines. To set the overspeed trip limit, the turbines speed is required to be increased upto that range. Turbine is rolled as per the normal practice. Sufficient time is allowed for the heating and expansion of the casing and rotor. It is not advisable to carry out overspeed test when the turbine is not properly heated up. Now, speed of the turbine is raised upto the maximum governing speed. Upto this speed, the governor can control the turbine speed. If electrical overspeed trip is provided, then this trip limit is to be bypassed. By pressing the overspeed test button in Woodward 505 governor, this electrical trip is bypassed. After electrical overspeed is bypassed, speed of the turbine is further raised above the maximum controllable speed. When mechanical overspeed limit is reached, the pin of the overspeed trip device fixed to the rotor comes out due to centrifugal force and operates the trip lever to trip the turbine. Tension of this pin can be adjusted by adjusting a spring to set a desired overspeed trip limit. After mechanical overspeed setting and testing, the turbine is ready for loading.

20.4  COMMISSIONING OF COOLING WATER SYSTEM Like other auxiliary system of power plant, cooling water system is to be commissioned also before turbine rolling. Cooling water pumps are commissioned like other electrical motor-driven equipments. The motor is commissioned first without coupling with the pump. After successful commissioning of motor, alignment is done and a pump trial run is taken. Trial run of all cooling tower fans is completed one by one. There should not be any abnormal vibration or sound in the fan or its gearbox when it runs on load. During commissioning, some main activities are carried out in the cooling water system these are explained here.

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20.4.1  Commissioning of Cooling Tower A lot of civil job is done during the erection of cooling tower. After the completion of a cooling tower, tower and cooling water basin are cleaned properly. After cleaning of basin and tower, fresh water is filled. Any leakage in the basin is checked. If any leakage is found, it is arrested. All spray nozzles are checked. After starting the cooling water pump, water distribution valves are properly adjusted to get a uniform water distribution in all the cells. Water should be evenly distributed throughout the mixing area of each cell and this should fall freely into the basin. By starting the cooling tower fan, it is to be checked that the drift eliminator is perfect and there is no mist escaping.

20.4.2  Flushing and Passivation As discussed earlier, there is a chance of debris inside the cooling water pipeline and basin during erection. So, the system is to be flushed thoroughly to remove the unwanted solid particles. The cooling tower basin is flushed out by opening the blowdown valve. After erection, pipeline upto the condenser is hydro tested. This water is flushed out. If required, this pipeline is flushed with the help of main cooling water pump or through a temporary pump with temporary looping arrangement. After flushing the system thoroughly, the pipeline is connected to the condenser. And cooling water is circulated through the condenser tube for some days for passivation and formation of protective layer inside the condenser tube.

20.5  COMMISSIONING OF ELECTRICAL SYSTEM Before commissioning of boiler and turbine of the power plant, electrical system is commissioned first. The electrical system of a power plant comprises of the following subsystems:

• • • • • • • • • • • • •

HT switchgear LT motor control centre (MCC) Unit auxiliary transformer Generator and excitation system Neutral grounding resistance panel CT, PT and lighting arrester panel Automatic voltage regulator (AVR) Generator protection system Various electrical motors Plant lighting system AC and ventilation system Emergency power or DG Station DC supply system

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Figure 20.4 shows an electrical system of a power plant.

Figure 20.4  Electrical system of power plant.

Some of the important commissioning activities are discussed here.

20.5.1  Charging Switchgear Panels Before charging any switchgear panel for the first time, following points are checked thoroughly:

• • • • •

Panel wiring is complete. Panel is free from any unwanted material, wires, cables, etc. Bus bar is properly supported with a bus insulator and there is no loose connection. All cables are properly terminated. Protective relays are tested and setting is properly coordinated. Relays are in operational condition. • Internal control wiring is as per the approved drawing. • Panel is properly earthed and the earth resistance is measured.

After checking the above points physically, the panel bus bar is meggered thoroughly. Before charging power on the bus bar, control supply is given to the panel and control function and interlock of the panel is checked. Outgoing feeders are turned off during this activity.

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Once all these activities are completed, the bus is charged and kept under observation. Now, the outgoing feeders can be charged one by one. Ensure that the protection system is on line. In this way, HT and LT switchgears including power control centre (PCC) and motor control centers (MCC) are charged.

20.5.2  Commissioning of Transformers After erection, the transformer is filled with new transformer oil. Oil filtration is started to improve the insulation resistance of transformer winding and the breakdown value of transformer oil. This filtration may take some days depending upon the size of transformer and initial insulation condition of the transformer. There should not be any leakage of oil from the transformer’s body, radiator or bushings. Fresh silica gel is filled in the breather. After oil filling in the transformer, following tests are conducted:

• Ratio test of transformer • Insulation resistance value of primary and secondary winding • Testing of all the protective relays including Buchholz and winding temperature switch • Earthing resistance • Vector group test • Oil breakdown value

Once all these tests are carried out and satisfactory result is obtained, the transformer is charged, keeping the secondary side open. Transformer is charged on no-load. In this condition, transformer is kept for some days. Any abnormal temperature raise, high current or high secondary voltage is monitored. Once the transformer is found perfect on no-load, then loading can be done gradually on the secondary side.

20.5.3  Commissioning of Motors HT and LT motors are used for various applications in a power plant. LT motors are connected to respective MCCs and HT motors are connected to HT switchgear. Before taking trial of any motor for the first time, the following points are checked thoroughly:

• Power cable is terminated properly at both ends and having a desired insulation resistance value. • Insulation resistance (IR) value of the motor winding is satisfactory. • Motor is properly earthed. • The motor is rotating freely in decoupled condition. • The motor is properly fixed to the foundation. • Control cable is laid properly and connected as per the drawing. • Overload setting is done as per the rating of the motor and proper rating fuse is put at the MCC. • In case of HT motor, the breaker is operating perfectly. • Space heater, if provided, is on line.

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After checking the above points, motor can be started from local in decoupled condition. Direction of rotation is checked. There should not be any abnormal vibration, bearing temperature, current and sound in the motor. The motor is allowed to run on no-load for some time. Interlock of the drive is checked. Motor trial is taken from remote or control room. If a group of motors are required to run in interlock, individual motors are commissioned by passing the interlock and then, they can be tested with interlock. Once no-load trial run of a motor is found satisfactory, then it can be coupled for load trial run along with a mechanical equipment.

20.5.4  Commissioning of Generator Protection System As discussed in Chapter 19, various relays are used for the protection of generator. All CTs and PTs are to be tested. Before trial run of the generator, these relays are to be tested through primary and secondary test sets and setting is to be done as per the relay coordination. Control wiring of the protection panel is to be checked. This should be as per the approved drawing. There should not be any loose connection at the relay terminal or terminal box. The wiring of panel should be properly dressed. Now, control supply to the relay panel is charged. Tripping of each relay is simulated. The tripping condition of generator and turbine should be tested along with annunciation with each relay operation.

20.5.5  Commissioning of Generator Commissioning of generator is a complex activity. This is the sum of some individual activities from voltage build up at the generator to synchronisation, loading and load shading on the generator. Some of the steps followed during commissioning of generator are discussed below: IR Value and PI Value of Winding Life of generator depends upon the strength of insulation. During transport, storage and erection, moisture may be absorbed by the insulating material which is required to be dried out. Insulation resistance (IR) values of both stator and rotor windings are measured with the help of a megger. IR test measures the resistance of an electrical insulation between the winding and core of the stator or rotor. The purpose of insulation is to block the current flow between the winding and the core. So, ideally this resistance should be infinite. In practice, IR is not infinitely high. This value should be more than as specified by the generator manufacturer. Polarisation index (PI) test of the generator winding is carried out to measure the absorption of current due to polarisation of insulation. PI is a variation of insulation resistance with time. It is the ratio of IR value measured after voltage applied for 10 minutes (R10) to the IR value measured after voltage applied for one minute (R1). Following procedure is to be followed during PI test:

• Remove all external connections to the generator and completely discharge the winding to the grounded machine frame.

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• Through a 1000/5000 volt motorised megger, apply DC voltage between the winding and ground. • Continue to apply this voltage for 10 minutes. • Measure the insulation resistance and note it down. • Stop the megger. • Completely discharge the windings to the grounded machine frame. • Start the megger and reapply voltage for 1 minute. • Measure the insulation resistance and note it down. • Calculate the polarisation index (PI) by dividing the ten minutes insulation resistance by one minute insulation resistance.

The value of PI, generally, should be above 2. In general, a high value of PI indicates good condition of insulation. If the PI value is less, then steps should be taken to dry the insulation and remove moisture. Voltage Build-up Before voltage build-up in the generator for the first time, the following points are to be thoroughly checked:

• All connections in the generator terminal are properly done. • IR and PI values of the generator winding are satisfactory. • Hipot (high potential) test is carried out on the generator stator winding (in most of the cases, hipot test is carried out at the generator manufactures’ testing laboratory) • Neutral point of the generator is earthed through NGR. • Generator protection system is on line. • Protection and metering CT terminal are not open. • AVR function is tested independently with a test load. • Excitation system is working properly. • Turbine is running at full speed. • Generator is properly earthed. • Generator cooling system is on line.

Once the above points are found satisfactory, the field breaker can be closed. Voltage builds up slowly. Now, observe the output voltage. There should not be any abnormal sound, spark and smoke from the generator, NGR, CT and PT panels. In no-load condition, the generator should run for some time. Open Circuit and Short Circuit Test In an open circuit test of the generator, the output voltage is measured with various field currents during no-load. The reading is plotted and the curve obtained, as shown in Figure 20.5, is termed as open circuit curve. In short circuit test, the output terminal is shorted with a suitable shorting link. This link should be capable to carry the full load current of the generator without overheating. Turbine runs at a lower speed and this speed is maintained constant throughout the test. Small amount

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Figure 20.5  Open circuit curve.

of field current is applied. As the output terminal is shorted, so the short circuit current flows at a very less amount of the field current. Now, the field current is increased gradually till the full load current is circulated in the short link. The curve of short circuit current versus field current is called short circuit curve. This curve is shown in Figure 20.6.

Figure 20.6  Short circuit curve.

Mostly, these two tests are carried out at the factory of a generator manufacturer. Still, an open circuit test is carried out during commissioning for checking and for future reference. After these two tests, the generator is ready for synchronisation and loading. Before synchronisation of generator for the first time, the phase sequence is to be checked properly. Once the set is synchronised as per the normal procedure (discussed earlier), load on the generator can be raised. The winding temperature, cooling air temperature, etc. are to be monitored regularly. Load Throw Test In this test, the generator is tested to find out the behaviour of AVR and turbine governing system during sudden reduction of load on the generator. The generator is allowed to run at more than 70% load. Suddenly, the tiebreaker, as shown in Figure 20.7, is opened. By doing so, the load of the generator comes to station load. There should not be voltage shoot up or overspeed due to shading of such a huge load. AVR and governor should be able to take care and bring back these parameters in control.



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Figure 20.7  Load throw test.

20.6  PERFORMANCE GUARANTEE (PG) TEST Performance guarantee (PG) test is carried out to measure the performance of the equipment as guaranteed by the manufacturer. The manufacturer of boiler, turbine and generator claims some minimum performance during the offer for the supply of equipment. After erection and successful commissioning of these equipments, these performances are measured before handover from the manufacturer to the power plant owner. For measuring the performance, some parameters are measured. Before PG test, the test procedure is prepared. In this procedure, the parameters to be measured and the means of measurement are decided. It is mutually agreed for how much time this test will be conducted. In some cases, it is carried out for one hour and in some cases, it is conducted for one day. The frequency of measurement is also decided prior to the commencement of PG test. The complete testing procedure is detailed as follows:

• Testing methodology:  The standard testing methodology is decided. • Testing equipment:  Who has to provide it; where it is to be located; how sensitive it must be, etc. are decided. • Tolerances:  The margin of error is decided. • Ambient conditions:  The atmospheric conditions assumed to be the base case are decided. Accordingly, testing results are adjusted to take into account any variance from these ambient conditions.

To measure the parameters, some standard measuring equipments or calibrated instruments of the plant process control are used. Which instruments are to be used for the measurement of which parameter is decided prior to PG test. Once all this procedure is decided, PG test can be carried out. Normally, PG test procedure is supplied by the manufacturer. It is preferred to conduct the PG test as early as possible after commissioning. In the subsequent sections, details of the PG test procedure of boiler, turbine and generator are given separately.

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20.6.1  PG Test of Boiler A boiler manufacturer claims mainly the following performance which is to be checked during PG test:

• • • • • • •

Specific fuel consumption per kilogramme of steam Purity of steam Efficiency of boiler Steam pressure and temperature at various load conditions Minimum and maximum rating Stability during load fluctuation Stack gas quality

To measure the above, it is required to measure some parameters. All the measuring instruments are calibrated. A PG test log sheet is prepared to note down these readings in a predetermined time interval, as mutually agreed. This log sheet is kept as a record for reference in the future. For measuring these parameters, normally, the plant process instruments are used. Following parameters are normally measured to calculate the above claimed performance:

• • • • • • • • • • • • • • • •

Fuel flow Feedwater flow Air flow Steam flow Desuperheating water flow Steam pressure Steam temperature Steam conductivity, silica Feedwater inlet temperature Exhaust flue gas temperature CBD flow Excess air or O2 percentage in flue gas Flue gas analysis Ash quantity Unburnt carbon in ash Drum level

A boiler is allowed to generate steam at various load conditions. Its capability to generate steam at required parameters and required efficiency is checked. As far as possible, it is required to maintain input parameters like calorific value of fuel, inlet feedwater temperature, etc. as per the design basis of the boiler to obtain the required performance. The heat transfer surface is to be kept clean by using soot blowers. If the input parameters change, then a suitable correction is made to calculate the performance. Once PG test is completed successfully, PG test log sheet is signed by the supplier and the owner representative. This sheet should be kept for the future reference to refer for any deviation in the performance.

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20.6.2  PG Test of Turbine Like boiler, a turbine manufacturer also claims some guaranteed performance, as mentioned below:

• • • • • • • • •

Specific steam consumption per kilowatt hour generation Exhaust steam temperature Condenser vacuum Auxiliary steam consumption in ejectors and gland sealing system Steam flow and heat contents in bleeding/extraction steam at different load conditions Vibration and temperature of bearings Noise level Stability during load throws Efficiency

To check these performances, some parameters are measured. The following parameters are measured using process instruments or some standard testing instruments, as decided mutually:

• • • • • • • • • • •

Steam flow Steam pressure and temperature Auxiliary steam flow Exhaust hood temperature Condenser vacuum Inlet and outlet cooling water temperature Condensate temperature and flow All bearing vibration and temperature Noise level around turbine Load on generator Control chamber pressure and temperature

20.6.3  PG Test of Generator For the PG test of generator, following parameters are measured.

• • • • • •

Generator power Terminal voltage Frequency Current Power factor Winding and air temperature

During PG test, load throw test is carried out, as described earlier. Also, the generator is tested at 110% loading in valve wide open (VWO) condition.

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EXERCISES 1. 2. 3. 4. 5. 6. 7. 8. 9. 10.

Why are chemical cleaning and alkali boil-out of a newly erected boiler required? What is passivation? Why is lube oil flushing carried in a turbine lube oil pipeline? Why is the steam blowing carried out? What precautions are to be taken during steam blowing? What happens to the boiler drum level during steam blowing? What is target plate? What is the function of a target plate? What are IR and PI values of a generator? Why is PG test carried out?

Chapter

21

Maintenance of Power Plant

21.1  INTRODUCTION Critical machines like turbines, pumps, fans compressors, etc. are used at a power plant. Each machine is required to run trouble-free to keep the power plant running. Failure at any of the machine may lead to the stoppage of power generation, costly replacement of machine or its parts. Also, in case of captive power plants, it may lead to other process loss. Availability of these machines increases the availability of power plant. Every equipment is having its own service life. Machine has its own life cycle. It has to pass through various stages. Various types of failures are noticed at various stages of life cycle of a machine. A plot of the failure rate over time for most of the machines looks like a bathtub. Life cycle of any machine, called bathtub curve is shown in Figure 21.1.

Figure 21.1  Bathtub curve.

When a new machine is put into service, some small failures are experienced due to design weakness or defects during manufacturing. A number of teething problems are experienced at this stage before the machine is stabilised. Sometimes, severe failures are also noticed. Teething problem is characterised by a high but rapidly decreasing failure rate. This decreasing failure rate lasts from several days to few weeks.  This stage is called infant stage. Some machines, stabilise quickly; some take longer time. Modification in some parts or strengthening of some weak components may bring down the failure rate in this stage. 439

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After infant stage, the machine enters into useful service life stage. Failure rate is very less in this stage and remains mostly constant for the majority of useful life of the machine. Only some small failures are experienced. Regular checking, lubrication, tightening, cleaning, etc. are required to keep the machine running in a trouble-free manner. The machine gives useful service life with proper cleaning, lubrication, inspection and lightening (CLIT) practices. Due to wear and tear, stress, etc. the machine life is deteriorated at the end of useful service life. Decaying stage of the machine is started. Some bigger failures take place in this stage. Wear-out failures take place at an increasing rate. It is required to take special care at this stage to keep the machine running. In dictionary, maintenance is defined as the work of keeping something in proper condition. Simply, it can be said that maintenance is the action taken to prevent a machine or component from failure. It is the activity to repair or avoid the normal equipment degradation due to continuous operation of the equipment and keep it in a proper working condition. In this chapter, first, we will discuss some normally adopted maintenance practices in power plant. Then, we will analyse some basic failures in power plant equipment and some maintenance methods. We will also describe some of the statutory procedures which are normally followed for the repair of boiler pressure parts.

21.2  TYPES OF MAINTENANCE PRACTICES Various maintenance practices are adopted in a power plant. All these practices have their own merits and demerits. Sometimes, a combination of more than one practices is followed. The maintenance practice adopted depends upon the criticality of plant, company’s maintenance strategy for avoidance of plant outage and risk involvement due to the failure of power plant and equipment. Depending upon the situation, a suitable maintenance practice is adopted. But, as the failure of power plant costs heavily and creates secondary losses also, so nowadays, sophisticated maintenance practices are followed. In the subsequent sections, all these maintenance practices are discussed.

21.2.1  Breakdown or Corrective or Reactive Maintenance In breakdown maintenance practice, maintenance is carried out as and when required. When any breakdown or failure of any equipment takes place, then only maintenance is carried out. This practice mostly leads to failure of plant operation. The machine is allowed to run till it fails. As nobody knows or no action is taken to check the healthiness of equipment, so reliability of the machine is very less. At any moment, any machine may fail and leads to plant stoppage. In this practice, no maintenance is carried out when the machine runs smoothly. There may be some saving at the beginning. But once there is breakdown, the cost of maintenance is high. A costly critical spare is required to be replaced. Plant operation suffers, loosing heavily due to stoppage of generation. Also, due to the failure of some critical equipment, there may be severe damage to man and machine. The main drawbacks of this system are listed below:

• High cost due to unplanned downtime of machine and plant • Increased repair cost due to replacement of costly spare and involvement of skilled maintenance staff

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• Probability of failure of secondary equipment or process damage (For example, breakdown in lubrication oil system may cause severe damage to turbine and stop power generation for quite a long period.) • Inefficient use of maintenance staff. • Less opportunity for improvement (as most of the time, maintenance people are busy with breakdown job.)

This maintenance practice is not advisable at any power plant. Most of the maintenance engineers are engaged to attend breakdown repair, hence getting less time for the improvement in plant. To avoid this, other suitable maintenance practices are to be followed. There may be some sporadic failure or breakdown even if other sophisticated maintenance practices are followed. In this condition, breakdown repair may be carried out. But, if other maintenance practices are followed efficiently, then definitely, there will be drastic reduction in the breakdown.

21.2.2  Preventive or Schedule Maintenance In preventive maintenance is carried out on time based or machine running hour-based schedule to detect, repair or replace, control degradation of components and increase the useful life of machine. Through this maintenance practice, reliability, machine useful life and availability increase. Breakdown is minimised by avoiding degradation. Though this maintenance practice is not fully helpful and efficient still, it is more acceptable than breakdown maintenance practice. In this practice, a maintenance schedule for each equipment is prepared. This schedule may be time-based (daily, weekly, monthly, quarterly or yearly) or machine running hour-based (1000 hours, 5000 hours, etc.). Necessary maintenance like checking, inspection, lubrication, bearing replacement, oil changing, etc. is carried out as per the schedule. Some of the terms used in preventive maintenance are discussed here. Maintenance schedule:  This is simply a chart that shows various maintenance activities and the intervals at which these activities should be done. The maintenance frequency of any equipment is decided by the following factors:

• • • •

Age of equipment Criticality of equipment Past history of failure Manpower availability

Schedule of maintenance, for more critical and older equipment having more failures in the past, may be planned at smaller interval. For new, non-critical equipment, maintenance may be scheduled at longer interval. All the equipment of power plant may be covered in this schedule. Different maintenance frequencies are is marked differently in the chart. Once a schedule is prepared, it can be translated to actual dates to plan when to perform various preventive maintenance activities. Different types of maintenance are carried out during different schedule as per the predetermined job list mentioned on the checklist. After completion of that particular schedule maintenance job,

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the chart is updated. Frequency of maintenance may be revised depending upon the machine condition during the last maintenance. Checklist:  Checklist for each equipment, listed on the schedule maintenance chart, is prepared. In this checklist, list of jobs that are to be carried out during different schedules are described. Jobs to be carried out during monthly maintenance, are not same as yearly maintenance. Jobs to be carried out are decided based on the factors described earlier. History book:  Each and every equipment should have a history book. Detailed specification of the equipment and spares used in it are listed in this history book. Jobs carried out on the equipment like date of job done, nature of job done, condition of the equipment before maintenance, abnormality found, spares changed/replaced during maintenance, condition of equipment after maintenance, etc. are logged on history book. From this history book, history of failures of that particular equipment can be obtained and mean time between failures (MTBF) can be found out easily. It provides a lot of information about the past failures and repair methods. For inventory planning also, this is helpful. Lubrication schedule:  For any moving equipment, lubrication plays a major role to get a desired useful life of that equipment. Proper lubrication programme of any plant can minimise the failure. Moving parts are required to be lubricated to minimise wear and tear. So, each plant should have a well designed lubrication schedule. First of all, each point of lubrication in an equipment is identified. Types of lubricants to be used are decided as per the recommendation of equipment manufacturer. The quantity of lubricant and the frequency of lubrication are decided based on the running pattern of the equipment, lubrication condition and past experience. Like this, each point of lubrication of all the equipments is considered and a schedule is prepared. As per the lubrication schedule, lubrication is carried out and recorded. Lubricant used should be free from contamination. Merits of Schedule or Preventive Maintenance Preventive maintenance is a planned maintenance programme. The component to be changed is planned well in advance. The job to be carried out is well known. So, manpower requirement can be forecasted easily. As the maintenance is carried out periodically, so rate of failure of equipment reduces and hence the loss of generation can be minimised. The equipment life and availability increase.

21.2.3  Predictive Maintenance In preventive or schedule maintenance practice, maintenance is carried out at a predetermined interval without considering the actual condition of equipment. Most of the time, unnecessary repairs are carried out which is not required at all, as per the actual condition of equipment. So, maintenance cost in schedule maintenance is more. Suppose the bearing of a pump is to be replaced after 10,000 running hours. It is not considered that the bearing may be in better condition and can be used for another 5,000 hours. The bearing is replaced by a new one without considering the actual bearing condition. In this case, maintenance cost cannot be optimised. Also, the bearing may fail well before its schedule.

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But, in predictive maintenance practice, the actual condition of equipment is checked regularly. Degradation is measured with the help of diagnostic equipments and maintenance is carried out accordingly to eliminate this degradation and avoid significant failure. The maintenance is not time-based but based upon the actual condition of equipment in this case. So, maintenance cost can be optimised by using the equipment parts optimally. Merits of Predictive Maintenance

• • • • • •

It reduces spares and inventory. The equipment is used optimally. It reduces unnecessary repairs. It eliminates catastrophic equipment failure. It reduces costly downtime. Maintenance can be done during idle period.

In power plants, this predictive maintenance practice is most suitable. Some maintenance engineers prefer to carry out maintenance thoroughly in a year during the boiler’s annual inspection and avoid any plant stoppage in between. Also, the condition of the equipment is monitored to check its healthiness and if required, maintenance is carried out during minor stoppages or idle period. The maintenance practice of any power plant is to be decided based on the situation and flexibility of the plant.

21.2.4  Condition-based Maintenance (CBM) Condition-based maintenance practice is nothing but a predictive maintenance practice. Degradation of the equipment is measured by sophisticated instruments. Equipment condition is monitored and suitable maintenance is carried out before any breakdown, preferably in the next available idle or low load period. Condition of the equipment is monitored through various condition monitoring instruments. Vibration, temperature, thickness, debris analysis and thermography are some of the condition monitoring methods adopted. For example, vibration measurement of any bearing can indicate the bearing condition. Debris analysis report of turbine oil can indicate any metal particle and hence, operating condition of the bearing. Raise in the stage pressure of turbine indicates deposition on blades. Tube thickness of the boiler can be measured to analyse the tube condition. Condition analysis can provide information if a trend is prepared and analysed. Equipment condition in any power plant is to be monitored properly. Trends of these parameters are to be prepared to decide what type of maintenance is to be carried out. Figure 21.2 shows the equipment condition monitoring.

21.2.5  Proactive Maintenance Proactive maintenance practices aim to eliminate the root cause of the failure. So, it is one step ahead of the other maintenance practices. Any failure is having some root cause. For example, turbine failure due to failure of bearing can be eliminated by maintaining the quality of turbine

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Figure 21.2  Equipment condition monitoring.

lubrication oil. So, in proactive maintenance, emphasis is given on the cleanliness of lube oil, not on the bearing failure. Proactive maintenance has the following three steps:

• Setting a quantified target relating to root cause of failure like lube oil cleanliness • Implementing maintenance plan to keep this root cause within the target level like routine filtration of oil, removal of contaminants • Routine monitoring of root cause with suitable technique like testing of oil As the root cause of the failure is taken care, so probability of failure reduces.

21.2.6  Total Productive Maintenance (TPM) Total productive maintenance (TPM) is a Japanese concept. It is a corporate cultural change programme, developed by Japan Institute of Plant Maintenance (JIPM). It is an approach to bring changes in the culture and performance of the plant operations by adopting structured maintenance practices. TPM is a proactive approach that aims to prevent any kind of failure before its occurrence. This is a maintenance programme which involves a newly defined concept for plant and equipment maintenance to optimise the productivity of equipment through systematic equipment maintenance involving the employees at all levels.  TPM focuses maintenance as a necessary and vitally important part of the plant. In TPM, maintenance is no longer considered as a non-profit activity. TPM cannot be implemented overnight. Normally, it takes at least two to three years to implement. TPM activities are carried out in small teams with specific tasks. Everyone is involved in keeping the equipment in good working order to minimise the production losses from equipment repairs, assists and set-ups. TPM aims to eliminate the following six big losses: 

• • • • • •

Breakdowns which can result in long, expensive repairs  Set-ups conversions and changeovers  Idling and minor stoppages  Reduced equipment speed/capacity  Defects and rework  Start-up losses



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5S First step of TPM implementation is 5S. 5S stands for five Japanese words that start with the letter S, i.e. Seiri, Seiton, Seiso, Seiketsu and Shitsuke. It is translated into English starting with the alphabet S. 5S stands for workplace organisation methodology. Problems cannot be clearly seen when the workplace is unorganised. Cleaning and organising the workplace helps to uncover the problems. Making problems visible is the first step of improvement in maintenance. Seiri (sort out):  The first step of the 5S process is Seiri or sorting out. All unwanted, unnecessary and unrelated materials in the workplace are sorted out by organising the items as critical, important, frequently used items, useless or items that are not required now. Unwanted items are thrown out. Critical items for use are kept nearby and items that are not going to be used in the near future are stored in some other place. This is done to ensure that everything left near the workplace is related to work. Also, the number of necessary items in the workplace are kept as minimum as possible. Seiton (systematic arrangement):  The concept, here, is ‘a place for everything and everything in its place’. By putting everything in an assigned place, it can be located quickly and kept at that place quickly. Every single item is allocated its own place for safekeeping and each location is labelled for easy identification of what it is for.  To identify the items easily, name plates and coloured tags are used. Vertical racks are used for this purpose and heavy items are stored at the bottom position in the racks. Seiso (shine):  This involves cleaning the workplace and making it free from dust, grease, oil, waste, scrap, etc. No loosely hanging wires or oil leakage from machines should be there. Seiso not only focuses on the cleaning of the working environment once, but also keeps it clean everyday to maintain the facility and equipment forever. Seiketsu (standardisation):  Standards are defined by which cleanliness can be measured and maintained.  It takes care of both personal and environmental cleanliness. Standardisation is helpful to detect abnormalities and unusual situations so that people can react immediately. Shitsuke (self-discipline):  It speaks about commitment to maintain orderliness and practice the first 4S as a way of life and bring self-discipline. TPM has eight pillars of activity, as discussed below: Pillar 1–Jishu Hozen (Autonomous Maintenance) This pillar focuses towards the developing operators to be able to take care of small maintenance tasks. The operators are responsible for daily maintenance activities of the equipments on which they are working to prevent them from deterioration. By this, the skilled maintenance people are utilised for more value-added activity and technical repairs. Pillar 2–Kaizen Kai means change and zen means good (for the better). Basically, kaizen refers to small improvements on continual basis. Kaizen requires no or little investment. A very large number of small improvements are more effective in a plant than a few improvements of large value. This pillar is aimed at reducing losses in the workplace that affect our efficiencies.

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Pillar 3–Planned Maintenance It is aimed to have trouble-free machines and equipments. With planned maintenance, focus is shifted from reactive to proactive method of maintenance and trained maintenance staff is used to train the operators to maintain their equipment in a better way. Pillar 4–Quality Maintenance This pillar focuses on maintaining the quality. Defects are eliminated in a systematic manner using techniques such as prevention of defects at source, mistake-proofing and effective introduction of operator quality assurance. It is believed that maintaining perfect equipment helps in maintaining the quality products. Condition of the equipment is set and is checked/measured regularly to conform values are within the standard. Through this, possibilities of defects are predicted before occurring and counter measure is taken before it takes place. Pillar 5–Initial Flow or Early Equipment Management The knowledge which has been developed to achieve the improvements in equipments through TPM implementation is now directed towards the development, design and implementation of new equipments which are to be procured and arrived at the plant. So, the new plant and equipment are capable to achieve their planned performance level immediately after commissioning. Pillar 6–Training Workforce is the asset of any organization. In this pillar of TPM, it is aimed to have multiskilled employees with high morale and having capability to perform all the required functions effectively and independently. Education and training are given to the people to upgrade their knowledge and skill to create sufficient number of experts in the plant. It is the requirement to train them to know why instead of know how. The employees are trained to achieve four phases of skill that are as follows:

• • • •

Do not know Know the theory but cannot do Can do but cannot teach Can do and also teach

Pillar 7–Office TPM Administrative function is a support system to the main plant production. Office TPM is followed to improve the productivity and efficiency at administrative areas and identify as welll as to eliminate the losses. This is possible by adopting suitable processes and procedures for better office automation. Pillar 8–Safety, Health and Environment (SHE) The aim of this pillar is to provide safe and healthy working place in the plant and take care of environment. People are motivated to work safely and keep the working environment healthy. To create awareness among people, slogans, quiz, drama, posters, etc. related to safety, health and environment are organised at regular intervals. Target is fixed to attain

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• Zero accident • Zero health damage • Zero fires

21.3  FAILURES IN POWER PLANT As discussed earlier, each equipment fails during its operation due to degradation of its components, abnormal operating conditions or faulty design. Failure of any equipment in power plant leads to huge loss. Sometimes, failure may lead to severe accident. High temperature and high pressure steam is used at power plants. So, failure in boiler or pipeline may create dangerous situation for man and machine. Also, the failure of turbine may take longer time to repair and the repair cost is very high. In power plants, different types of failures are experienced. Among them, some are repetitive in nature and some are sporadic. Maintenance staff of the plant is acquainted with repetitive nature of failure like oil leakage and steam leakage. But failures which are very rare requires higher skill to handle. These sporadic failures are to be handled properly. All these failures are to be analysed and the root cause of the failure is to be find out. In the subsequent sections, some major failures in power plant equipments are discussed.

21.3.1  Failure in Boiler Various types of failures are noticed in a boiler. For a small failure, the boiler is not required to be stopped. It can be attained while the boiler is in operation. In some cases, the boiler is to be stopped to attain this failure. Some of the major failures in boilers are discussed here. Boiler Tube Leakage Leakage of tube is commonly observed in a boiler. For attaining this problem, the boiler is to be stopped and the leakage tube is to be replaced or repaired. Leakage can be detected by symptoms like loss of water, noise in boiler or disturbance in boiler water chemistry, etc. If the leakage is minor, boiler can be continued to run for some time. If the leakage is severe, the boiler is to be stopped immediately and cooled down to take the repairing job. It is not advisable to run the boiler for longer period with leakage tube. It may damage some healthy tubes also. Leakage of the tube may take place due to the following reasons:

• Scaling • Erosion • Corrosion

Scale may form at fireside and waterside of the tube. Fireside scaling takes place due to the deposition of combustion products at the outer surface of the tube. This deposition forms hard surface on the tube surface. Due to poor water chemistry, waterside scaling takes place. Presence of scale affects the heat transfer, as it is a bad conductor of heat. Tube fails due to the overheating of tube material.

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Corrosion also takes place at both fireside and waterside of tube. Due to aggressive surrounding medium, the tube is corroded. Corrosion makes the tube material thin and it may fail. Failure of protective layer leads to pitting of the tube. Erosion is a mechanical phenomenon and takes place due to process like friction, impact, turbulence, etc. Due to abrasive combustion particles, tube is eroded and its thickness reduces which lead to failure of the tube finally. Other than the above reasons, tube may fail due to the corrosion fatigue and stress corrosion cracking. Tube may burst due to starvation and overheating. Opening of this burst looks like mouth of a fish. So, it is called fish mouth opening. There may be corrosion at the lower temperature zone of air heater and economiser due to sulphuric acid vapour dew point. This is called acid corrosion or low temperature corrosion. Failure Mechanism of Boiler Tube As discussed earlier, leakage of boiler tube takes place due to scale, corrosion and erosion. In this section, we will discuss some more failure mechanisms responsible for the tube leakage. These failures are to be eliminated to minimise the tube leakage. To analyse the causes of failure, the following mechanisms are to be understood clearly: Pitting:  Due to the presence of oxygen in feedwater, pitting is normally formed. Oxygen reacts with the tube metal to form iron oxide. The tube internal surface is corroded in deep grove spots called pitting. This can happen in the running boiler due to excessive oxygen in the feedwater or due to improper passivation. Pitting is normally observed near the economiser feedwater inlet area of a running boiler. Due to improper passivation, this can observed at non-drainable surfaces. Stress corrosion cracking:  Stress corrosion cracking takes place where combination of high tensile stress and corrosion fluid are present. The damage is in the form of crack which propagates from tube internal wall. There may be transgranular or intergranular crack in the tube wall. Normally, this is observed near higher external stress areas like attachments. It is characterised by a thick wall, brittle type crack. Corrosion fatigue:  This type of failure takes place due to the combination of thermal fatigue and corrosion. It happens due to improper design, water chemistry and oxygen contents in the feedwater. Due to the combination of these, protective magnetite layer of tube inside the wall is damaged and the tube wall is exposed to corrosion. Normally, this type of failure takes place near the external attachments. This failure is characterised as wide transgranular cracks. Short term overheat:  Due to insufficient fluid flow in the boiler tube, particularly in superheater, tube metal temperature reaches dangerously high level and lead to ductile rupture of the tube. This is characterised by an opening called fish mouth, as shown in Figure 21.3.

Figure 21.3  Fish mouth opening.

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Long term overheat:  Due to restriction in flow, scale deposits, etc., metal temperature increases and continues to operate for longer period and the tube fails finally. This type of failure is characterised by minimal swelling and a longitudinal split that is narrower than the fish mouth opening. Tube metal often has heavy external scale build-up and secondary cracking. This can be seen in superheater and furnace wall tubes. Fireside corrosion cracking:  Tube outside surface is exposed to corrosive flue gas and subjected to thermal fatigue. This thermal fatigue can initiate cracks on the less elastic scales deposited on the tube’s external surface and expose the tube material to the corrosive flue gas. This type of failure is a characterised as a series of cracks that initiate on the outside surface of the tube and propagates into wall. These cracks are developed over longer period. These failures are normally observed at the furnace wall tubes. Caustic attack:  Where there is an excessive deposit inside the tube surface, water flow in contact with the tube reduces, causing local underdeposit boiling and the concentration of boiler water chemicals increases in that area. If the pH of boiler water is high, it results in a corrosive attack and breaks down the protective magnetite layer. This failure is characterised as localised wall loss at the inside wall of the tube. High temperature oxidation:  This can occur locally in areas that have the highest temperature like superheater, when outside surface temperature is more than the oxidation limit of the tube material. Graphitisation:  During long term operation, when the tube material is exposed to excessive temperature, it experiences dissolution of the iron carbide in the steel and formation of graphite nodules. This takes place in carbon steel tube of high carbon contents or in carbon–molybdenum steel. This failure is characterised as brittle with a thick edge fracture. Erosion:  Erosion occurs due to impingement on the tube external surface. The erosion medium may be abrasive particle of the combustion product or steam. Mostly, this happens due to the impingement of ash or during soot blowing. This is characterised by metal loss from the tube’s outer surface. Damage is oriented on the impact side of tube. Failure of Auxiliary System of Boiler Failure of any auxiliary equipment of a boiler may lead to the stoppage of boiler. These auxiliary systems are as follows:

• • • •

ID, FD and PA fans Boiler feed pump Fuel handling system Ash handling system

Some of the commonly experienced problems of these systems are discussed below. ID, FD and PA fans:  Every boiler is having fans to supply fresh air, evacuate flue gas and for conveying fuel, etc. In these fans, following problems are normally experienced:

• Vibration due to misalignment, disturbance in static and dynamic balancing because of deposition in fan impeller and failure of bearing

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• Failure of bearing • Wear out of impeller and shaft • High bearing temperature due to insufficient lubrication and chocking in bearing cooling system, etc. • Failure of coupling

All the fans are to be inspected thoroughly at a fixed interval. The bearing condition is to be monitored. Proper lubrication schedule is to be followed. The alignment is to be set right if it is disturbed. Boiler feed pump:  Boiler feed pump is a multistage high pressure pump. Normally, there are more than one feed pump for each boiler. So, the standby feed pump can be taken into operation immediately in case of any problem. Following problems are normally observed in a feed pump:

• • • • • •

Chocking of suction strainer Leakage from gland Failure of bearing Vibration Increase of bearing temperature Failure of coupling

Bearing condition of the pump is to be monitored continuously. Lubrication schedule is to be followed. Any leakage from the gland can be adjusted by putting a new gland seal or mechanical seal. Boiler feed pump is to be overhauled by a skilled maintenance personnel at a specific interval. Gland cooler and suction filter are to be cleaned as and when required. Fuel handling system:  Stoppage of fuel handling system equipment can lead to forced shutdown of the boiler. To avoid this, proper maintenance programme is to be followed to eliminate breakdown of equipments like coal crusher, screen, belts, pulveriser, coal feeder, fuel oil pump, etc. These equipments are to be inspected regularly and necessary repairing or replacing programme is to be made well in advance. Ash handling system:  Ash of the boiler cannot be evacuated, in case, there is any problem in this system. There may be failure in the ash feeder, ESP, ash transmitter, ash conveyers, etc. These equipments are to be inspected frequently to detect any deterioration and to be restored promptly.

21.3.2  Failure in Turbine Turbine internals are exposed to high temperature and pressure and they rotate at high speed. Some failure is experienced during operation of turbine. Rotating and stationary blades of turbine deteriorate due to prolonged exposure to high temperature. Mostly, failure of blade is the main failure of a turbine. Some of the commonly experienced turbine failures are listed below:

• Failure of blades • Failure of rotor

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• Failure of bearing • Wear out of steam seals • Failure of auxiliary system

Failure of Turbine Blades Failure of blades of turbine takes place due to the following failure mechanism: Stress corrosion cracking:  Like boiler tube, stress corrosion cracking takes place due to high stress and corrosive medium. Turbine blades are subjected to high tensile stress caused due to centrifugal force. Stress corrosion cracking is found in blades at low pressure zone. Steam quality also plays a vital role in stress corrosion cracking. The crack developed in the blades may propagate as transgranular or intergranular cracks on the blade body. Pitting:  Pitting may take place when passive protective layer of the blade is destroyed. Under the deposition of blade, very small anodic areas are formed in large numbers. So, pitting corrosion takes place. Normally, pitting is observed under blade deposits at the wet steam or low pressure (LP) blade stage. Pitting may take place at all stage blades when the turbine is kept standstill for longer period. This type of pitting is called shutdown pitting. Corrosion fatigue:  Due to stress reversal, any material is supposed to fail. This is called fatigue. The mechanism speeds up when the material is placed in a corrosive medium. Fatigue of material is produced due to thermal state change (thermal fatigue) and creep (creep fatigue). Failure due to corrosion fatigue is experienced as fracture. Corrosion fatigue can be avoided by maintaining the steam quality, as recommended by the turbine manufacture. Solid particle erosion:  During operation, scale and iron oxide are dislodged from steam pipeline and if they pass through steam strainer, they impact the blade at high velocity. Due to this impact, erosion takes place on the blade. Also, during erection, some foreign particles may be present at the piping system, which create solid particle erosion. This can be avoided by proper steam blowing before commissioning. The last stage blades handle moist steam. If steam temperature is not maintained properly, water droplets are formed at this stage. These heavier water droplets are responsible for the erosion of last stage blades. Deposits:  When the steam quality is not pure, impurities are deposited on the turbine blade surface. Silica is carried over from boiler to steam due to improper steam separation. This silica is deposited on the blade surface. Deposit on the blade reduces the turbine efficiency and leads to corrosion of blade. Turbine interstage or wheel chamber pressure can indicate the deposit condition of the blade. When deposit is more, the wheel chamber pressure increases. Creep:  It creep is the tendency of a solid material to slowly deform the material permanently to relieve stress. This is more severe when the material is exposed to heat for longer period. As the turbine blades and casing are exposed to high temperature for longer period, there is a chance of creep failure. Fatigue:  Due to speed change, change in load, etc., the stress on turbine blade changes. This may lead to fatigue failure. Normally, the blade root damaged due to fatigue.

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Failure of Turbine Shaft Rotor of the turbine is also exposed to high stress and high temperature with corrosive medium. After operation for a longer period, there is a chance of failure of rotor due to the following failure mechanisms:

• Normal wear • Fatigue • Stress corrosion cracking

The shaft is subjected to mechanical and thermal stress during operation. Also, due to change in load, start, stop, etc., it is subjected to cyclic stress. So, fatigue and stress corrosion cracking is experienced in the rotor. Failure of Turbine Bearing Bearing of a turbine is lubricated and cooled by lubrication oil. If the supply of this oil is interrupted while the turbine is in service, then the bearings will be severely damaged. During normal operation also, the soft babbiting metal of bearing is subjected to wear. So, the bearing clearance increases. Bearing is required to be changed when this clearance increases. Axial thrust of the turbine is taken by the thrust bearing. When this thrust is more, there is a chance of failure of thrust bearing. Old bearing can be used after rebabbiting. The condition of bearing can be monitored by the bearing temperature and vibration measurement. Bearing is to be opened when these values increase. Debris analysis of lube oil can indicate the worn out condition of the bearing. Problem of bearing should be detected at early stage and suitable action is to be taken, otherwise it can create severe damage to the turbine. Inter seals, stationary and moving parts may be damaged due to rubbing. To avoid bearing failure, the quality of lube oil is to be maintained strictly, as per the recommendation of turbine manufacturer. Oil centrifuge is to be used regularly for this purpose. Lube oil filter is to be cleaned when differential pressure increases. Wear Out of Steam Seals of Turbine Steam seals are used to restrict the steam to bypass any blade stage. Steam seals are also used at the gland portion of a turbine. Wear out of these seals is common. When steam seals are damaged, it decreases the efficiency of turbine, as steam is escaped to the next stage without doing any work. Also, sufficient steam is found leaking from the gland portion. These seals are damaged first when there is any rubbing. So, it is required to replace these seals whenever required. These seals are to be inspected during every minor and major overhauling of the turbine. Failure of Turbine Auxiliary System Sometimes, it is required to stop the turbine due to problem in the auxiliary system. Following problems are normally experienced in the turbine auxiliary system of a power plant:

• Failure of pumps (oil pumps, CW pumps and condensate extraction pumps) • Steam leakage • Condenser tube leakage

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• Chocking of steam ejector nozzles • Chocking or leakage of oil cooler tube

In most of the cases, there is a standby arrangement for the above systems. Problems can be attained by taking the standby system on line while the turbine is in operation, without taking shutdown. Failure of pumps:  Oil pump is used to supply lubrication oil to the bearings, condensate extraction pump is used to evacuate the condensate from the hotwell of a condenser and cooling water pump is used to circulate cooling water in the condenser. All these pumps are having standby arrangements. The plant may be required to stop in case of failure of any of the pump and if its standby pump is not available. Following problems are observed in these pumps:

• • • • • •

Leakage of fluid from the gland Failure of bearing Misalignment Vibration Failure of coupling Failure of shaft sleeve

By implementing a proper inspection schedule and condition monitoring technique, these failures can be eliminated. Standby pumps are always to be kept ready so that they can be put into service during emergency. Standby pumps are required to be changed into service regularly to ensure all the pumps are available for use. Gland leakage can be arrested by putting a new gland packing or changing mechanical seal. Condition of the bearing and alignment can be monitored by checking the vibration and bearing temperature regularly. Overhauling of pumps and replacement of worn out components are to be carried out as and when required. Stoppage of turbine due to failure of the above pumps can be eliminated if all the pumps are available. Changeover of these pumps can be done while the turbine is in operation. Steam leakages:  Due to the degradation of joint gasket and sealing material, sometimes, steam leakage is observed from flanges, valve bonnet and gland. When leakage is severe, plant is required to be stopped to arrest this leakage. Nowadays, online sealing technique is available. These leakages can be arrested through online sealing technique without stopping the plant. Sometimes, leakage in the pipeline is observed due to crack or puncture. Welding is required in this case. Condenser tube leakage:  Due to corrosion, condenser tube is punctured. This can be detected when the conductivity of condensate increases. As the conductivity of cooling water is high, so, mixing of cooling water with condensate (due to leakage of tube) increases the conductivity of condensate. This leakage is to be arrested as quickly as possible to avoid further damage of the boiler tube. If the condenser is having multipass arrangement, then this leakage can be attended while the turbine is in operation by reducing the load on turbine and isolating one pass. Both ends of the leaked tube can be plugged temporarily and the tube can be replaced later on.

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Leakage of tube can be detected by filling condensate above the tube bundle at the shell side of condenser. The condensate then leaks through the leakage point and comes out from the tube end. Chocking of steam ejector nozzle:  Any dislodged corrosion particle may chock the throat of an ejector nozzle. In this case, sufficient vacuum does not build up at the condenser. Standby ejector can be put on line and the chocked nozzle can be cleaned in this case. Chocking or leakage of oil cooler tube:  Lube oil is cooled before it is supplied to the bearing. Cooling is done in the oil cooler. Cooling water flows inside the tube and oil flows at the shell side of the oil cooler. Scale and sludge are deposited at the inner side of the tube, affecting the heat transfer. The outlet valve of cooling water is normally throttled to maintain the oil temperature. When the tube is chocked, this valve is required to be opened more. This indicates that the tube is getting chocked. Tube is to be cleaned before the condition when the oil temperature cannot be maintained by opening this valve fully. Due to corrosion, this tube may leak. As the oil pressure is more than the cooling water pressure, so in normal condition, oil mixes with the cooling water and can be traced at cooling tower. But there is a chance of mixing of cooling water into the oil when the oil pump does not run or it is at a standby cooler. This leaked tube is to be plugged as soon as the leakage is detected. Problem in Cooling Tower As we know, cooling tower plays a major role for the efficient operation of a steam turbine. Hot cooling water from the condenser is cooled at cooling tower which is again recirculated to the condenser. Reduction in temperature of cooling water at cooling tower is required to maintain a desired vacuum at the condenser and hence, the efficiency of the turbine too. The difference in the inlet and outlet temperatures of cooling water at a cooling tower is called differential temperature. For effective cooling of water at cooling tower, fans are used. Due to larger size blade, peripheral velocity of these fans is more. Any deformation of blade profile or any problem at the reduction gearbox can create severe vibration and lead to damage of these fans. So, proper care is required to be taken to maintain these fans in continuous operation. Blade profile is to be checked regularly and damaged blades are to be replaced. After changing the blade, rebalancing of fan is required. Normally, vibration switches are provided to trip the fan in case of excessive vibration. It is to be ensured that the vibration switch functions properly. Cooling tower fan is operated in moist atmosphere. It is found that the base frame and foundation bolts are badly corroded. It is to be checked regularly. Normally, in most of the power plants, cooling tower is neglected, causing severe damage to the blades and gearboxes. There is a chance of contamination of lubrication oil of the gearbox. Failure of oil seals may cause oil leakage from the gearbox. Gears get damaged if the oil level is not maintained at the gearbox. To take care of this, oil level of the gearbox is to be checked regularly and if required, the oil is to be added. Oil is to be checked regularly to find out any contamination. Coupling of drive is to be checked regularly. Where cooling tower is placed in a dusty atmosphere, the atmospheric dust mixes with water and settles at tower basin as sludge. Basin blowdown is to be given regularly to remove this settled sludge. Suspended undissolved solid particles can be removed with the help of side

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stream filter. During major shutdown of plant, cooling tower basin is to be cleaned and the basin wall is to be painted. Algae growth chocks the water distributor nozzles and fills, causing non-uniform water distribution. Proper water treatment can eliminate this problem. Distribution nozzles may be chocked due to any foreign particle. These nozzles are to be cleaned regularly and the damaged nozzles are to be replaced. Damage of drift eliminators increases the drift loss, causing more water make-up. Sometimes, the distributor or fills fall down to the basin and chocks the water circulation. These materials are to be removed, if found. Wire mesh provided at the outlet of a cooling tower is to be cleaned regularly. By adopting efficient maintenance practices and condition monitoring practices, the problem of cooling tower can be minimised.

21.4  NON-DESTRUCTIVE TEST (NDT) Power plant equipments are operated at high stressful condition. These are operated at higher temperature and pressure. Along with these conditions, equipments (particularly turbine) rotate at high speed. So, mechanical stress is also more at the turbine. It is essential to evaluate the condition of components regularly. It is done with the help of some testing techniques without destroying the component known as non-destructive test (NDT) methods. With the help of NDT, minor abnormalities can be detected easily, well in before, to avoid equipment failure. Some of the NDTs which are normally carried out in power plants are discussed below:

• • • • • • •

Dye penetration (DP) test Fluorescent magnetic particle test Ultrasonic test Hardness test Ultrasonic thickness test Radiographic test In-situ metallography

NDT technique is adopted to find out the condition of boiler, turbine and steam pipeline.

21.4.1  Dye Penetration (DP) Test The DP test technique is adopted to find out any crack in the component which is not visible to naked eye. Very small crack, in metallic or non-metallic materials can be detected by this testing. Surface to be tested is cleaned thoroughly and should not be too rough. After cleaning, a coloured penetrating liquid is applied over the surface. This liquid penetrates into the crack (if any) due to capillary action. Now, the surface is wiped up to clean the excess penetrant. A base liquid is applied over the surface. The coloured penetrant which has entered inside the crack is drawn back, leaving a clear mark over the base liquid. For clear visibility, the penetrant contains dye or fluorescent material to make the impression visible under white light or suitable ultraviolet light respectively.

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This is a very easier technique to detect any crack on a clean surface. Normally, this test is carried out to check any crack on the boiler steam drum, water header, tubes, boiler drums, turbine bearing, casing, rotor shaft, blades, etc.

21.4.2  Fluorescent Magnetic Test Fluorescent magnetic test is carried out to detect any surface or subsurface discontinuities due to inclusion of non-metallic object like void or due to internal or surface crack in a ferromagnetic material. When the test piece is magnetised, magnetic flux is induced. If there is a flaw, inclusion or discontinuities on the surface, then a leakage field is formed above the surface of the discontinuities portion. Magnetic particles, dust mixed with kerosene is sprayed over the test piece. Due to leakage field, some of the magnetic particles, applied migrate to the flaw where the magnetic flux leaks and forms a flaw indication, indicating the location of discontinuity, its size, shape and extent. If the discontinuity lies deeper, it will be difficult to find by this method. This method can be used to indicate crack on any size and shape of the test piece. This method is used to find abnormalities of the boiler drums, headers, piping, turbine shaft, casing and blades, HT bolts, etc.

21.4.3  Ultrasonic Test Ultrasonic test is carried out to detect any discontinuity in the material and to detect its thickness. High frequency sound wave beyond the audible range above 200000 cycle/s is known as ultrasound wave. This ultrasound wave of short wavelength and high frequency is transmitted from a probe placed over the test piece. A receiver probe (separate probe or same probe) is used to detect the reflected wave or echo. If the material is homogeneous, then the wave travels through the test piece and reflects from the back surface. In case, there is any discontinuity exists on the wave travel path, some part of the wave is reflected from the discontinuity and some part travels through the test piece till it is reflected from the back surface. The wave reflected from the discontinuity and back surface that has travelled different path can be indicated on a CRT monitor. From the CRT monitor, size, density and location of the discontinuity can be found. Time taken for the reflection can detect the thickness of the test piece. This technique is adopted to detect any crack or flaw in the boiler drums, turbine casing, blade, HT bolts, etc. This technique is also used to measure the thickness of a boiler tube.

21.4.4  Radiographic or X-ray Test In radiographic test, electromagnetic waves such as X-ray and g-rays are used. Absorption of these rays depends upon the density and thickness of the material to be tested. A photographic film is used to create an image to detect different density materials. High density homogeneous portion, where the absorption is high, creates light areas on the film when developed. Whereas, in the area of defect (flaw, crack, or inclusion), where absorption is less, a black impression is created on the film when developed. By observing the film, the defect can be easily detected. Radiographic test is widely used to inspect any defect at welding or casting, forging, etc.

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21.4.5  In-situ Metallography Metallography is the study of physical microstructure and other metallurgical features of the metal with the help of a microscope. In situ metallography and replication is a NDT technique used for this. The surface of the component to be tested is prepared by various methods of grinding, polishing and etching. Non-destructively duplicate or replica of the surface is obtained on a thin plastic film. Impression of topography of the surface is obtained in the replica. Then, this replica is examined by high magnification through a microscope.

21.5 DIFFERENT TYPES OF MAINTENANCE PROGRAMME OF TURBINE Every power plant is expected to run continuously for years together. A turbine is operated at high temperature and pressure. It has to operate under different conditions like load change, start, stop, etc. Wear out and thermal stress reduce the efficiency and reliability of the machine. So, it is advised to maintain the turbine on continuous basis through suitable maintenance and condition monitoring practices. Turbine manufacturers advise to carry out specific maintenance other than the regular inspection, checking and monitoring activities. This specific maintenance is on running hour basis. To calculate the equivalent running hours, number of starting of turbine and operating hours are taken into account. For every start, around 30 hours is added to the operating hours of the turbine. Deterioration created by one starting is equivalent to 30 normal operating hours. So, the turbine which is frequently started requires maintenance sooner. The equivalent running hour is calculated as follows: where Req = equivalent running hours Rn = normal operating hours N = number of starts

Req = Rn + N  30

Following two types of overhaul are advised by the turbine manufacturers:

• Minor overhaul • Major overhaul

Minor Overhaul Mostly, at every 20000 to 25000 equivalent running hours, this overhaul is advised. In this overhaul, casing of the turbine is not opened. Following activities are carried out during minor overhaul:

• • • •

Bearing cover is opened. Bearing condition is inspected and clearance is measured. Condition of coupling and alignment of turbine are checked. Visual inspection of the gears of a gearbox and barring device is done. Servicing of control system, adjustment of governing, protection and safety system is done.

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• Radial run out of rotor is checked. • Axial play of rotor is checked by removing the thrust bearing. • Any abnormality noticed during normal operation is attained.

Major Overhaul Due to continuous operation of turbine, wear out of turbine internals and deposit on blades take place. So, it is required to open the turbine casing and inspect the turbine internals during major overhaul. Normally, this type of overhaul is advised after 75000 to 100000 equivalent operating hours. Following activities are normally carried out during major overhaul:

• • • • • • •

Turbine casing is opened. Internal parts of turbine are inspected. Deposit on blades is removed by sand blasting. Damaged seals are replaced. All the activities listed in minor overhaul are carried out. Governing valve seat lapping is done. Any damaged component is replaced. Non-destructive (ND) test is carried out to evaluate condition of bearing, rotor shaft, blades, etc. • Servicing of ESV is carried out. • Rotor balancing is checked. • Inspection of steam pipeline is carried out.

Apart from the above overhaul activities, any abnormality found in between is attended to keep the turbine healthy. Daily checking of bearing vibration, temperature, axial displacement, interstage pressure, gland steam requirement, etc. can provide information about the turbine condition. Proper start-up procedure minimises unusual thermal stress on turbine.

21.6  STATUTORY RULES AND REGULATIONS APPLICABLE TO THE BOILER The boiler is monitored as per Indian Boiler Act–1923 and Indian Boiler Regulations–1950. Every boiler is required to be registered with the director of boilers of the concerned state and assigned a registration number. The registration authorises to operate the boiler and it is to be renewed every year. Some important sections of Indian Boiler Act–1923 regarding registration and renewal of certificate are discussed here. For details, Indian Boiler Act–1923 and Indian Boiler Regulations–1950 are to be referred. Section 7–Registration Each boiler in use is to be registered with the director of boilers of the state. A registration number is issued to the boiler. The director issues a certificate to the owner, authorising the use of boiler for a period of twelve months. Registration number of the boiler is to be permanently marked on the boiler in prescribed manner.

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Section 8–Renewal of Certificate It is required to renew the certificate on expiry of the period for which it was granted or any accident occurs or any alteration or repair is done in the boiler. Before expiring of the certificate, the boiler inspector is requested for inspection along with the prescribed inspection fees (depends upon the heating surface of boiler). Boiler inspector fixes a date within 30 days from the receipt of the request and intimates the owner at least 10 days before. He inspects external/internal sides of the boiler. Hydro test is carried out in his presence. Based on the report of boiler inspector, renewal certificate is issued by the director of boiler for another one year in Form VI. Section 9–Provisional Order After successful inspection, the boiler inspector may issue a provisional order (PO) in Form V, permitting the boiler to be used. This provisional order is valid for six months or till the receipt of renewal certificate from the director of boilers. Section 14–Duty of Owner at Examination All the reasonable facilities for examination and reasonable information are to be provided to boiler inspector as per his requirement. A boiler is to be properly prepared in empty condition and thoroughly cleaned. All doors of manholes, hand holes, sight holes are to be kept open. For the inspection of boiler, the owner is bound

• To provide the inspector all reasonable facilityies for the inspection as may reasonably required by him • To properly prepare the boiler and make the boiler ready for inspection in the prescribed manner • To provide drawings, specifications, certificates and other particulars as may be prescribed

Section 12–Alteration and Renewals to Boiler Without written permission of director, no structural alteration, addition or renewal is permitted in any registered boiler. Section 23–Penalties for Illegal Use of Boiler The owner may be punished in the form of fine, in case, he uses the boiler either without certificate or at a higher pressure than that is allowed. Section 24–Other Penalties The owner may be punished in the form of fine in case of unauthorised structural alternation, addition or renewal, tamper safety valve or fails to report an accident.

21.6.1  Procedure for Annual Inspection of Boiler As per Section 8 of Boiler Act–1923, the certificate for use of boiler shall cease to be in force when the period for which it is granted is expired. Normally, the certificate is valid for one

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year. The boiler is to be inspected every year by the IBR inspecting authority for renewal of the certificate. Inspection of boiler is a statutory requirement as per Indian Boiler Act–1923. Amendment is made in Indian Boiler Regulation to permit the boiler, exclusively used for power generation to run for another twelve months. As per regulation 376 (ff) of Indian Boiler (amendment) regulation 2007, a boiler specifically used for power generation may be allowed to run for another twelve months with certain conditions and satisfactory verification of records. For annual renewal, it is required to follow some procedure. Every boiler engineer should be familiar with this procedure, as every year he has to take care of inspection for the renewal of certificate. Following steps are followed for the renewal of certificate: Intimation and Deposit of Inspection Fees Before expire of certificate, intimation regarding expected shutdown programme of the boiler is given to the concerned IBR authority along with the required inspection fees. The amount of inspection fees is decided based on the heating surface of the boiler. Inspecting authority fixes up a suitable date within 30 days from the receipt of the letter, giving at least 10 days notice of the date so fixed to the owner. Preparation for Inspection As per Regulation 376 of Indian Boiler Regulations–1950, a boiler is to be prepared for inspection by the inspecting authority. After shutdown of boiler, the boiler is made empty and cleaned thoroughly. Tube’s outside surface, steam drum, mud drum, etc. are cleaned. Outside surface of the tube are cleaned through wire brush or water jet. Furnace and water wall are cleaned thoroughly. All the manholes, hand holes are opened. All the boiler mountings are removed. Any connection of steam and hot water to the other steaming boiler is disconnected. Necessary arrangement is made to facilitate the inspector to inspect the boiler thoroughly for any abnormality like crack, bulge, blister, corrosion, erosion, etc. on the pressure part of the boiler. 24 V hand lamp is provided inside the furnace for easy inspection. Scaffolding is made to get an access to the critical areas. Open Inspection of Boiler On the schedule date, the boiler inspecting authority carries out open inspection of the boiler. The inspector may require boiler general arrangement (GA) and other drawings for his reference. All these drawings are to be made available. Owner of the boiler has to provide facility, etc. as per Section 14 of Indian Boiler Act–1923. Open inspection of boiler is carried out by the inspecting authority, as per Regulation 390 of Indian Boiler Regulations–1950. He mainly checks for any deformation of the boiler which may lead to failure of the boiler pressure parts. He checks internal and external condition of the pressure parts for any abnormality like crack, bulge, blister, corrosion, erosion, etc. He may instruct to cut some of the header or tube to check the internal condition of tube or header. He verifies the safety valve, blowdown valve, etc.



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Hydraulic Test After open inspection of the boiler, the manholes, hand holes, etc. are closed. Safety valve flange is made blind. Water is filled in the boiler. There should not be any air trapped inside the boiler pressure parts. It is advisable to raise the pressure upto the working pressure of the boiler, as per the normal procedure (described earlier) before the visit of inspecting authority for preliminary test to find out the tightness of joints. Hydraulic test is carried out as per regulation 379 of Indian Boiler Regulations–1950. In the presence of inspecting authority, the pressure is raised normally upto 125% to 150% of the working pressure of a boiler. The pressure gauge of inspecting authority is fitted and its reading is referred for hydraulic test. The boiler should withstand such pressure satisfactorily without leakage or deflection or distortion for at least 10 minutes. The details of hydraulic procedure are discussed in Section 13.9. Provisional Order After successful hydraulic test of the boiler, the inspecting authority issues a provisional order in Form V, authorising the use of boiler. The validity of this provisional order expires after six months or after issue of the final certificate. Final Certificate As the provisional order is valid for six months, so before that, the final certificate is expected in Form VI from appropriate IBR authority based on the inspection report of the inspecting officer. Validity date, maximum pressure at which the boiler shall work and safety valve setting pressure, etc. are mentioned in this certificate. During annual inspection period, maintenance of other auxiliary equipments like fans, fuel handling system, ash handling system, ESP, etc. can be carried out. This period is to be utilised effectively to increase the availability of the above systems. As far as possible, this opportunity is to be utilised fully to run the boiler trouble-free for next one year.

21.6.2  Repairing Procedure of Boiler Each registered boiler in use is having a memorandum of inspection book maintained by the concerned IBR authority. In this book, date of inspection, inspection note, hydraulic test details, pressure parts replaced, etc. are noted. Each repair which is carried out on the pressure parts and the parts which affect the satisfactory performance of boiler is noted there. For any such repair, prior approval of the concerned IBR authority is taken. Without permission of the concerned authority, no repair or alternation can be carried out in a boiler. But during operation, some deteriorations may take place which require repairing like fusion welding in pressure parts, pipelines, headers, replacement of damaged pressure parts, etc. For the repair of boiler, following procedure is mostly followed: Intimation and Inspection Fees Deposition Like annual inspection, intimation for repair is given to the inspecting authority. Required inspection fee is deposited for inspection. On the fixed date, inspector inspect the boiler to

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assess the repair job to be carried out. Sometimes, it may be required to make an access to repair the faulty portion. For this, some healthy tubes may required to be removed or cut. The inspector prepares a detailed list of job to be carried out. Repair Order The repair job is entrusted to an approved boiler repairer who can satisfy the concerned IBR authority regarding the quality of welding and other repair done by him. For this, a registered boiler repairer is hired. A request letter is submitted to the inspecting authority to issue a repair order on the name of the repairer selected by the owner. After getting the repair order, repairing can be started. Material Inspection Materials which are to be used for repairing like boiler tubes, fittings, etc. are required to be inspected by the inspecting authority. For this, material test certificates and drawings are submitted. The inspecting authority inspects all these materials for acceptance. The drawing is approved by the inspector. Then only, these materials can be used for repairing. Fit-up Inspection During repairing work, the inspecting authority may like to visit the site to inspect the quality of job in progress. Mostly, before the final welding of tubes or pipes, the inspector inspects the fit-up. Once the fit-up inspection is done, he may permit for final welding. He may require to test the skill of the welder. IBR certified welder is utilised by the repairer to carry out the repairing job. Non-destructive (ND) Test To check the quality of welding, X-ray test is conducted. X-ray test report of welding is submitted to the inspecting authority. Hydro Test Once the repairing job is completed, hydro test of the pressure parts is conducted in the presence of inspecting authority, as per the procedure discussed earlier. After successful hydro test of the boiler, inspecting authority permits to put the boiler into service.

21.7  RLA STUDY Boiler and turbine work in high temperature and pressure condition continuously throughout their service life. Due to aging and stress, continuous degradation of the material takes place. Failure of any critical component during operation may lead to huge loss and unsafe condition. To study the exact condition of the components and their remaining life, remaining life assessment (RLA) study is carried out. This study is conducted to examine aging effect and healthiness of the boiler tube, header, drum, pipeline, turbine rotor, casing, blade, bearing etc. Any weak component close to the end of its service life can be replaced before it fails in order to extend the useful life of the entire plant and ensure safe operation.

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As per IBR regulation 391A, the boiler is to be tested non-destructively after operation of 1,00.000 hours or when it completes a life of twenty five years for the assessment of the remnant life. Following ND tests are performed for RLA study:

• • • • • • • •

Visual and dimensional inspection Ultrasonic test Magnetic particle test Dye penetration (DP) test Ultrasonic thickness test Hardness test Replication for metallography Videoscopic examination

21.8  WELDING Welding is an important technique in power plant maintenance. It is a process that joins metal. Welding is done by melting the workpiece and adding some filler material to form a molten pool. When this pool cools, it becomes a strong joint. In past days, riveting process was adopted in the absence of welding. Nowadays, welding makes maintenance simpler and costeffective. So, welding technique is widely used in the power plants. Due to advanced welding technique, boiler design has become simpler. Repairing of damaged parts like boiler tubes, furnace, pipelines, etc. is done easily by welding. Nowadays, various types of welding techniques are used. Some of the commonly used welding processes are discussed here. Arc Welding In arc welding, concentrated heat of an electric arc is utilised to melt the workpiece into which some molten metal of consumable electrode is added further. To create an arc, direct current (DC) or alternating current (AC) is used depending upon the material to be welded and electrode used. Gas metal arc welding (GMAW) or metal inert gas (MIG) welding, gas tungsten arc welding (GTAW) or tungsten inert gas welding (TIG), shield metal arc welding (SMAW) are the examples of arc welding. Resistance Welding In this process, heat is produced by passing high current across the joints. Due to resistance caused by the contact between two surfaces and high current passed through it, high heat is produced and small pool of molten metal is formed. Spot welding and seam welding are the two types of resistance welding. Energy Beam Welding This is a new process of welding. High energy density beam is utilised in this process. In this welding, the size of weld area is very small. Laser beam welding and electron beam welding are the examples of this type of welding.

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We will discuss about some of the widely used arc welding process which are mostly used for the maintenance purpose at power plants.

21.8.1  Shield Metal Arc Welding (SMAW) Sometime, shield metal arc welding is called as manual metal arc (MMA) or stick welding. This is the most common type of welding that we come across. In this process, consumable electrode is used. Either direct current (DC) or alternating current (AC) is used to produce arc between a flux coated electrode and the workpiece. When high current flows and arc is produced, both workpiece and electrode melt. When the flux coating of electrode melts, it produces a gas that serves as shielding and protects the hot welding area from oxidation. Also, a layer of slag is covered over molten metal pool, protecting it from oxidation. This slag is removed by chipping after cooling. As the electrode is consumed continuously during welding process, so the welding is required to be stopped frequently to insert a new electrode into the holder. Power Source of SMAW To create arc during welding, either alternating current or direct current source of power is used depending upon the welding material and electrode used. This power source is capable of supplying the high welding current at lower voltage. For AC source, welding transformer is used. For DC source, welding generator or rectifier sets are used. Electrode is connected to the power source through a holder and current carrying cable. The electrode may be connected to +ve or –ve terminal of the power source depending upon the electrode specification. Workpiece is connected to earth or +ve terminal of the source accordingly. Handle of the holder is insulated so that the welder can hold it without any risk of electric shock. Welding cable is made of flexible copper or aluminum conductors to carry the required welding current without heating. Electrode in SMAW As discussed earlier, the electrode used in SMAW is consumed during welding process and it is covered with flux to produce shielding gas and slag to protect the welding area from oxidation. These electrodes are available in different core wire diameters and lengths. Diameter of the electrode decides the welding current and hence, the thickness of the workpiece to be welded. Depending upon the base material, the type of electrode is chosen. These electrodes are available as per American Welding society (AWS) specification. For welding of boiler tubes and pipes, mostly A5.1 electrodes are used. These electrodes are designated as EXXXX (E6013, E7018, E8018, etc.). Most of the time, engineers are confused about these numbers. It is explained here briefly. The maintenance engineer should know the meaning of each digit of electrode for proper selection of the welding electrode. EXXXX:  Here, E designates arc welding electrode. E60XX:  The first two digits designate tensile strength of the electrode in thousand pounds per square inch (kpsi). In this case, it is 60 kpsi.

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Electrodes with various tensile strength like E70XX, E80XX and E90XX are available. Mostly for carbon steel pipes and tubes, E60XX and E70XX electrodes are used. For alloy steel pipes and tubes, E80XX and E90XX electrodes are used. EXX1X:  The third digit of the electrode designates the position of welding that can be done with the electrode. In case of 1, it is suitable for all position welding and for 2, it is suitable for flat position and horizontal fillets only. EXX13:  The last two digits designate the suitable power source and type of flux covering over the electrode. These specifications are mentioned in Table 21.1. Table 21.1  Power Source and Type of Flux Covering Over the Electrode Electrode EXX10 EXX11 EXX12 EXX13 EXX14 EXX15 EXX16 EXX18 EXX20 EXX24 EXX27 EXX28

Current Source DC +ve only AC or DC +ve AC or DC –ve AC or DC ±ve AC or DC ±ve DC +ve only AC or DC +ve AC or DC +ve AC or DC ±ve AC or DC ±ve AC or DC ±ve AC or DC +ve

Flux Covering Organic Organic Rutile Rutile Rutile, iron powder (approx 30%) Low hydrogen Low hydrogen Low hydrogen, iron powder (approx 25%) High iron oxide Rutile, iron powder (approx 50%) Mineral, iron powder (approx 50%) Low hydrogen, iron powder (approx 50%)

In power plants, most of the time, low hydrogen flux coating type electrode is used. Low hydrogen electrodes are used to avoid hydrogen cracking. EXX15, EXX16 and EXX18 electrodes are called low hydrogen electrodes. Moisture contents in this type of electrode are required to be maintained less than 0.6%. These electrodes are stored carefully and heated in an oven prior to use. EXXXX-A1:  This suffix is added for low alloy steel electrode to know the approximate amount of alloy in the weld deposition. Some of the suffixes are as follows: A 1 0.5% Mo B1 0 .5% Cr, 0.5% Mo B2 1.25% Cr, 0.5% Mo B3 2.25% Cr, 1% Mo B4 2% Cr, 0.5% Mo B5 0 .5% Cr, 1% Mo C1 2.5% Ni C2 3.25% Ni C3 1% Ni, 0.35% Mo, 0.15% Cr SMAW electrodes are available in various sizes. These sizes are selected depending upon the workpiece thickness and welding current required. The normally available sizes are given below:

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Electrode Size for Various Thickness Workpiece 2.5 mm 3.15 mm 4 mm 6 mm

upto 4mm 4 mm to 10 mm more than 10 mm more than 22 mm

Process of SMAW This is the simplest welding process where the electrode is continuously consumed during welding process. In this welding, one terminal of the power source is connected to the workpiece and another to the electrode through a cable and holder (Figure 21.4). Initially electrode is touched to the workpiece so that an arc is initiated. Then, the electrode is withdrawn to a certain distance to maintain the arc. Heavy current flows through the arc. So, sufficient heat is produced to melt the welding area of the workpiece as well as electrode tip along with the flux coating.

Figure 21.4  SMAW welding.

During melting of flux, shielding gas is produced which shields the welding from atmospheric air contact. The molten metal of workpiece and electrode form a pool. Slag which is formed due to melting of flux coating covers this molten pool, restricting the hot surface from contact with the surrounding atmosphere and hence, restricts oxidation. This slag layer is required to be removed after each pass or layer of welding. The main disadvantage of this process is that welding is to be interrupted for inserting a new electrode into the holder.

21.8.2  Gas Tungsten Arc Welding (GTAW) or Tungsten Inert Gas (TIG) Welding TIG welding is a non-consumable electrode type welding. Here, the electrode used for maintaining arc is made of tungsten. A separate filler rod is used for welding. Inert gas like argon is supplied externally into the welding area for shielding. So, it is called argon welding also. DC source is used for this welding. By changing the diameter of the tungsten electrode, (hence the heat input), workpiece having different thicknesses can be welded. The welding process is very slow and requires high skill. High quality welding is achieved through this process. Root pass welding of pipes and tubes is done by this welding process.

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Process of TIG Welding The welding holder used in this welding process is called torch. Non-consumable tungsten electrodes having various diameters can be fitted into this torch. Argon gas is supplied through the torch to the welding area. Pressure of this gas can be adjusted through a gas regulator. The electrode is connected to the power source through a welding cable. Another terminal is connected to the workpiece, as shown in Figure 21.5.

Figure 21.5  TIG welding.

Arc is initiated by touching the electrode to the workpiece. When arc is maintained, then a separate filler rod is inserted into the arc area. Due to high heat of the arc, this filler rod and welding area of the workpiece melt to form molten pool. Argon gas shields this pool from the surrounding atmosphere. After cooling of the pool, good quality welding is obtained. As no slag is produced, so chipping is not required after welding. Current for the welding is adjusted by a regulator. Filler Rod of TIG Welding Like SMAW electrode, filler rod for TIG welding is available in various types. Filler rod melts during welding process and this molten metal mixes with the parent molten metal pool. So, the filler rod is consumed continuously. Filler rod is designated as SXX. Suffix S indicates the filler rod is solid. The second and third digit indicate the strength of the material in kilo pound per square inch (kpsi). For S80 filler rod, 80 indicates its strength as 80 kpsi. Mostly, S70, S80 and S90 filler rods are used for TIG welding of boiler tubes and pipes.

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21.8.3  Preheating Preheating is required to preheat thick workpiece to certain temperature uniformly throughout the thickness for better quality welding and to prevent or remove undesirable materials from the weld. Temperature of the base metal, just surrounding the point of welding is raised either by gas burner, oxy gas flame, electric heater or induction heater. In multipass welding of some thicker jobs also, preheating is required between the interpass welding. Normally, preheating is required for welding job of higher wall thickness. Preheating temperature is decided by the following factors:

• Composition of base metal • Thickness of base metal • Feasibility of post-weld heat treatment

During preheating, it is to be ensured that the total thickness of workpiece is heated uniformly. Temperature of the base metal is checked with help of thermal chalk or recorded in a recorder by thermocouple. Thermal chalks are available for various temperatures. The said chalk melts when touched to the workpiece and confirms that the workpiece has attended the required temperature. Reason of Preheating

• By heating the base metal, any moisture present in the area dries out, thereby helping in avoiding porosity, hydrogen embrittlement or hydrogen cracking. • The welding process uses high temperature during welding. There is a high temperature difference between the cold base metal and the welding area, causing differential thermal expansion and high stress around the welding area. Preheating minimises this. • Preheating slows down the cooling rate after welding in the weld and base metal, producing more ductile metallurgical structure.

21.8.4  Post-weld Heat Treatment (PWHT) Like preheating, post-weld heat treatment or stress reliving of weld area is carried out after welding of a thicker section base metal. The reasons of PWHT are given below:

• It is used for stress reliving (SR) of the welding joint area. This process removes the internal stress that may develop during welding. • It helps to obtain suitable metallurgical structure.

Steps of PWHT Control temperature raise:  Temperature of the base metal is raised at certain rate to attain a desirable temperature. This is done by controlling the current through an electric heater or induction heater. PWHT temperature is selected as per the chemical composition of the base metal. Sock or hold:  Temperature of the base metal is kept constant at PWHT temperature for certain period. Socking time may be one hour or two hours depending upon the thickness of material.



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Control cooling:  After socking, the base metal is cooled slowly as per the desired rate. All the above processes are recorded in a recorder. Thermocouple is used to measure the temperature and record it.

21.8.5  Defects in Welding Welding is done to join two metal pieces together and the welding strength is required to be as much as that of the parent material. But during welding process, some defects are noticed which weaken the joint. A good quality weld is required to be free from all defects. Following defects are usually noticed in a welding: Cracks Due to unequal thermal expansion and contraction of metal during welding, crack develops. Lack of Fusion If sufficient heat is not available during welding process, fusion of parent material could not take place. Porosity Due to inclusion of slag, foreign material or gases, the joint is not homogeneous. This phenomenon is called porosity. Undercut During welding process, root of the welding is fused more. This happens if the heat input is more. The parent material melts more resulting into undercut.

21.8.6  Testing of Welding Joints Welding joint is required to be inspected thoroughly to avoid any defect. Strength of the joint weakens due to defect in it. This may fail at any moment before the required stress level is reached. Following testing and inspection methods are adopted to find out any defect in the welding joints: Visual Inspection The welding joint is inspected visually to find out any crack, undercut, lack of fusion or porosity. Before inspection, welding slag over the welding is removed. Non-destructive (ND) Test As discussed earlier, ND test is carried out to find out any defect in the welding. Radiography, dyepenetration test, magnetic particle test, etc. are carried out. In power plants, mostly radiographic (X-ray) test is carried out to check any defect in the welding in tubes, pipes or headers.

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21.9  BEARING Bearing is a very common item used in a rotating equipment. Bearing is used to reduce rotational friction and support radial and axial loads. Different types of bearings are used. Bearings are identified by their nomenclature given as numbers and alphabets. Some basic information on bearing types and nomenclature is given here. Bearing nomenclature consists of following parts:

• • • •

Bearing type code Series code Bore Suffix

Bearing Type Code The first number or alphabet indicates bearing type. Mostly, following practice is widely used to designate any bearing:

1 2 3 4 5 6 7 8 32 N NU R

Self-aligning ball bearing Spherical roller bearing Double-row angular contact ball bearing Double-row ball bearing Thrust ball bearing Single-row deep groove ball bearing Single-row angular contact bearing Felt seal Tapered roller bearing Cylindrical roller bearing Cylindrical roller bearing, separable inner ring, no thrust load capacity Inch (non-metric) bearing

Series Code The second number of the bearing indicates the series of the bearing. It indicates the relationship between bore size, outer diameter and thickness of the bearing or robustness of the bearing, as mentioned below:

8 9 0 1 2 3 4

Extra thin section Very thin section Extra light Extra light thrust Light Medium Heavy

Spherical roller bearing (type code 2) and tapper roller bearing (type code 32) have five digits in the bearing number. In this case, first digit is bearing type code as usual. The second and third digit is known as bearing width series and bearing OD series respectively.

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Bore The third and fourth digits indicate the bore size in millimetres. Bore size is five times the third and fourth digits together (except from 00 to 03).



00 01 02 03 04 05 06

10 12 15 17 20 25 30

mm mm mm mm mm mm mm

For bore size less than 10 mm, the bearing number has three digits only. In this case, the last digit indicates the bore size in millimetres. Suffix Following are the suffix used to describe a bearing:

Z ZZ RS1 2RS1 FY FG K K30 W33

One side shield Double side shield One seal (R indicates rubber) Two seals Machined brass retainer Polyamide (nylon) retainer 1:12 tapered bore 1:30 tapered bore Outer ring with lubrication groove and three lubricating holes

Internal Radial clearance

C1 C2 No code C3 C4 C5

Less than C2 Less than normal Standard Greater than normal Greater than C3 Greater than C4

EXAMPLE 21.1  Write the names of following bearings: (a) 6205 ZZC3 (b) 22308 C3 (c) 627 ZZ Solution (a) 6 2 05

(Type code 6) deep grove ball bearing (Series code 2) light (Bore 05  5) 25 mm

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(b) (c)

ZZ C3 2 2 3 08 C3 6 2 7 ZZ

Both side shield Clearance C3 (Type code 2) spherical roller bearing Width series code OD series code (Bore 08  5) 40 mm Clearance C3 (Type code 6) deep groove ball bearing (Series code 2) light Bore 7 mm Both side shield

21.10  COUPLING Coupling is used to transfer motion from one drive shaft to another. There are various types of coupling available. These are generally categorised into following types:

• Rigid coupling • Flexible coupling

Rigid Coupling Rigid couplings are mainly used in areas where two shafts are coaxial to each other. There is no misalignment. There are many types of rigid couplings. Following types are commonly used: Rigid sleeve or muff couplings:  This is the simplest type of coupling. In this type of coupling, two shafts are inserted into a sleeve or pipe matching with the shaft diameter. The sleeve is locked by screw and power is transmitted through the key way. Flanged coupling:  Both the shafts have flanges at their ends. These flanges are matched are tightened through bolt. Flexible Coupling Flexible couplings are used to transmit torque from one shaft to another when two shafts are slightly misaligned. These types of coupling allow radial, axial or angular movement of two shafts. Various types of flexible coupling are used to allow varying degrees of misalignment. Following types of flexible couplings are mostly used. Jaw coupling or spider coupling or lovejoy coupling:  Spider coupling has two metallic hubs and an element called spider, as shown in Figure 21.6. Both hubs of couplings have three lugs. When the coupling is fitted together, the lugs of one hub fit inside the spaces between the lugs on the other hub. A rubber spider with six legs fits between the spaces within the lugs. The torque is transmitted through the rubber spider. This coupling is only used for low power drives.

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Figure 21.6  Jaw coupling.

Pin bush coupling:  Pin bush coupling is a modified flanged coupling. In flanged coupling, two flanges are fitted to both the shaft ends and bolted together. But in case of pin bush coupling, bolts are replaced by pins with rubber bushes. This modification allows certain flexibility. Figure 21.7 shows pin bush coupling.

Figure 21.7  Pin bush coupling.

Gear coupling:  Gear couplings use gear teeth to transmit torque from one shaft to another. The coupling accommodates misalignment through the clearance between the inner and outer gear teeth. Figure 21.8 shows gear coupling.

Figure 21.8  Gear coupling.

Grid coupling or bibby coupling:  Grid couplings use two slotted hubs with a steel grid running between them to transmit torque. The coupling flexes by allowing the grid to slide along the slots in the hubs. Maintenance is easier in this coupling. Figure 21.9 shows grid coupling. Meta flex coupling or flexible disc coupling:  Coupling halves are connected via multiple flexible stainless steel discs. The coupling has high speed high torque capability. There are two types of disc coupling. Single disc type coupling has two hubs and a single, flat, stainless steel

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Figure 21.9  Grid coupling.

disc spring in between them. Double disc type coupling has also two hubs and an additional centere spacer sandwiching the two disc springs. This type of coupling is used for turbine coupling. Figure 21.10 shows meta flex coupling.

Figure 21.10  Meta flex coupling.

Tyre coupling:  This is a flexible coupling. A gap is maintained between the shaft ends and a flexing member known as tyre is used to connect them. This coupling avoids metal contact and smoothens vibration. Tyres are made of natural rubber and fire resistance and antistatic (FRAS) elements. Figure 21.11 shows tyre coupling.

Figure 21.11  Tyre coupling.

Fluid coupling:  Fluid coupling is not a type of flexible coupling but it is used in association with the flexible couplings. Fluid coupling allows motors to start up at low load. The fluid coupling uses two wheels and an outer shell to transmit torque. Figure 21.12 shows fluid coupling.

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Figure 21.12  Fluid coupling.

21.11  SHAFT ALIGNMENT Every mechanical rotating machine has a driver and driven arrangement. The driver equipment like pump, fan, generator, compressor, etc. are coupled and driven by motor or turbine. It is essential that the shafts of driven and driver equipment are aligned properly. Shaft alignment is the positioning of the rotational centres of two machines such that they are colinear when the machines are under normal operating condition. Misalignment is the main root cause of most of the failures of any rotating equipment. Properly aligned machine can minimise the vibration, increase the bearing life, reduce the energy consumption and component wear, increase the plant availability and improve the product quality. alignment is done during cold condition of the machine. It may disturb during running due to thermal effect, piping stress, machine torque, foundation movement, etc. Alignment is a vast subject. Only some basic discussion is made here to provide the reader some basic idea. Following are the two types of misalignment:

• Radial or offset or parallel misalignment • Axial or angular or gap misalignment

Combinations of both of these are also found. In radial or parallel or offset misalignment, the centre lines of both shafts run parallel to each other but they are offset [Figure 21.13(a)]. In axial misalignment, axial spacing or coupling gap of both shafts is not uniform or the coupling faces are at an angle to each other [Figure 21.13(b)]. This has no relation to the axial play or axial shift of the shafts. For correction of axial alignment or coupling gap, actually angularity is measured. So, it is called angular misalignment also.

Figure 21.13  (a) Radial misalignment and (b) Axial misalignment.

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These two types of misalignment may occur in two planes—horizontal plane (side to side) and vertical plane (up and down). So, there are actually four misalignments that may happen. These are as follows:

• • • •

Axial vertical misalignment Radial vertical misalignment Axial horizontal misalignment Radial horizontal misalignment

Axial vertical misalignment occurs when the drive or motor shaft is at an angle with the driven or equipment shaft (Figure 2.14). Coupling face gap at top and bottom are not same.

Figure 21.14  Axial vertical misalignment.

Radial vertical misalignment occurs when the drive or motor shaft is moved vertically away from the driven or equipment shaft but both shafts are still parallel and are in the same vertical plane (Figure 21.15).

Figure 21.15  Radial vertical misalignment.

Axial horizontal misalignment occurs when the drive or motor shaft is at an angle with the driven or equipment shaft at the horizontal plane (Figure 21.16). Coupling face gap at left and right are not same.

Figure 21.16  Axial horizontal misalignment.

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Radial horizontal misalignment results when the drive or motor shaft is moved horizontally away from the driven or equipment shaft at horizontal plane (Figure 21.17).

Figure 21.17  Radial horizontal misalignment.

Corrections of all the above misalignments are required for the smooth operation of equipments. During alignment, the drive equipment (motor or turbine) is aligned with the driven equipment (fan, blower, pump, generator, gearbox, etc.). The driven equipment is kept stationary and the driving equipment is moved for correction. It is not possible to align the machine upto 0.00. Different types of coupling have different tolerance level. Alignment should be within that tolerance level.

For correction of alignment following, two methods are adopted, i.e., straightedge and filler gauge method and dial gauge method. Details of these methods are discussed here.

21.11.1  Straightedge and Filler Gauge Method This is a very simple method of alignment. This method is suitable for small and non critical equipment. It may be used for primary correction before precision alignment. Figure 21.18 shows straightedge and filler gauge method. Following steps are followed in this method:

Figure 21.18  Straightedge and filler gauge method.

Axial Vertical Correction Ensure mounting bolts are properly tightened before taking measurement. Measure flange face gap at 12 o’clock position with the help of a filler gauge. Do not rotate the shafts. Now, measure the flange face gap at 6 o’clock position. If there is any difference in the gap, then vertical axial misalignment exists. If the gap is more at 6 o’clock position, then shim is to be placed under front footings of the motor or shim is to be removed from the rear footing of

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motor. If the gap is more at 12 o’clock position, then shim is to be placed under rear footings of the motor or shim is to be removed from the front footing of motor. Radial Vertical Correction Place a straight edge over the rim of the coupling. Measure the difference of height of flange rims at 12 o’clock position by putting the filler gauge in between lower rim and straightedge. The filler gauge reading indicates the thickness of shim that is to be added or removed. If the motor is at lower level, adjust the motor height by putting shim at all four footings of the motor. If the motor is at higher level, adjust the motor height by removing shim from all four footings of the motor. Axial Horizontal Correction Measure the flange face gap at 3 o’clock position with the help of a filler gauge. Do not rotate the shafts. Measure the flange face gap at 9 o’clock position. If there is any difference in these two readings, then horizontal axial misalignment exists. The amount of misalignment is the difference of the filler gauge readings. For the correction of misalignment, motor is to be rotated at its centre axis with the help of jacking screws provided at the motor footing. The motor is to be rotated by adjusting the jacking screws that are diagonal to each other. The shim thickness is not to be disturbed. Radial Horizontal Correction Place a straightedge over the rim of the coupling. Measure the gap between flange rim and straightedge at 3 o’clock position by putting the filler gauge in between the lower rim and straightedge. If there is a gap, then radial offset exists. For the correction of this misalignment, motor is to be moved totally across its centre line with the help of jacking screws. The motor is to be moved by adjusting the jacking screws at one side. The shim thickness is not to be disturbed.

21.11.2  Dial Gauge Method Mostly, for critical equipments and for precision alignment, dial gauge is used. Dial gauge is fixed with the help of a suitable fixture. The base or holder of the fixture is attached on the shaft of the driven equipment and the dial gauge plunger is kept over rim and face of the coupling of the driven equipment which is required to be moved for alignment. The arrangement is shown in Figure 21.19.

Figure 21.19  Dial gauge method.

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Following steps are followed while doing alignment with a dial gauge:

• Adjust the dial gauge in such a way so that the plunger of the dial gauge is slightly pressed against the coupling and plunger tip always remain in touch with the coupling during full rotation and reading can be obtained at any position. • Dial gauge plunger placed on the rim of the coupling gives radial alignment reading and that placed on the face of the coupling gives axial alignment reading. • Set both the dial gauge reading zero at 12 o’clock position. • Mark a witness mark in the coupling face. • Rotate both the shafts by 360°. If the fixing arrangement is perfect, then both the dial indicators should come back to the original reading, i.e., zero. • Rotate both the shafts simultaneously in 90° increments at clockwise direction seen from the stationary machine side (fan, gearbox, pump, etc). Match the witness mark at each position. Note down the readings of dial indicators with their signs (+ or –). • Take readings at 3, 6 and 9 o’clock positions. 12 o’clock and 6 o’clock readings are known as vertical readings and readings of 3 o’clock and 9 o’clock are known as horizontal readings. Now, note down the readings obtained as per the diagram shown in Figure 21.20.

Figure 21.20  (a) Radial or rim or offset readings and (b) Axial or face or angularity readings.

Interpreting the Readings

• First verify the accuracy of the readings. The sum of 12 and 6 o’clock (vertical) readings should be equal to the sum of 3 and 9 o’clock (horizontal) readings. This is true for both axial and radial readings. For example,

Radial reading: Axial reading:

12 3 12 3

o’clock o’clock o’clock o’clock

+ 6 + 9 + 6 + 9

o’clock o’clock o’clock o’clock

reading reading reading reading

= 0 = –12 = 0 = 20

+ 10 = 10 + 22 = 10 + 8 = 8 – 12 = 8

• The difference of two vertical and two horizontal radial readings (known as total indication run out or TIR) is to be divided by two to represent the actual differences in the two shaft centre lines at vertical and horizontal. Signs of the indicator readings are to be considered to prevent errors in the calculations. For example,

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Radial reading: Axial reading:

Vertical difference = 10 – 0 =10 10 Vertical misalignment = = 5 2 Horizontal difference = 22 – (–12) = 34 34 Vertical misalignment = = 17 2 Vertical difference = 8 – 0 = 8 8 Vertical misalignment = = 4 2 Horizontal difference = –12 – 20 = –32

32 = - 16 2 For the correction of alignment, a procedure (as discussed in straightedge and filler gauge method) is adopted. By knowing the coupling diameter (indicator circle), front footing distance and rear footing distance, shim thickness and driving equipment shifting can be calculated. But this is not discussed here, as the aim of this section is to give only a basic idea about alignment.

Vertical misalignment = -

Axial Vertical Correction The misalignment is calculated as follows: VA =

( F6 - F12 ) 2

where VA = vertical axial misalignment F6 = dial gauge reading at 6 o’clock position (face or axial) F12 = dial gauge reading at 12 o’clock position (face or axial) For the correction of misalignment, shim thickness is adjusted from the motor footing. If the reading is positive, shim is to be placed under rear footings of the motor. In case of negative reading, shim is to be placed under front footings of the motor. The shim thickness can be calculated as follows: S=

VA DF + ¥A 2 2

where S = shim thickness VA = vertical angular gap (dial gauge reading) DF = diameter of coupling (indicator circle) A = distance between front and rear mountings

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Radial Vertical Correction The vertical radial misalignment is calculated as follows: VR =

( R6 - R12 ) 2

where VR = vertical radial misalignment R6 = dial gauge reading at 6 o’clock position (rim or radial) R12 = dial gauge reading at 12 o’clock position (rim or radial) If the reading is positive, shim is to be placed under all four footings (front and rear) of the motor. In case of negative reading, shim is to be removed from all four footings of the motor. Axial Horizontal Correction The horizontal axial misalignment is calculated as follows: HA =

( F9 - F3 ) 2

where HA = horizontal axial misalignment F3 = dial gauge reading at 3 o’clock position (face) F9 = dial gauge reading at 9 o’clock position (face) For the correction of misalignment, motor is to be rotated at its centre axis with the help of jacking screws (diagonal to each other) provided at the motor footing. The shim thickness is not to be disturbed. Radial Horizontal Correction The horizontal radial misalignment is calculated as follows: HR =

( R9 - R3 ) 2

where HR = horizontal radial misalignment R9 = dial gauge reading at 9 o’clock position (rim) R3 = dial gauge reading at 3 o’clock position (rim) For the correction of misalignment, motor is to be moved totally across its centre line with the help of jacking screws. The shim thickness is not to be disturbed. This method of alignment is known as rim and face method. Some other alignment methods are also used for alignment that are as follows:

• Dial gauge reversed rim method • Single laser systems method • Twin laser systems method

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21.12  MACHINE VIBRATION The vibration problem of equipments is experienced by most of the engineers. Vibration is the back and forth movement or oscillation of machines and components. Vibration in equipments creates a lot of trouble. When vibration exceeds acceptable limits, immediate attention is required. Abnormal vibration can result from a number of causes. Other than the primary equipment, auxiliary equipments may be the reason of vibration. Some of the major causes of vibration are listed below:

• • • • • • •

Imbalance Misalignment Damaged bearing Shaft run out Wear Looseness Rubbing

The effects of vibration may be severe if not attended promptly. The effects of vibration are given below:

• • • • • •

Accelerate rates of wear Damage equipment severely Create noise Cause unsafe conditions Lead to degradation in plant working conditions Consume excessive power

Fundamentals of vibration can be understood by a vertical spring with weight, as shown in Figure 21.21. At standstill, the deflection of the spring is just sufficient to counter balance the weight W. At position 1, the spring is at rest. The spring is then slowly extended to position 2 and released. The subsequent motion of the weight as a function of time is wavy, as shown in the graph (Figure 21.21). It exhibits the basic characteristics of mechanical vibrations.

Figure 21.21  Spring and vibration.

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The maximum displacement from the rest is called amplitude of the vibration. The vibratory motion repeats at regular intervals (A1, A2, and A3). The interval of time within which the motion sequence repeats is called cycle. The number of cycles completed per second is known as frequency. Vibration is measured and analysed correctly to find out the machine condition. Portable type vibration measuring instrument is used for this. In critical equipments, permanent type vibration measuring probes are fitted which indicate that the vibration of the equipment is on line. Vibration readings are taken at bearing housing of equipment and motor ends in vertical, horizontal and axial directions. Vibration measurement may either be relative or absolute. An absolute vibration measurement is one that is relative to free space. A relative vibration measurement is one that is relative to a fixed point on the machine. The vibration readings are normally expressed in three different values. These are as follows:

• Peak amplitude value • RMS value • Peak to peak value

Peak value is the maximum amplitude of vibration. RMS value is the average value and calculated by multiplying the peak amplitude by 0.707 (for sinusoidal wave). Peak to peak is the total amount of movement (back and forth). The peak value is multiplied by 2 to get this value. This is expressed for displacement only. Figure 21.22 shows the peak, RMS and peak to peak valve.

Figure 21.22  Peak, RMS and peak to peak value

Following are the three methods to measure the vibration:

• Displacement • Velocity • Acceleration

Displacement In displacement, distance or amplitude of the vibration is measured from a resting position. The displacement is expressed in millimetres or micron or miles. Displacement measurement is suitable for low frequency measurements only and is useful for measuring very low amplitude displacements. Non-contacting proximity sensors and eddy probes are used to measure displacement.

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Velocity Velocity is the rate of change of displacement. This measurement determines how far an object is deflected (displacement) and the rate of deflection (frequency). Velocity is expressed in millimetre per second (mm/s). Velocity measurement is suitable for low to medium frequency measurements. Electromagnetic sensors are used to measure velocity. Acceleration Acceleration is the rate of change of velocity. Acceleration measurement is suitable over a wide band of frequencies from very low to very high frequencies. Accelerometers are the most commonly used sensors for measuring acceleration. Acceleration is expressed in millimetre per second square (mm/s2). The amplitude of acceleration, velocity and displacement are related to vibration frequency. Acceleration is the derivative of velocity, which in turn, is the derivative of displacement. Following relation exists between them: Velocity = 2p f  Displacement Acceleration = (2p f )2  Displacement



here, f is the frequency. Phase relations between displacement, velocity and acceleration are independent of amplitude and frequency. The phase difference between acceleration and displacement is always 180° which means that when the object reaches its maximum displacement, the acceleration is maximum in the opposite direction. Velocity always lags acceleration by 90° and leads displacement by 90°. It is maximum when both acceleration and displacement are zero. Another kind of display commonly used by vibration analysts is the spectrum. A spectrum is a graphical display of the frequencies at which a machine component vibrates together with the amplitudes of the component at these frequencies.

EXERCISES

1. 2. 3. 4. 5. 6.

7. 8. 9. 10. 11.

What is a bathtub curve? What factors are considered for preparing a maintenance schedule? What is history book and how does it help in maintenance? Mention some condition monitoring methods. What is proactive maintenance? Which country is having the concept of TPM? How many pillars of activity does it possess? What is the importance of Kazen? What are the main reasons of boiler tube leakage? What is fish mouth opening? What is erosion? What is non-destructive test? Which tests are normally carried out?

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12. 13. 14. 15. 16. 17. 18. 19. 20. 21. 22. 23. 24. 25. 26. 27.



28. 29. 30. 31. 32. 33. 34. 35. 36. 37.

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What is dye penetration test? How is the defect in welding joint detected in radiographic test? Why does deposition take place on the blades of a steam turbine? How can the leakage of a condenser tube be detected? How is the equivalent running hours of a turbine calculated? What is the difference between minor overhaul and major overhaul of a turbine? Which rules and regulations are applicable for a boiler? What are the main duties of an owner during inspection of a boiler? On what factor(s) does the amount of inspection fees depend? When is the boiler certificate renewed? What is provisional order (PO) and when is it issued? What are the main steps followed for certificate renewal of a boiler? What is boiler repairing procedure? What is RLA study? What is the procedure of shield metal arc welding (SMAW)? What is low hydrogen welding electrode? Which electrodes are used for carbon steel and alloy steel? What is TIG welding process? Why are preheating and post-weld heat treatment (PWHT) required? What are the normal defects in welding? Define radial and axial misalignment. Which method is adopted for precision alignment? What are the causes of vibration? What are absolute and relative vibration? Define peak and RMS value of vibration. What are the different methods of vibration measurement? When is the velocity measurement suitable?

Chapter

22

Control and Instrumentation

22.1  INTRODUCTION Control and Instrumentation (C and I) is an important system of any process plant. This system measures and monitors the performance of any plant. So, some basic knowledge about C and I is required by every power plant engineer. Nowadays, the power plant is highly automated. In this chapter, we will discuss in details about the scope and function of C and I in a power plant. Control and instrumentation are two separate functions. Instrumentation takes care of process measurement and control takes care of monitoring and control of these parameters through suitable hardware and software. Nowadays, process control is highly automated. Use of DCS and PLC has made the plant operation very efficient and operator-friendly. Various functions in power plant like maintaining level, speed, temperature, pressure, etc. are done automatically through higher level of automation system. Process measurement measures the process parameters and show the exact condition of different processes to the operator. It may not be possible to describe the scope of C and I in this book. But sufficient care is taken to describe some basics of C and I, used in the power plants to make the reader understand about the functions of C and I in a power plant.

22.2  PROCESS MEASUREMENT In a process plant, it is required to measure various process parameters to know about the current process condition. The process measurement provides some information about the process value by measuring the value of quantity or condition. Mainly, the process measurement comprises of following three elements:

• Sensor or input device • Signal processor • Output device 486

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Figure 22.1 shows the process measurement.

Figure 22.1  Process measurement.

For various process measurements, all these three elements may not be there. But for easy understanding, we will discuss all these three elements. Sensor or Input Device Sensor is the device which is exposed to the process to be measured. For example, thermocouples and vibration probes. These sensors use various principles to convert physical quantity into suitable signal. Signal Processor The input signal received from the sensor is processed or compared with the standard signal to obtain an output signal to indicate the parameter at the output device. Output Device In output device, the measured physical quantity is displayed. Display unit, recorder or plotter are the examples of output devices. The output signal is used for process control also, which will be discussed later. In modern process measurement, the principles used are so complex that we may not separate the above three elements. Sometimes, all these elements are the integral part of a measuring instrument.

22.2.1  P and I Diagram P and I diagram is a very essential drawing for process measurement and control. This is a diagram which shows the pipeline along with the installed equipments, instrumentation and control interlocks. This is a schematic drawing to show the process flow and its control. A standard set of symbols is used to represent all the components. All the components of a P and I diagram are identified by numbering systems. With this unique item number, every equipment, valve, instrument and pipeline can be identified easily. The pipeline number contains its size, thickness, material and fluid contents. Location of instruments and their type can also be identified by some suitable symbols. In a power plant, mostly, following process parameters are measured:

• • • •

Pressure Temperature Flow Level

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• Weight • Vibration • Speed

We will discuss one by one about various process parameter measurements. (Measurement of speed has been discused in Chapter 16.)

22.3  MEASUREMENT OF PRESSURE In the earlier chapters, absolute pressure and gauge pressure have been already discussed. In a power plant, it is required to measure the pressure of steam, water, air, etc. For this measurement, pressure gauges are used. Pressure transmitters are used for process control and measurement at distributed control system (DCS) and programmable logic control (PLC) systems. Various principles are used for pressure measurement. Bourdon tube and manometer are two important principles used for the pressure measurement.

22.3.1  Bourdon Tube Pressure Gauge Normally, pressure gauges are installed at different locations of the boiler and turbine field. Mostly, Bourdon tube type pressure gauge is used. This type of gauge has a tube, called bourdon tube which is bent in a circular arc. One end of the bourdon tube is fixed and connected to the pressure to be measured. The other end of the tube is free (Figure 22.2). When pressure is applied to the tube, radius of the circular arc increases. The movement of free end of the bourdon tube is transmitted to a sector. This sector moves a pointer connected to it over a calibrated scale to give the mechanical indication of pressure.

Figure 22.2  Bourdon tube pressure gauge.

When this pressure gauge is used for measurement of pressure of hot steam, sufficient care is to be taken so that the burden tube does not come in contact with the hot steam directly. Water sealing arrangement is made for this. Following two methods are adopted for the installation of pressure gauge on hot steam pipeline.

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Method 1 In this case, the impulse line is connected to the top of the steam pipeline and the pressure gauge is fixed at a lower level (Figure 22.3). Due to the condensation of steam, water seal is always available.

Figure 22.3  Pressure gauge fixed at lower level.

Method 2 In this case, the impulse line is connected to the top of the steam pipeline and the pressure gauge is fixed at a higher elevation than the steam pipeline. A loop, to collect condensate, is provided in the impulse line near the pressure gauge, as shown in Figure 22.4.

Figure 22.4  Pressure gauge fixed at higher level.

22.3.2  Manometer Manometer is a simple device to measure pressure. It has a transparent U-tube, as shown in Figure 22.5. This tube is partially filled with either water or mercury. Water and mercury are widely used, as their specific weight for various temperatures are known and they do not stick to the tube. Pressure to be measured is applied at one end of the tube of the manometer. Reference pressure (normally, atmospheric) is applied to the other end of the tube. When level of the liquid is balanced, then in that condition

P2 – P1 = g h

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Figure 22.5  Manometer.

where P2 = unknown pressure P1 = reference pressure g = density of manometer liquid h = difference in level In this case, it is assumed that the density of fluid whose pressure is to be measured is negligible.

22.3.3  Pressure Sensor/Transmitter Pressure transmitter generates a signal which is proportional to the applied pressure. The applied pressure is, first, converted into mechanical movement in a pressure sensor. This mechanical movement is then converted into electrical signal. Following techniques are utilised to produce mechanical movement:

• • • • •

Bourdon tube Spring and piston Bellows and capsule Diaphragm Strain gauge

Bourdon tube principle has been explained in Section  22.3.1. The movement of bourdon tube due to applied pressure acts as a presser sensor. In spring and piston method, pressure is applied to a piston which moves against the compression of spring. The position of piston is proportional to the applied pressure. Figure 22.6 shows a spring and piston type pressure sensor. In case of bellows and capsule, when pressure is applied to a closed bellow, then the bellow expands and produces mechanical movement which is proportional to the applied pressure. Figure 22.7 shows a bellow type pressure sensor.

Figure 22.6 Spring and piston type pressure sensor.

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Diaphragm type pressure transmitter is mostly used for process pressure measurement. When pressure is applied on the thin diaphragm, it expands. This movement of diaphragm is utilised to measure the pressure. Figure 22.8 shows a diaphragm type pressure sensor.



Figure 22.7  Bellow type pressure sensor.

Figure 22.8  Diaphragm type pressure sensor.

In strain gauge principle, the mechanical movement changes length of an element. This movement of element can be utilised to change the electrical resistance. The mechanical movement obtained in the above sensor is converted into electrical signal. Following methods are used to get an electrical signal from the mechanical movement:

• Piezoelectric method • Capacitive method

Piezoelectric Method In this type of pressure transmitter, a piece of crystalline material is used. There are certain substances which generate voltage when they are subjected to mechanical forces or stress. These substances are generally crystalline which are available in following two types

• Natural • Synthetic

Natural crystalline are quartz and tourmaline and synthetic crystals include Rochelle salts, barium titrate, ammonium dihydrogen phosphate (ADP). Crystalline material produces an electric charge on its surface when it is mechanically stressed. This electric charge is measured. The crystalline material is stressed due to mechanical movement of the sensor, as discussed earlier. Capacitive Method In this method, the mechanical movement of the sensor changes the capacitance of an electronic component which produces output signal proportional to the pressure applied.

22.3.4  Smart Transmitter Nowdays, smart transmitters are widely used in power plants for measurement and control. This transmitter is microprocessor-based. It has following features:

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It has memory. It can be programmed. It can convert analog signal to digital. This can perform calculations. A smart transmitter can diagnosis self-faults. It can communicate with remote location. This is less sensitive to the effect of temperature and humidity.

This transmitter is preferred over the simple electronic transmitters. Both analog and digital output signals are obtained from this transmitter. Normally, 4 mA–20 mA output signal is obtained from this transmitter. This signal is less affected by the electrical disturbances. Figure  22.9 shows the block diagram of smart transmitter.

Figure 22.9  Block diagram of smart transmitter.

With the help of a communicator, testing, configuring, feeding or acquiring data can be done. Communicator is a handheld interface device that allows digital instructions. The communicator can be connected directly to the smart transmitter or in parallel anywhere in the loop. Mostly, variable capacitance (diaphragm) and variable resistance (strain gauge or piezoelectric) methods are used for the primary sensing of transmitter. In Figure 22.10, a variable capacitance transmitter is shown. When pressure is applied, the movable diaphragm deflects due to pressure difference between both sides of the diaphragm. The moving diaphragm acts as a capacitance plate. Two metallic surfaces act as the fixed plate of a capacitor.

Figure 22.10  Variable capacitor type smart pressure transmitter.

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When the moving diaphragm deflects, capacitance between moving and fixed plate changes. The electronic circuit measures the variation in capacitance between moving and fixed plate and generates a signal which is proportional to the differential pressure applied. Variable resistance smart transmitters are also used nowadays. Absolute pressure, gauge pressure and differential pressure (DP) can be measured by these transmitters. DP transmitters are also used to measure the level and flow. Absolute Pressure To measure the gauge pressure, pressure is applied to one port of the sensor while the other port is kept open to the atmosphere. Gauge Pressure One port of the transmitter is closed (welded or vacuum sealed) when it is used to measure the absolute pressure. When pressure is applied to the other port, it indicates absolute pressure. Differential Pressure (DP) To measure the differential pressure, pressure is applied at both the ports. Transmitter indicates the difference between two applied pressures. Smart pressure transmitters are mounted on manifolds. The manifolds are available in following three types:

• Two-valve manifold • Three-valve manifold • Five-valve manifold

Figure 22.11 shows a two-valve manifold. This type of manifold is used for absolute or gauge pressure transmitter.

Figure 22.11  Two-valve manifold.

Figure 22.12 shows a three-valve manifold. This type of manifold is used for differential transmitter. In this case, when the equalising valve is opened, pressure difference at both sides of the moving diaphragm becomes zero. This valve is used to test zero reading of the transmitter. Proper care is required to be taken while installing a pressure transmitter so that the hot fluid is not applied to the moving diaphragm directly.

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Figure 22.12  Three-valve manifold.

22.4  MEASUREMENT OF TEMPERATURE Measurement of temperature is an important function in a power plant. It is required to measure the temperature of feedwater, steam, flue gas, air, etc. at various points. Temperature is a critical parameter to know about the process condition. For the measurement of temperature, various techniques are used. Like pressure measurement, temperature measurement has two main elements, i.e., sensor and transmitter. The sensor is exposed to hot fluid whose temperature is to be measured. A sensor uses the following principles:

• • • • • •

Thermocouple (TC) Resistance temperature device (RTD) Liquid expansion and vapour pressure Bimetallic Infrared Pyrometer

In power plants, mostly, thermocouple (TC) and resistance temperature device (RTD) sensors are used. Liquid expansion method is used to measure the temperature of process fluid at site. In non-contact methods like pyrometer and infrared techniques, sensor does not come in contact with the hot fluid.

22.4.1  Thermocouple When two different metal wires having different electrical properties are joined at both ends and one joint end is heated, then a potential difference is produced between the two junctions. This phenomenon is called seebeck effect. This potential difference is proportional to the temperature difference between the two joints or junction points. The measured junction voltage is calibrated to the temperature scale. The EMF generated is given by E  a (T1  T2 )  b (T12  T22 ) here, a and b are two constants and depend upon the type of thermocouple.

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Thermocouples are available in several forms. For industrial use the sensor comes in a metal enclosure. Figure 22.13 shows a thermocouple.

Figure 22.13  Thermocouple.

22.4.2  Resistance Temperature Device (RTD) Electrical resistance of a metal conductor changes with the change in its temperature. Resistance increases when the conductor is heated and decreases when it is cooled. The relationship between resistance and temperature is given by

R = RO(1 + a T)

where R = resistance of the conductor when heated to temperature T RO = resistance of conductor at 0 °C a = temperature coefficient of resistance A resistance temperature device (RTD) is shown in Figure 22.14.

Figure 22.14  Resistance temperature device (RTD).

Sometimes, a special type of resistance is used. It is made of small piece of semi-conductor material. In this case, a small change in temperature produces a large resistance change. This type of sensor is called thermistor.

22.4.3  Infrared Temperature Measurement Device This is a non-contact type temperature measuring device. Here, the measurement of temperature is done by measuring the thermal radiation emitted by a hot body. This thermal radiation is called infrared. Wavelength of this radiation is longer than that of visible light.

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22.4.4  Liquid Expansion Type Temperature Measuring Device In this type, the sensor is filled with a liquid such as mercury or a liquid used as a refrigerant. When the sensor is heated, liquid filled inside expands or evaporates. So, the sensor becomes pressurised. The pressure inside the sensor varies as the temperature rises. This pressure raise is measured and converted into temperature scale.

22.4.5  Temperature Transmitter Temperature transmitter is used for the process measurement and control. Output of the temperature transmitter is digital and can be connected to the plant automation system like DCS or PLC. Without installing a transmitter, the output signal of thermocouple and RTD type sensor can also be connected to DCS or PLC, as these signals are electrical quantity. But for transmission of this weak ohm or millivolt signal without disturbance, a transmitter is preferred. In temperature transmitter, this weak low level signal is converted into high level analog signal which can directly interface with an indicator, recorder or DCS/PLC. Transmitter is microprocessor-based and has various advantages. It is required to install the temperature transmitter close to the sensor location to avoid any signal disturbance. 4 mA–20 mA output signal is connected to the control device. Temperature transmitters are available in following three mountings:

• Rail mounting • Field mounting • Head mounting

Rail-mounted transmitter is fixed inside a junction box. The transmitter is fitted into junction box through rail arrangement. Normally, many transmitters are fixed in the junction box to which the sensor cables of various sensors terminate. Output of all transmitters is taken to DCS or PLC. Field-mounted transmitter can be mounted directly at field, as its construction is robust and can withstand difficult industrial environment. This type of transmitter is mounted closure to the sensor. Head-mounted transmitter is an integrated part in the housing or connection head of the temperature sensor.

22.4.6  Thermowell Thermowell is widely used in the power plants. It is used to provide protection to the temperature sensor. The sensor is kept isolated from direct contact with the medium whose temperature is to be measured. Thermowell also allows removing or replacing sensor without any danger of leakage of hot medium.

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22.5  MEASUREMENT OF FLOW In power plants, it is required to measure the flow of fluids like cooling water, feedwater, steam, air, etc. Various types of flow meters are used for this. Some of the common types are given below:

• • • • •

Mechanical flow meter Differential flow meter Electromagnetic flow meter Ultrasonic flow meter Rotameter

22.5.1  Mechanical Flow Meter In this type of flow meter, there is a mechanism positioned at the path of flow of the fluid which rotates continuously at a speed which is proportional to the flow rate. Normally, this type of meter is used to measure the flow of liquid. Mechanical flow meters are available in two groups, as mentioned below:

• Positive displacement type



– – – –

Reciprocating piston Rotary piston Nutating disc Helix type

• Inferential type

– Single or multijet type – Turbine type – Horizontal or vertical propeller type Operating principle of displacement type is volumetric. Displacement of detecting element is proportional to the volume of liquid flow. Shaft of the meter rotates once when an exact quantity of fluid is passed. This rotation can be measured with a mechanical or electronic device which indicates the flow. In inferential type flow meter, rotor of the meter rotates at a speed proportional to the velocity of flow through the meter. Turbine meter is the most commonly used meter in this type. Turbine type meter has a rotor with multiple blades. The rotor spins as the liquid passes through these blades. Speed of the rotor is proportional to the flow rate. This speed can be measured with the help of a magnetic pickup tachometer or mechanical gear arrangement. Figure 22.15 shows a turbine type flow meter.

22.5.2  Differential Pressure Type Flow Meter This type of flow meter is widely used in industries for flow measurement. In power plants, it is used to measure the flow of boiler feedwater, condensate, steam, etc. This meter is maintenance-free, as it does not have any moving part.

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Figure 22.15  Turbine type flow meter.

The basic operating principle of differential pressure flow measurement is very simple. The pressure drop across the meter is proportional to the square of the flow rate or flow rate is proportional to the square root of the differential pressure across the meter. Following elements are used as primary element of these type of flow meters:

• Orifice • Nozzle • Venturi

Figure 22.16 shows the differential pressure type flow measurement. These elements act as an obstacle and are placed at the flow path of the fluid, causing localised changes in the velocity. This change in velocity produces a change in pressure. The differential pressure is measured through a DP transmitter.

Figure 22.16  Differential pressure type flow measurement (a) Orifice, (b) Nozzle and (c) Venturi.

This differential pressure on either side of the obstruction is tapped and measured. Flow is given by the following equation:

q  K DP

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where q = flow K = meter constant DP = differential pressure Orifice is popularly used as a primary device for DP flow measurement. This is a flat metal disc with a specific sized hole bored on it. The orifice plate material is suitable for pressure and temperature range of the fluid to be measured. The hole is concentric, eccentric or conical type. Orifice plate is inserted into pipe between the two flanges. Orifice plates are available in following two designs:

• Thin orifice plate • Sharp square edge orifice plate

22.5.3  Electromagnetic Flow Meter This type of flow meter can measure the flow of any fluid which is electrically conductive. The basic principle of operation depends on Faraday’s law of electromagnetic induction. When an electric conductor moves inside a magnetic field in a direction perpendicular to its lines of force, an EMF is generated which is proportional to the number of lines of force cut by the conductor in unit time. Here, constant magnetic field is generated around the pipe by a magnet or energising coils. The flowing liquid acts as a conductor. EMF is generated which is directly proportional to the flow. Generated EMF is collected from two electrodes mounted at the pipe wall and is measured by some secondary devices which is then converted into flow. Figure 22.17 shows an electromagnetic flow meter.

Figure 22.17  Electromagnetic flow meter.

22.5.4  Ultrasonic Flow Meter Ultrasonic sound wave is used in this type of flow meter to measure the velocity of the flow of fluid. These are available in two types that are as follows:

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• Doppler type • Time of travel or transit type

Doppler meter measures the frequency shifts caused by the liquid flow. Two transducers are mounted in a case attached to the pipe. One transducer is called transmitter and another one is called receiver. Ultrasonic sound wave of known frequency is sent through a transmitter to the liquid whose flow is to be measured. Solids, bubbles or any discontinuity present in the liquid causes reflection of wave which is received by the receiver transducer. As the liquid causing the reflection moves, so the frequency of reflected wave gets shifted. This frequency shift is proportional to the liquid velocity. This reflected signal is measured and converted suitably to find out the flow. Portable Doppler meters are available with rechargeable internal power pack. A Doppler type ultrasonic flow meter is shown in Figure 22.18.

Figure 22.18  Doppler type ultrasonic flow meter.

Time of travel or transit type flow meter has transducers mounted at each side of the pipe. Speed of the signal wave travelling between the transducers increases or decreases with the velocity of liquid to be measured. A time differential relationship which is proportional to the liquid velocity is measured. The liquid whose flow is to be measured, should not have discontinuities (as in the case of Doppler type) so that there would minimum signal scattering and absorption. Figure 22.19 shows a timer of travel type ultrasonic flow meter.

Figure 22.19  Transit type ultrasonic flow meter.

22.5.5  Rotameter Rotameter is an indicating instrument by which flow of most of the fluids can be measured. This is a simple instrument. It has a metering tube and a float. The metering tube normally has a glass tube on which scale is etched and suitable inlet and outlet connection provision is made.

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Flow of fluid takes place through the metering tube vertically upward. When flow takes place, the float raises until a condition of equilibrium is reached. At this point, the upward thrust on the float, due to differential pressure generated because of flow of fluid through the tube, is equal to the weight of float. Position of the float indicates the flow. Figure 22.20 shows a rotameter.

Figure 22.20  Rotameter.

In earlier designs, the float was rotating type for keeping the float at centre and stabilising. So, it was called rotameter. But nowadays, the float is non-rotating type.

22.6  MEASUREMENT OF LEVEL OF LIQUID Level measurement is one of the important process measurements. In a power plant, it is required to measure the level of various liquid and solid materials. Level of liquid like water tank, DM water tank, condenser hotwell, deaerator and level of solids like coal bunker, ash hopper, etc. are measured. In this section, we will discuss about the level measurement of liquid. The level measurement of liquid is of two types—direct method and indirect method.

22.6.1  Direct Method of Level Measurement Level is obtained directly in this method. Mainly, three types of level measurement are used in this method.

• Sight glass type • Magnetic level gauge type • Float type

Sight Glass Type This is a simple method of level measurement of liquid in a tank. It consists of a scaled glass tube which is connected to the lower and upper level of the tank with isolation valves. As the level of the liquid in the tank changes, the level in the glass tube also changes. The glass tube is protected by some metallic protective covering around it. Figure 22.21 shows a sight glass type level measurement.

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Figure 22.21  Sight glass type level measurement.

Magnetic Level Gauge Type Glass type level gauge is unsafe and the glass tube becomes invisible after continuous contact with the medium. So, nowadays, magnetic level gauge is widely used in place of a simple sight glass type gauge glass. Magnetic liquid level gauge has a vertical measuring chamber which is connected to the tank at both the ends like glass type level gauge. This vertical measuring chamber contains a magnetic float. Magnetic float is a permanent magnet and floats inside this measuring chamber. It rises and falls according to the liquid level of the tank. An indicating chamber which contains small metallic strip indicators is attached to this measuring chamber. These metal strip indicators are flipper type. When the float magnet of the measuring chamber passes over these metallic strip indicators, they rotate 180° due to magnetic attraction. One side of the indicator is white while the other side is red. When it is attracted by the float magnet, red side is displayed. These flags are closely spaced and give a very distinct column corresponding to the tank level. Figure 22.22 shows a magnetic level gauge.

Figure 22.22  Magnetic level gauge.

Float Type Level Measurement This is a simple type of level measurement of a liquid tank. A float is used here. This float follows the level of liquid due to its buoyancy. The float is attached to a cable onto which an indicating pointer is attached. The pointer moves over a scale which is calibrated in terms of level of the tank. Figure 22.23 shows a float type level gauge.

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Figure 22.23  Float type level gauge.

22.6.2  Indirect Methods of Level Measurement In this method, level measurement is done by measuring a variable that changes with the level. Some of the widely used methods are as follows:

• • • • •

Pressure gauge type Radiofrequency (RF) capacitance type Differential pressure type Ultrasonic type Radar type

Pressure Gauge Type This is a simple indirect method of level measurement. In this method, the pressure exerted by a column or head of liquid in the tank is measured. A pressure gauge is fixed at the lowest level of the tank. The pressure at this point changes with the change in height of the liquid inside the tank. The pressure measured is calibrated to the height of the liquid level. Figure 22.24 shows a pressure gauge type level measurement.

Figure 22.24  Pressure gauge type level measurement.

Radio Frequency (RF) Capacitance Type Radio frequency (RF) capacitance uses the electrical characteristic of a capacitor to measure the level. In this method, a measurement probe is placed inside the tank. This probe acts as one plate of capacitor and the tank metallic wall acts as another plate. These two plates are separated by

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the medium whose level is to be measured. When the level of medium changes, capacitance of the above capacitor also changes. This change in capacitance is dependent upon the level of medium. In this case, the medium should be an insulating material. When the medium is conducting, an insulating coat or sheathing is applied over the measuring probe. Probe acts as one plate of capacitor whereas, conducting medium acts as another plate and the applied sheathing of the probe acts as an insulation between these two. As the level of fluid changes, the capacitance also changes. The measured capacitance is converted into level of tank. Figure 22.25 shows a radiofrequency (RF) capacitance type level measurement.

Figure 22.25 RF capacitance type level measurement (a) Non-conducting medium and (b) Conducting medium.

Differential Pressure Type Differential pressure (DP) method of level measurement is widely used in the power plants to measure the level of various storage tanks. One port of the transmitter is connected to the lower level impulse line and another port is connected to the upper level impulse line. Level can be measured between these two tapings by measuring the differential pressure between these two. When the tank is full, pressure at lower taping is more and DP is also more. When tank level is low, then the pressure at lower taping is less and DP is less. When the tank is at atmospheric pressure, upper tapping is not required. This end of the DP transmitter is kept open to the atmosphere. The DP measured by this method is converted into level. Figure 22.26 shows a DP type level measurement.

Figure 22.26  DP type level measurement.

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Ultrasonic Type In this method, ultrasonic sound wave is used to measure the level. A transmitter directs the ultrasonic wave downwards, i.e., towards the surface of measuring material. Echo of this wave is received by a receiver. Time taken by the wave from its transmission to receipt indicates the level of process material. The sensor (consisting of transmitter and receiver) is fixed to the top of the tank. This is a non-contact type level measurement. Figure 22.27 shows an ultrasonic type level measurement.

Figure 22.27  Ultrasonic type level measurement.

Radar Type In this method, electromagnetic microwave is used. This is a non-contact type level measurement. Electromagnetic wave is directed downward to the process fluid surface through a sensor consisting of transmitter and receiver. The receiver of the sensor receives back a portion of the energy that is reflected from the process fluid surface which indicates the level of medium.

22.7  MEASUREMENT OF LEVEL OF SOLIDS In Section 22.6, we have discussed the method of level measurement commonly used to measure the level of liquids. In a power plant, it is required to measure the bunker, silo or bin level of solids like coal, ash, etc. In this section, we will discuss only some commonly used methods to measure the level of solids. Following techniques are used to measure the level of solids in bins, hoppers or silos:

• • • • •

Ultrasonic Guided wave radar Radar Laser Load cells/strain gauges

First four methods measure the distance from sensor location to the surface of the material and hence, the height of material in the vessel. Load cell or strain gauge measures the mass of material by measuring the force exerted on a sensing element. Radar method has already been discussed in section 22.6.

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Ultrasonic Type Like ultrasonic level measurement of liquid, level of any solid in a vessel is measured. The time between the transmitted and reflected ultrasonic wave indicates the height of material in the vessel. Guided Wave Radar Type The radar method of level measurement is called time domin reflectometry (TDR). But, in this method, there are chances of false echo from the walls of vessel. To overcome this difficulty, guided wave radar technique is used. In this technique, a rod or cable is used to guide the microwave as it passes down from the sensor into the material whose level is to be measured. By this technique, the spread of microwave beam is controlled with the help of a probe that is introduced directly into the media. This guide probe concentrates the radar signal within a small diameter cylinder along the probe. Laser Type In this method, distance from the sensor to the surface of material is measured. A microprocessorbased measuring device calculates the distance by multiplying the speed of light by the time taken by a laser pulse to travel from the sensor to the target and then moving back to the receiver. Infrared light is used in this case. The laser beam has very little divergence so that an accurate targeting is possible. Load Cell/Strain Gauge Type Load cell is a popular device to measure weight. The weight of material is converted into measurable electrical output. In this method, the material in the bin, hopper or silo is weighed continuously through a load cell. By knowing the weight of material, volume of the material is calculated. The entire bin is supported by load cell. Any change in the material level in the bin produces a change in the weight which is measured by a load cell. Strain gauge is one type of load cell. Mostly, it measures the resistance. It acts on the principle that when a metal conductor is stressed or compressed, its resistance changes due to the change in its length and diameter.

22.8  CONTINUOUS WEIGHT MEASUREMENT In a power plant, it is required to measure the weight of the material conveyed continuously through a conveyor belt. Particularly, it is required to weigh the coal that is fed to the boiler through a conveyer belt. For this purpose, belt weigher is used. In this section, we will discuss about a simple belt weigher which is mostly used for belt weighing purpose. A belt weigher measures the weight of bulk material while in motion. Belt weigher uses a load cell to measure the material weight on the belt and send this signal to a processor where the conveyor speed is also measured. The conveyed material applies a force proportional to its

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weight through the belt to the load cell. Using weight and speed of the conveyor, the processor calculates the rate of material transferred on the belt.

22.9  MEASUREMENT OF VIBRATION Measurement of vibration and axial displacement of turbine rotor are some critical functions in any turbine turbovisory system. We can find very simple vibration measuring system in power plants. For the measurement of vibration, vibration measuring sensors are used as primary sensing element. This sensor produces electric signals using eddy current principle. The sensor contains a coil which is wound on a permanent magnet. When a ferromagnetic material is moved with respect to the magnet, magnetic flux created by the coil varies and hence, the induced EMF too. This induced EMF is proportional to the gap between the magnet and the ferromagnetic material. This gap voltage indicates the gap between the ferromagnetic material and the sensor.

22.10  PROCESS CONTROL Process control is one of the important instrumentation function in any process industry. The output of any process is measured and corrective action is initiated in case of any deviation from the desired level. So, the process control is the combination of process measurement and corrective action in case of deviation. For any process control, there are following elements:

• Primary measuring device or sensor • Controller • Actuator or output device Figure 22.28 shows the block diagram of process control.

Figure 22.28  Block diagram of process control.

Primary measuring device or sensors are listed below:

• • • •

Sensing devices Switches or pushbuttons Proximity switches Limit switches

Actuator or output devices are listed below:

• Valves • Solenoids

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• Motor • Actuators • Positioners

Process parameter is measured by a measuring device or sensor which gives feedback to a controller. The controller compares this input with the preset value and generates a signal which actuates an actuator or output device to bring back the process parameter to the normal desired value. In this section, some details about controllers are given. Following are the two types of control system:

• Open loop control system • Closed loop control system

Open Loop Control System In open loop control system, the output device or actuator is actuated when the output process value reaches a preset value. Figure 22.29 shows an open loop control system.

Figure 22.29  Open loop control system.

For example, a liquid is to be filled in the tank when the level of the tank falls to certain level. Level switch of the tank operates when the level becomes low and opens a valve to fill up the tank, as shown in Figure 22.30.

Figure 22.30  Open loop control.

Closed Loop Control System In the above example, the tank can be filled up by a level switch. But the level in the tank cannot be maintained to a certain level automatically. In closed loop control system, it is possible. The level in the tank can be maintained upto the desired level with very little deviation. For example, let us consider the above tank. To keep the tank level always at 80%, we have to consider close loop control system in this case. In this case, the level of the tank is continuously measured. When level falls below 80%, then the controller generates a signal to open the control valve, as shown in Figure 22.31. This

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valve allows the fluid to flow to the tank. When level becomes more than 80%, the controller output closes the valve.

Figure 22.31  Closed loop control.

In this case, the output is measured continuously and used as a feedback of the controller. Figure 22.32 shows a closed loop control system.

Figure 22.32  Closed loop control system.

This measured feedback is always compared with the setpoint and control action is initiated if there is any deviation. The difference between setpoint and feedback is called error signal. In power plant process control, this close loop control system is widely used to control the process variations.

22.11  PID CONTROLLER Most of the closed loop control system, used nowadays to control the process variations, uses PID controller. This is a very simple controller having ability to control any difficult or complicated process and with proper tuning, it can maintain the process value very close to the setpoint. In PID controller, ‘P’ stands for proportional, ‘I’ stands for integral and ‘D’ stands for derivative. The error signal (difference of setpoint and feedback) is used to get the output signal from the controller. In proportional (P) element, the actuating signal is proportional to this error signal. In integral (I) element, the actuating signal is an integral function of the error signal and in derivative (D) element, the actuating signal is the derivative function of error signal. To get a better control effect, the PID elements are tuned separately. Microprocessors are used for PID controller. A PID controller has three display windows to display the process value (PV), set value (SV) and the actuator position. Figure 22.33 shows a PID controller.

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Figure 22.33  PID controller.

It has facility to tune P, I and D elements. Buttons are provided to change the setpoint and put the controller in auto or manual control mode. Nowadays, PID controllers are programmed in PLC or DCS system.

22.12  ACTUATOR OR OUTPUT DEVICE As discussed earlier, the actuating signal obtained from a controller is used to correct the process parameter through an output device or actuator. Actuator or output device is the final correcting device in process control. Some of the important output device used for process control in power plant are listed below:

• • • • • • •

Control valve Solenoid valve Electrically operated valve Pneumatic cylinder Hydraulic cylinder Variable speed drive Motorised positioner

Some of the above devices are pneumatically operated and some are electrically operated (motorised). Sometimes, hydraulic operated actuators are also used. The main function of these devices is to control the process parameter.

22.12.1  Pneumatically Operated Control Valve Pneumatic control valves are mostly used in the power plants for process control. A list of following process control done by these valves in a power plant is given below:

• Boiler drum level control • Final steam temperature control • Hotwell level control

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• Deaerator level control • Steam pressure and temperature control at PRDS

Mostly, diaphragm type control valves are used. In this valve, there is a pneumatic actuator which operates a valve for the final process control. Linear motion of the valve spindle is achieved due to upward and downward movement of the actuator. The upward and downward movement of diaphragm is obtained by the compressed air. There is a flexible membrane called diaphragm. When the compressed air is applied on this diaphragm, a force results which is equal to the air pressure multiplied by the area of diaphragm. Due to this force, the diaphragm moves against a spring. This spring keeps the valve in required position (open or close) in the absence of air supply. As the air pressure increases, force on the diaphragm increases. Spindle starts moving against the force of spring. This movement stops where the spring tension is equal to the applied force on the diaphragm. Normally, two types of valves are used depending upon the process it has to control. These are as follows:

• Air to open • Air to close

The choice between these two depends upon to what position the valve should back in case of failure of compressed air supply. The closing and wide opening of the (in case of failure of air supply) depends upon the nature of application and safety requirements. Figure 22.34 shows pneumatically operated control valve.

Figure 22.34  Pneumatically operated control valve (a) Air to close and (b) Air to open.

In air to close type control valve, the valve remains in open condition during the absence of air supply. When air is applied from the top over the diaphragm, the force exerted compresses the spring and moves the spindle downward to close the valve. As the air pressure increases, the valve plug moves progressively and finally, closes the valve. When air fails, the valve spindle moves due to the action of spring and opens the valve. In air to open type control valve, the valve remains close during the absence of air. Air is applied below the diaphragm. The force exerted, compresses the spring and moves the spindle upward to open the valve. When air pressure increases, the force on the diaphragm increases which compresses the spring further and opens the valve fully. When air fails, valve closes

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immediately due to the spring action. A scale and pointer is attached to the spindle to know the position of valve. Basic design of any pneumatic control valve depends upon the following aspects:

• • • •

Temperature of process fluid Pressure difference between upstream and downstream of the valve seat Permissible leakage Fluid volume that the valve has to handle

Positioner and I/P Converter The concept of pneumatic type control valve has been discussed. Sometimes, a positioner and an I/P converter is attached to the valve. Due to higher friction and higher differential pressure, more air pressure is required to operate a valve. In these valves, stronger springs are used to overcome these effects. In this situation, a positioner is fitted to the valve yoke and linked to the spindle of the valve by a feedback arm in order to monitor the valve position. The positioner has three ports connected to the compressed air supply, control pneumatic signal from controller or I/P converter and output air to control valve respectively, as shown in Figure 22.35.

Figure 22.35  Positioner.

The positioner compares input pneumatic signal and valve position and provides output pressure to the actuator accordingly. The merits of positioner are listed below:

• It ensures a linear relationship between the input and the control valve position, irrespective of the change in differential pressure, stem friction, etc. • It acts as a signal amplifier. It obtains low pressure pneumatic signal from controller or I/P converter and provides a higher pressure output signal to the actuator diaphragm by using a separate high pressure input. • Valve positioning is accurate. • Valve response is faster.

The above discussed positioner is also called P/P converter. This positioner uses pneumatic signal to provide a pneumatic output. Any control valve with P/P converter and I/P converter can be used in PLC or DCS-based automation system for process control. I/P converter converts 4 mA-20 mA electrical signal from DCS to a 0.2 bar to 1 bar pneumatic signal. The arrangement of I/P and P/P converter and control valve is shown in Figure 2.36. Nowadays, smart positioners are used which are microprocessor-based for better process control.

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Figure 22.36  Control valve arrangement.

22.12.2  Solenoid Valve Solenoid valve is an electromechanical valve. The valve is operated by electric supply. Mostly, these valves are on or off type. The valve consists of a solenoid which is a coil. This coil is magnetised when an electric current passes through it and attracts a plunger which changes the state of the valve position. The valve is available as normal open (NO) and normally closed (NC) type. In NO type valve, the valve closes when current is supplied to it. Whereas, NC type valve opens when current is supplied. A spring is used to bring back the valve to the original position in case of failure of current. Solenoid valve is available in two or three-way port connection.

22.12.3  Motorised Valve In some applications, motorised valve is used in place of pneumatic valve. Motorised valve uses an electric motor to operate the valve. Spindle of the valve is connected to a motorised actuator. The valve may be globe, gate or butterfly type. Movement of the spindle depends upon the type of valve. In case of butterfly valve, the spindle rotates. In case of globe or gate valve, the spindle movement is longitudinal. The actuator may be multiturn or part-turn type. In case of globe or gate valve, the actuator has to rotate so many times to open or close the valve. But, in case of butterfly valve, the actuator has to move only 90°. To convert the rotational movement of the actuator to longitudinal, there is a gear arrangement. Motorised valves are used for three different application duties that are as follows:

• Open–close duty • Positioning duty • Modulating duty

In open–close duty, the valve is used either to open or close the valve. Intermediate positioning is not possible in this case. These valves are rarely operated and the interval between their operations is more. In positioning duty, the valve can be hold at any intermediate position between open or close.

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In modulating duty, the valve can be used in closed loop process control system where the valve position changes continuously to maintain the process parameter. Components of a Motorised Valve A motorised valve consists of the following main components: Motor:  Single phase or three-phase motor is used as actuator. Sometimes, DC motor is also used. Motor moves in forward or reverse direction, as per the requirement to open or close the valve. The motor is having higher torque to take care of sticky valves. As the valve is to be placed at very extreme working atmosphere, so the motor is not fan-cooled. Normally, this motor does not have continuous rating. The motor requires time to cool after certain time. Gear:  To reduce the speed of motor, gear arrangement is provided. The reduction ratio is more and the gear is self-locking type to prevent an accidental closing or opening. Clutch and manual lever:  During non-availability of electric supply, the valve can be operated through a hand wheel. Clutch arrangement is provided so that the hand wheel does not move during motor operation. Limit and torque switch:  To stop the actuator at the end position (full open or full close), two limit switches are provided. When the valve reaches the end position, the limit switch of that end operates and the motor is stopped. Hence, these limit switches protect overtravel of the valve. Torque switch is provided to prevent the actuator from overloading due to high torque. Motor control switchgear:  The motor control switchgear is placed inside the actuator where the contactors or thyristors are placed to switch on or off the motor as well as to rotate the motor in forward or reverse direction. Also, position feedback of the valve is obtained to indicate the valve position at DCS or PLC.

22.12.4  Pneumatic Cylinder Pneumatic cylinder or air cylinder uses compressed air to produce force and hence, movement of a piston in linear direction. When compressed air enters the cylinder, it pushes the piston and thus, the air expands. A rod is connected to this piston. Movement of the piston moves this rod in linear direction. These cylinders are found in various sizes. Pneumatic cylinder is normally used to operate dampers of ID and FD fans. Signal from the controller is used to position the cylinder at a desired position. Pneumatic cylinders are available in following types:

• Single acting cylinder • Double acting cylinder

Single Acting Cylinder In single acting cylinder, air is admitted into the cylinder at one end. It pushes the piston against the force of spring. When air pressure increases, the movement of piston takes place

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and when air pressure reduces, the spring moves the piston to home position. Figure 22.37 shows a single acting pneumatic cylinder.

Figure 22.37  Single acting pneumatic cyliner.

Double Acting Cylinder In double acting cylinder, air is used to move the piston at both the directions. Air is admitted into the cylinder at both ends of the cylinder. When air pressure below the piston is more than that of above the piston, piston moves forward and when air pressure above the piston is more than that of below the piston, piston moves backward. Figure 22.38 shows a double acting pneumatic cyliner.

Figure 22.38  Double acting pneumatic cyliner.

22.12.5  Hydraulic Cylinder Pressurised oil is used in hydraulic cylinder to obtain linear movement of the piston. The pressurised oil is admitted to one end of the cylinder. Due to pressure of oil force (F = P  A) is created on the piston, where A is the area of piston and P is the pressure of oil. This force moves the piston in forward direction. Piston is fitted with suitable seals or O-rings to prevent oil leakage. The piston is connected to a rod which moves along with piston. This rod is connected to the device which is to be controlled. Rod gland is provided at the interface area between cylinder head and rod to prevent oil leakage. Like pneumatic cylinder, hydraulic cylinder is also available in various sizes. Hydraulic cylinder is used at turbine stop valve and governing valve.

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22.12.6  Variable Speed Drive Variable speed drive or variable frequency drive (VFD) is used for various applications in power plants. For process control, these drives are used at following areas:

• • • • • • •

ID fan (to control draft of boiler) FD fan (to control air supply to the boiler) Coal feeder (to control coal supply to the boiler) Cooling water pump (to control cooling water supply to the condenser) Cooling tower fan (to control water temperature) Condensate extraction pump (to control hotwell level) Boiler feed pump (to control boiler drum level)

Variable speed drive or variable frequency drive is used to control the speed of drive by controlling the frequency of power supplied to an AC motor. As the frequency is varied, so these drives are called variable frequency drive (VFD). Sometimes, this is also called variable voltage variable frequency (VVVF) drive. Speed of a motor is given by where F = frequency in hertz P = number of poles of the motor

RPM  120 

F P

The block diagram of VFD is shown in Figure 22.39.

Figure 22.39  Block diagram of a variable frequency drive.

Normally, three-phase AC power is connected to a variable frequency controller. Depending upon the operator interface signal or output signal from the process controller, variable frequency controller generates a three-phase variable frequency power which is connected to a threephase AC induction motor. Speed of AC motor varies according to the frequency to change the process parameter to a new value. During starting of VFD, normally, low frequency and low voltage are applied to the motor. So, high starting current is reduced. Then, the voltage and frequency are increased at a control rate called ramped upto accelerate to obtain the required output. Variable Frequency Controller This is the main part of VFD. It changes the frequency of the power supply. This is a solid

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state electronic power conversion device. For conversion of power, the controller has following two units:

• Rectifier unit • Inverter unit Figure 22.40 shows a variable frequency controller.

Figure 22.40  Variable frequency controller.

The rectifier unit consists of a three-phase diode bridge. The applied three-phase AC power is converted into DC intermediate power in this unit. The DC power obtained from the rectifier unit is converted to three-phase AC power again with the required frequency. Electronic switches and thyristors are used for this. Desired voltage and frequency are obtained by switching on and off the DC output of rectifier unit through these electronic switches and thyristors. The output waveform of the inverter is closely approximates a sine wave. Output voltage is varied by changing the width and polarity of the switched pulses, whereas the output frequency is adjusted by changing the switching cycle time. Output of this inverter unit is connected to the motor which controls various process parameters.

22.13  PLANT AUTOMATION Automation is a very complex system in a process industry. The meaning of automation is automatic process measurement, logical calculation and control to a desired value in totality of plant operation. Nowadays, the automation is very improved and plant operation is automatic to such an extent that human interface is eliminated to a certain extent. High speed data processing capability of microprocessor has brought a revolution in today’s industrial automation. Giving details of plant automation is beyond the scope of this book. Hence, we will discuss some main features and some basic idea about the plant automation system. Nowadays, mainly, programmable logic control (PLC) or distributed control system (DCS) are used for plant automation. This system can handle a lot of data and make a decision to control the plant process based upon the preloaded programme. This system can handle very complex process operation. The speed and accuracy of PLC and DCS are very high. We will discuss about PLC and DCS in the subsequent sections in detail.

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22.14  PROGRAMMABLE LOGIC CONTROL (PLC) PLC is a special computer device used for plant automation. PLC belongs to computer family having in-built random access memory (RAM) and read only memory (ROM) features. It has a central processor unit (CPU) for the entire data processing. Single PLC can replace thousand of control relays. PLC is programmed for a specific process control which can be changed as per the requirement. According to programming, PLC continuously measures the process inputs and generates output signals. PLC also provides process feedback and understands operator’s instructions. A simple block diagram of PLC is shown in Figure 22.41.

Figure 22.41  Block diagram of PLC.

PLC is used nowadays in almost all industries for process automation in place of hardware control system. PLC is available in various sizes and shapes. Small Fixed Type PLC Small fixed type PLC of smaller capacity is used for small control logic of some individual equipment like compressors, ash handling system, etc. PLC used in this case is smaller one having few inputs and outputs (I/Os). The processor capacity is also low. All the components of this type of PLC are mounted on a printed circuit board. Small logic programme is loaded to the PLC through computer. Most of the time, this PLC is used for a specific requirement. The PLC used for compressor is only look after the operational automation of compressor. This type of PLC has no slotted components. Defect on any circuit of PLC requires to change the entire PLC unit. This PLC is used in small equipments and circuits having lesser operational logic. Most of the operational checks can be viewed on two or three line display window through scrolling push button sets. This PLC can be mounted in any type of atmosphere close to the equipment. Modular Type PLC This type of PLC is used for complex process automation of a plant having critical logic with a lot of inputs and outputs (I/Os). All the components of this type of PLC are in the form of individual printed circuit board and housed within an enclosure called module. These modules slide into the slots provided in the back plate. To facilitate connection of individual modules

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to the back plate, slots are provided. Back plate is a large printed circuit board. Different types of terminal blocks are provided to facilitate the termination of input and output terminals. This PLC is having a larger process data handling capability depending upon the process complexity and mounted in a panel. Modular type PLC is widely used for plant automation. It has a lot of merits. Some of them are listed below.

• • • • • • •

It is easier for troubleshooting. Defective module can be easily replaced. Capacity can be easily expanded by adding more compatible modules. I/O modules can be expanded to add any further improved process control logic. It is mounted in panels. So, it can be located in a safe and controlled atmosphere. It can be programmed at site as per the requirement and can be updated time to time. Larger capacity of PLC is possible. Different modules can be placed at different panels.

22.14.1  Different Modules of PLC As discussed earlier, PLC is having different modules for different functions. In this section, we will discuss about some main modules of PLC. These are as follows:

• • • • •

Power supply module CPU I/O module Ethernet module Profibus module

Power Supply Module This module supplies the power requirement of PLC. Sometimes, two power supply modules are used for redundancy in power supply. Power module contains a battery to supply power to the processor during failure of auxiliary power supply. CPU Central processing unit (CPU) is the main module of any PLC. This is the brain of PLC. CPU module is fixed to the base plate through sliding slots. CPU consists of microprocessor, memory chip and other integrated circuits to control logic, monitoring and communication. In programming mode, the programme logic is downloaded from a PC to the memory of CPU where it is stored. In run mode, the programme is executed to control the process. The programme is stored at read only memory (ROM) which is backed up by lithium battery supply source. CPU scans input and update the output accordingly based upon the programme. Scan time of CPU is very fast of the order of 1/1000th of a second or milliseconds. CPU processing cycle is shown as a block diagram in Figure 22.42.

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Figure 22.42  CPU processing cycle.

Sometimes, two CPU units are provided to get redundancy in processor. I/O Module Input and output are connected to PLC through I/O module. It provides physical termination between equipment and PLC. Different I/O modules are used for different I/Os. In PLC, various types of inputs and outputs are used. Some of them are analog signals, mainly 4 mA–20 mA signals. Some of them are discrete or digital which give a signal that is either on or off. Sometimes, an isolation circuit is provided for inputs and outputs to keep the field signals isolated from the PLC. Some important inputs and outputs are listed below: Digital inputs (DI):  These include

– – – –

Push button Selector switch Limit switch Relay contacts

Analog inputs (AI):  These include

– – – –

Pressure transmitter Flow transmitter Level transmitter Temperature transmitter

Digital output (DO):  These involve

– – – –

Pilot light Solenoid Relay coil Motor starter

Analog output (AO):  These include

– – – –

Pneumatic control valve Variable frequency drive Analog meter Hydraulic or pneumatic actuator

I/O modules are available in 8, 16, 32 or 64 channels to facilitate connection of 8, 16, 32 or 64 inputs or outputs. These modules are arranged in such a way that in future, some more modules can be added. Cable from the field equipment is terminated to the I/O module

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through a suitable terminal block set. Digital or analog inputs or outputs are terminated to the respective module. Ethernet Module This is used for communication between PLC and operator console. Sometimes, more than one PLC are used for plant operation and there are more than one operating stations and engineering stations. Communication between them is possible through Ethernet cable and hub arrangement. Profibus Module This module is also used for communication in between PLCs as well as in between PLC and I/O module.

22.14.2  PLC Programming As discussed earlier, the logic programme of PLC is stored in the ROM of PLC. This is downloaded to the PLC memory from a PC. Normally, this PC is called engineering station. This PC is connected to PLC through networking or Ethernet. In programming mode, the programme can be modified or edited. But, in run mode, the programme is run without any scope of modification. The process logic is written by various methods. Some of the widely used methods are mentioned below:

• Ladder logic • Function block

Ladder logic is a very simple and widely used programming method. It uses symbols instead of words. The completed programme looks like a ladder though it represents an electrical circuit. Let us consider the following case as an example. When the level of tank decreases, limit switch LS 1 closes and coil C1 picks up to start pump M. When the level of tank increases to a certain level, limit switch LS 2 closes and coil C2 picks up. Hence motor M stops. Ladder circuit of the above example is shown in Figure 22.43. This is the simplest example of ladder logic. Left and right of the ladder indicate positive and ground of power supply. The rungs represent wiring among the different components. Large critical process logic can be written on ladder diagram method having many rungs.

Figure 22.43  Simple ladder logic.

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22.14.3  Other Features of PLC Other than process control, PLC is having other data handling facility which is required for assessing the plant performance. Some of these features are listed below:

• • • • •

Process information Trending Alarm handling Report generation Data logging

Process Information Real-time process data is visible at the operator console to inform an operator about the current process status. Trending The process data obtained is shown in graphical form. Trend of variation of any process parameter indicates the process behaviour in the past for certain duration. Trend can be obtained for one minute to some weeks. Alarm Handling This feature of PLC provides an alarm in audible form, in case, any parameter goes beyond a certain desired level. This abnormal situation can be recorded for future reference. Report Generation Different reports are possible to be generated by putting different types of queries. Recorded data available in PLC memory is used for this. Data Logging Real-time process data is stored for future use. Capability of data handling depends upon the memory of PLC. Each PLC is having a certain memory level. So, after sometime, back up of the logged data is taken and the data is deleted from the memory for further data logging.

22.15  DISTRIBUTED CONTROL SYSTEM (DCS) DCS is used in today’s industrial automation having more complex process and a lot of input output signals. DCS combines various standalone process controls to a common platform and integrates all the required hardware. DCS may be categorised as higher version of plant automation system. Nowadays, there is no significant difference between PLC and DCS. DCS is same as earlier discussed modular type PLC having all the discussed modules. PLC of different processes are networked through Ethernet to get a common centralised operating system. Workstations, engineering stations and various PLCs are integrated through networking. An operator can access any data of any PLC

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subsystem from any workstation. This makes the plant operation centralised and the data can be obtained from a common information base. DCS combines different PLCs of different areas. So, it is not possible to differentiate PLC from DCS. Figure 22.44 shows the combination of PLCs and DCS.

Figure 22.44  PLC and DCS.

22.16  HUMAN MACHINE INTERFACE (HMI) In any automation system, the data to be shown to the operator should be in such a way that it can be understood by the operator and the manipulation made by an operator in the workstation can be understood by the processor of DCS or PLC. For this, special software is required to be loaded. HMI is an interface between man and processor to interact. These includes graphics, flow diagrams, knobs, levers, control buttons, etc. The manipulation made by an operator is converted into processor recognised language to control the desired process. At workstation PCs, operator works with HMI. Various separate pages are found in the workstation to control various parameters. These pages are animated to provide information to the user in a very friendly manner. These pages are made as per the operator’s convenience.

EXERCISES

1. What is P and I diagram? 2. What are the three elements of process measurement? 3. Why is a manometer used? 4. What is a smart transmitter? 5. How are gauge pressure, absolute pressure and differential pressure measured in a smart transmitter? 6. What are the principles used to measure the temperature? 7. What is the principle of thermocouple (TC) and RTD? 8. What is thermowell and why is it used? 9. What are the methods used to measure the flow? 10. Why is a rotameter used? 11. What are the methods used for the measurement of liquid level? 12. How does a belt weigher work? 13. What are the three elements of process control?

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Explain the open loop and close loop control system. What is PID controller? What is the difference between air to open and air to close pneumatic control vales? Where is variable frequency drives (VFD) used? How many types of PLCs are available? What are the different modules in a PLC? What are DI/AI inputs and DO/AO outputs? What are the features of PLC other than process control? What is human machine interface (HMI)?

14. 15. 16. 17. 18. 19. 20. 21. 22.

Chapter

23

Scope of Energy Conservation in Thermal Power Plants

23.1  INTRODUCTION Huge quantity of primary fuel is used at thermal power plants to generate electricity. Efficiency of thermal power plant is only 30%–35%. So, only 30%–35% of the energy input is converted into electricity. Rest of the energy is lost. A 500 MW thermal power plant consumes around 10000 t of coal per day. Saving of 1% coal per day will save 100 t of coal per day and 30000 t of coal per annum (considering 300 operating days). Reduction in coal consumption not only saves the primary fuel but also reduces CO2 emission. It is important to reduce the greenhouse gas emission which is the greatest threat that we are facing today. Energy conservation is the only solution for the cost-effective use of finite natural resources, minimising fuel cost, increasing profitability and minimising environmental effect. Some well known energy conservation methodologies are discussed here for an effective operation of a thermal power plant. There is tremendous scope to save huge amount of fuel if these techniques are adopted during operation and maintenance of thermal power plants.

23.2  ENERGY CONSERVATION IN BOILER In a boiler, fuel combustion takes place and high pressure steam is produced to drive a turbine. A lot of potential is there to reduce the fuel consumption in a boiler by adopting some suitable methods. Some of the methods are discussed below: Excess Air Control For burning of fuel, oxygen is required. Oxygen is obtained from atmospheric air. Only 21% of oxygen is utilised for combustion. 78% nitrogen is having no role for combustion. But, it is handled to supply an adequate amount of oxygen. As discussed earlier, shortage of oxygen is responsible for incomplete combustion. Like this, excess oxygen is also responsible for 525

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unnecessary handling of air and heat loss on flue gas. So, the required amount of oxygen or air, as per the boiler design, is to be supplied to the boiler for combustion. Continuous monitoring of O2 and CO can optimise the boiler operation and save the fuel consumption. Excess air percentage can be calculated as follows:

Excess air percentage =

Percentage of oxygen in flue gas ¥ 100 (21 - Percentage of oxygen)

Online oxygen analyser is to be checked and calibrated regularly. The reading is to be cross checked with a portable analyzer or an Orsat apparatus. Water Quality and Tube Cleaning Improper boiler water treatment is responsible for scale formation inside the surface of a boiler tube. Scale is a bad conductor of heat. So, heat transfer is affected due to scale. Scale formation can be avoided by maintaining a proper boiler water quality. Water quality is to be checked regularly. Online water quality monitoring system is very effective. Despite of all the care taken, scale is formed in the boiler tube and affects the heat transfer. Periodical chemical cleaning of tube internal can be done to increase the heat transfer. External surface of the tube can be cleaned thoroughly by high pressure water jet or by brushing periodically to remove the fireside scale and soot deposition. Optimising soot blowing also helps to make the tube external surface clean. Arresting Air and Flue Gas Leakages Normally, the boiler casing and the ducts of a boiler are insulated. After continuous operation cracks and leakages may develop there. So, the casing and ducts are to be checked regularly and any leakage found is to be repaired. Manholes and inspection doors are to be properly closed to avoid air ingress. Leakage in combustion air (FD, secondary and primary) system can easily be found, as air leaks with pressure. Most of the time, air leakage is experienced at air heater. Fresh atmospheric air leaks to the flue gas. In this case, the power of FD and ID fan increases. Air heater is to be tested periodically and leaked tube is to be repaired or plugged to minimise the air leakage. Leakages are also found at flue gas path, i.e., boiler furnace, economiser, air heater, flue gas ducts, ESP casing, damaged expansion bellow, etc. Cold atmospheric air is soaked through these leakages, as this circuit is at negative pressure. Leakage at flue gas path increases the flue gas volume and hence, ID fan power increases. Leakage can be found by measuring O2 level at various locations of the flue gas path. If O2 level is more than that of the boiler furnace, it indicates there is an air ingress into the flue gas path. Significant amount of power can be saved by repairing these leakages. Proper Combustion Burning of fuel takes place in the boiler furnace. If the combustion is not proper, then unburnt fuel is carried out with the flue gas or ash. Shortage of combustion air, improper fuel distribution in furnace and improper fuel size are some of the reasons for incomplete combustion.



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For complete burning of fuel three Ts, i.e., time, temperature and turbulence play an important role. Turbulence can be adjusted by adjusting secondary and primary air for complete combustion without much excess air. Flame condition is to be checked regularly to optimise the burning condition in the furnace. Optimise Blowdown Blowdown is required in a boiler to maintain the TDS level of boiler water. Significant amount of heat is available in this blowdown water. Excess blowdown causes heat loss and requires more make-up water. So, blowdown quantity is to be selected strictly as per the requirement. Automatic blowdown control system can be installed to optimise the blowdown quantity and hence, minimise the loss of energy. Heat Recovery from Blowdown Heat of blowdown water can be recovered by suitable means to avoid the loss of heat energy. Water at high pressure is drained to continuous blowdown (CBD) tank. At CBD tank, its pressure is dropped and flash steam is produced. The level of CBD tank is maintained to get the flash steam continuously. This flash steam can be used at the deaerator for feedwater heating. From CBD tank, excess water is drained out. A heat exchanger may be placed at CBD drain to remove heat from this drain water. Minimise Boiler Surface Radiation Energy is lost due to radiation from the boiler. Proper application of insulation at boiler casing, ducts and pipelines can reduce this loss. Normally, insulation is overlooked by most of the engineers. It is observed that some boiler surfaces and valves are not properly insulated. Measuring surface temperature (at the surface of aluminium cladding) can indicate the insulation condition. Surface temperature should be 40°C–50°C above the atmospheric temperature. Damaged or worn out insulation should be changed. Operating Condition Mostly radiation loss of boiler remains the same at all load conditions. So, the boiler is to be operated at boiler maximum continuous rating (BMCR) load always. Part-load operation consumes more energy per unit of the steam generation. So, part load operation is to be avoided. Combustion Air and Feedwater Heating Heating of combustion air increases the combustion efficiency. So, the hot air temperature at air heater is to be monitored regularly. Due to the choking of air heater tube, heat exchange is affected and air temperature reduces. So, the air heater is to be cleaned periodically. Feedwater heating reduces the fuel consumption. The feedwater temperature of LP and HP heaters is to be monitored continuously. Low feedwater temperature at boiler inlet increases the fuel consumption. So, the economiser inlet temperature and heat gain at economiser should be checked regularly. Deposition of fly ash over the economiser tube minimises the heat transfer. So, the external surface of economiser tube is to be maintained clean by soot blowing and periodical external cleaning.

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Optimising Soot Blowing Soot deposition at boiler tube surface reduces heat transfer. Flue gas exhaust temperature increases in this case. Periodical soot blowing can keep the tube surface clean. For effective soot blowing, blowing steam pressure and temperature are to be maintained during soot blowing. Maintaining Design Parameter Operating boiler at design parameter consumes less fuel. Following parameters are to be maintained at design level:

• • • • • • • • • • • •

Combustion air temperature Feedwater temperature Deaerator pressure Furnace draft Boiler exhaust flue gas temperature Coal mill outlet temperature Fuel size Fluidising bed height Furnace oil temperature Outlet steam temperature and pressure Oxygen in flue gas Loss of ignition (LOI) or unburnt carbon is ash

Any deviation in these parameters affects the fuel consumption. So, proper care of these parameters can save energy in a boiler. Fuel Preparation and Handling Proper coal size in case of coal-fired boiler, improves the combustion. Sieve analysis of coal coming out of crusher is to be done regularly and crusher gap is to be adjusted. Oversize coal is responsible for unbent loss in the bottom ash in case of grate-fired, AFBC and CFBC boilers. In case of pulverised boiler, coal fineness of 75% through 200 mesh and 99.5% through 50 mesh are to be maintained for effective burning. Fuel oil temperature and proper atomisation improve the combustion in an oil-fired boiler. So, an exact fuel condition, as per the design, is to be maintained in the boiler for the optimisation of burning condition and save fuel. Heat Recovery from Ash In AFBC and CFBC boiler, fluidising bed height is maintained by draining bed. As the bed is at higher temperature, so loss of energy takes place. Suitable arrangement can be made to recover this heat by heating the combustion air or feedwater. Proper Deaeration of Boiler Feedwater Deaerator is the most commonly used equipment to remove dissolved oxygen and any gases from the feedwater. Air present in steam reduces the efficiency of heat transfer. Deaerator



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parameters are to be maintained properly for effective deaeration. Periodical checking and cleaning of deaerator spray nozzles improve the deaerator efficiency. Deaerator vent is to be optimised to minimise the energy loss without affecting venting of dissolved gases.

23.3  ENERGY CONSERVATION IN BOILER AUXILIARY EQUIPMENTS Boiler Feed Pump A boiler feed pump supplies feedwater into the boiler. Three-element level controller is used to control the level of a boiler drum. In this case, feed control valve regulates the feedwater flow as per the requirement. Due to throttling operation of control valve, energy is lost. To avoid this loss, VFD may be installed at the boiler feed pump and three-element controller may be used to vary the feed pump speed as per the requirement, keeping the control valve fully open. Sometimes, defective automatic recirculation valve (ARC) causes energy loss. It is to be ensured that water is not flowing back to the deareator through ARC when there is a sufficient flow to the boiler. Choking of suction filter can consume more power. So, this filter is to be cleaned regularly. ID, FD, PA and SA Fans Various fans are used in a boiler to supply air and evacuate flue gas. These fans are connected to the boiler through ducts and isolating damper or valves. The flow control by adjusting these dampers or valves causes energy loss. VVF drive may be used in these fans to reduce the energy loss. Flow variation can be done by adjusting the speed of these fans. For isolation purpose, dampers, flaps or butterfly valves are provided at the duct. These dampers or valves always remain in the air/gas path and cause energy loss. These dampers or valves may be replaced with fully withdrawn type guillotine damper. Pressure drop in a circular duct is less as compared to the rectangle duct. Whereever possible, circular duct may be used. Unnecessary bends in duct may be avoided. Coal Mill Loading of excess ball in a ball mill consumes more power. So, an exact quantity of ball is to be loaded to get the required fineness of coal. More coal fineness increases the amount of incombustible materials in the fly ash. The mill outlet temperature is to be maintained for easy burning.

23.4  ENERGY CONSERVATION IN STEAM TURBINE Maintain Design Parameter Operating turbine at design parameter makes the steam turbine efficient. Steam consumption in a turbine increases if the steam pressure, temperature and exhaust pressure reduce. So, this is to be kept in mind to get the required efficiency of turbine.

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Use Extraction As discussed earlier, the efficiency of Rankine cycle increases by feedwater heating or regenerative cycle. The extraction steam from steam turbine is used for this. For getting a better efficiency, all the extractions are to be used and feedwater outlet temperature at all the heaters are to be monitored. Level of the heaters is to be set correctly. Use Flash Steam Flash steam produced at flash tank into which heater emergency drains are connected, is to be used. The condensate produced may be reused. Maintain Vacuum The condenser vacuum plays a major role in the energy saving of steam turbine. Steam consumption increases if the vacuum reduces. Air ingress into the condenser, scaling of condenser tube, insufficient flow of cooling water, high inlet temperature of cooling water, etc. are some of the reasons for low vacuum in a condenser. These points are to be monitored regularly to minimise the steam consumption in steam turbine. Insulation of Steam Turbine The outer surface of a turbine is to be insulated properly to reduce the radiation loss. Most of the time, turbine insulation is neglected. Application of proper insulation by skilled professionals can reduce the radiation loss. Operating Condition Steam turbine operates with highest efficiency in full load condition. Part-load operation consumes more energy input. As far as possible, a turbine is to be loaded fully to get better efficiency. Subcooling of Condensate The exhaust steam of steam turbine is condensed in the condenser with the help of cooling water. This condensate is again used in a boiler. Around 95% of the condensate is reused. If the cooling water flow is more, then the condensate temperature reduces. This is called subcooling. Proper Maintenance Steam is supposed to flow through the fixed and moving blade sets. Interstage sealing is provided to restrict the steam bypass from the blade stages. If this sealing is damaged or clearance increases, then the steam leakage increases and the steam bypasses blade stages without doing any work. This condition is detected by monitoring the turbine exhaust temperature. The exhaust temperature increases when the interstage seal clearance increases. Leakage of steam from turbine gland, ESV, etc. contribute is energy waste. These leakages are to be arrested. Deposition of silica on turbine blades and nozzles increases pressure drop and hence, the energy loss too. Turbine internal is to be cleaned at regular interval to remove this scale. Passing of casing drain valve increases the energy loss. Casing drain valves are to be checked regularly. Steam traps should be in operation.

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23.5 ENERGY CONSERVATION IN STEAM TURBINE AUXILIARY EQUIPMENTS Condenser Air ingress can take place into the condenser through flange joints, valve steam seals, rupture disks, condensate pumps, etc. This air affects heat transfer, increases back pressure and reduces vacuum. Small air ingress can consume a considerable amount of energy. Nowadays, online helium leak test method is available to detect any air leakage points as well as to arrest them. During operation, sludge or scale can accumulate on the condenser tubes. This sludge or scale affects the heat transfer. So, the vacuum of condenser reduces and the steam consumption increases. Various methods are available to clean the condenser tube surface. Mechanical methods like high pressure hydrojet, brush, spring loaded cleaner bullet, etc. are used to clean the tube offline. Closed loop acid cleaning method is also adopted to clean the tube periodically. Condensate Extraction Pump (CEP) Condensate extraction pump is used to remove the condensate from the condenser hotwell. The flow of condensate to deaerator is adjusted by the control valve depending upon the hotwell level. Throttling action of this control valve increases the energy loss. To avoid this loss, VFD may be installed for CEP. According to the level of hotwell, the speed of pump may be adjusted. Control valve always remains in open condition in this case. Lube Oil Pump Oil pump (AOP and MOP) is used to supply the oil requirement of a steam turbine. Some part of oil is used for the lubrication of turbine bearing (lube oil) and remaining part is used for controlling and governing (control oil). Control oil pressure is more than the lube oil pressure. Mostly, a single oil pump of higher delivery head is used to match control oil pressure. Lube oil is obtained by reducing the oil pressure. This arrangement consumes more power. Two independent pumps may be used to supply low pressure lube oil and high pressure control oil separately. This arrangement reduces the energy consumption. Cooling Water System Most of the time, much attention is not given on the cooling water system and it operates at lower efficiency. Leakages in recirculation pumps and pipeline are noticed. Cooling tower is not operated as per its design parameter. Following actions may be taken to increase the efficiency of a cooling tower:

• Hot water distribution nozzles are to be cleaned regularly and damaged nozzles are to be replaced for better spray of water. • Fills or splash bars are to be cleaned properly to avoid any choking of water flow. • Aluminium or fabricated fan blades are to be replaced by high efficient moulded FRP blades with aerofoil design. • Proper water treatment programme is to be adopted to avoid the growth of algae and scale formation. Algae growth and scale restrict the flow path and make the system inefficient.

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• Side stream filter may be used continuously to remove the suspended sludge from water. Cell basin is to be cleaned periodically to remove the sludge. • COC of water is to be maintained. • VFD may be installed at coding tower fan to adjust the fan speed as per the requirement. Like this, VFD may be installed for recirculating pump to adjust the flow of cooling water as per the load on steam turbine. • Isolate cooling water in standby coolers.

23.6 ENERGY CONSERVATION IN OTHER AUXILIARY SYSTEMS OF A POWER PLANT Coal Handling Plant A considerable amount of auxiliary power is required at coal handling plant for handling, sizing and pollution control. Following methods may be adopted to reduce the power consumption at coal handling plants:



• Idle running of coal handling plant is to be minimised. System should be stopped when the plant is not in operation. • Coal is to be screened before feeding to the crusher. The required size coal can be segregated and only oversize coal is fed to the crusher. By doing this, crusher size and power consumption decreases drastically. • Sieve analysis of coal coming out from the crusher is to be done and accordingly, the crusher gap is to be adjusted regularly. If oversize coal is more, then it requires recycling, if undersize coal is more, it consumes more power. In both cases, power consumption is more. Optimum setting is to be adjusted for lowest power consumption. • Coal size fineness at pulveriser inlet and outlet is to be monitored. Larger size coal is taken as input and then, it is made fine, consuming more mill power. Mill reject should be minimum. • Mill inlet/outlet air temperature and primary air to fuel ratio are to be maintained properly. • Coal feeding is to be done at rated capacity. Partial loading consumes more power. • Using washing coal with around 35% ash can reduce the coal handling cost and increase the boiler efficiency.

Ash Handling Plant Removal of ash is a continuous process in any boiler. Some energy saving methods may be adopted to reduce the energy consumption at ash handling plants. Some of the points are discussed below.

• • • • •

Loss of ignition (LOI) in ash should be minimum. Dry bottom ash system consumes lesser power than the hydraulic bottom ash system. Use high efficient controller for ESP fields and keep the internal clean. There should not be air ingress into the ESP due to casing leakage. Space heaters to be made off if not required.

Scope of Energy Conservation in Thermal Power Plants 





533

• Purging timing of bag house is to be decided on the basis of actual condition of the bag, not on the fixed timer. • Dense phase system is to be operated in vessel level mode, not in timer mode to reduce the compressed air requirement. The number of bends in conveying pipeline should be reduced as far as possible. • Use separate air compressors for different air pressure requirements.

Pipeline High pressure hot fluid (like steam and feedwater) flows in the pipeline. Proper pipeline design can reduce the loss of energy. Following points are to be monitored for energy conservation:

• Undersized pipeline, bends and fittings are responsible for pressure drop in the pipeline. Adequate size of pipe with lesser bends and fittings is to be used to minimise the pressure drop and energy loss. • Poor insulation in pipeline increases the energy loss. The condition of pipeline insulation is to be checked regularly. Surface temperature is to be measured and if found more, reinsulation is to be made. • Most of the times insulation is removed from flanges, valves and other fittings during maintenance and left naked. Insulation should be applied in these areas after maintenance. • Condensate formed in steam pipeline is removed through traps. Traps should be in functional condition. Faulty (passing) trap is responsible for the loss of steam. Trap checking schedule is to be followed to find any defective trap. • Any pipeline which is not in use is to be isolated. • Steam leaks commonly develop around the valve stems and pipe flanges. Even a small leak causes a significant loss of energy during a year. So, leakages in the pipeline are to be arrested immediately.

Pump Different pumps are used in a thermal power plant. Most of the time, it is found that pumps are overdesigned and operates at lowest efficiency. By increasing the efficiency of pumps and modifying the pump as per the requirement, a lot of energy can be saved. To meet the operating conditions, overdesigned pumps may be modified by the following methods:

• Reducing size of impeller diameter(trimming) • Installing VFD • Stage blinding in case of multistaging pump. As per the affinity law



• At constant impeller diameter,

q1 Ê n1 ˆ = q2 ÁË n2 ˜¯



Flow



p1 Ê n1 ˆ = Head or pressure p2 ÁË n2 ˜¯

2

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Power consumption

• At constant speed

kW1 Ê n1 ˆ = kW2 ÁË n2 ˜¯



Flow



Head or pressure



Power

3

q1 d1 = q2 d 2 p1 Ê d1 ˆ = p2 ÁË d 2 ˜¯

kW1 Ê d1 ˆ = kW2 ÁË d 2 ˜¯

2

3

It is clear that the pump power consumption is proportional to the cube of impeller diameter or speed of the pump. Pump efficiency calculation:  The efficiency of a running pump can be calculated easily by the following method. To measure the efficiency, following parameters are required:

• • • • •



Flow rate of the pump in cubic metre per second (can be measured by any flow meter) Power consumption by the pump (electrical power can be measured by any energy meter) Density of pumping fluid (1000 kg/m3 for water) Acceleration due to gravity (can be taken as 9.81 m/s2) Head developed by the pump in metres (discharge head – Suction head can be measured by any pressure gauge) Efficiency of the pump =

Hydraulic power Ph (kW) Power input to pump shaft ¥ 100

Hydraulic power Ph (kw) can be calculated as follows.



Flow rate (m3 /s) ¥ Density of the fluid (kg/m3 ) ¥ Acceleration due to gravity (m/s 2 ) ¥ Total head (m) Hydraulic power Ph (kw) = 1000

Power input to pump shaft can be calculated as follows: Power input to pump shaft = Motor input power (measured by any energy meter)  Motor efficiency EXAMPLE 23.1  During operation, following readings are measured from a cooling water pump of a thermal power plant: Pump flow Suction head Discharge head Total head Measured motor power

1260 m3/hr (0.35 m3/s) +1.25 m (0.125 kg/cm2) 50 m (5 kg/cm2) 50 – 1.25 = 48.75 265 kW

Scope of Energy Conservation in Thermal Power Plants 



535

Motor efficiency 90% Power input to pump shaft 265  0.9 = 238.5 kW Calculate the efficiency of pump. Solution  As per the formula, 0.35 ¥ 48.75 ¥ 1000 ¥ 9.81 = 167.38 kW 1000 Hydraulic power Efficiency = Power input to pump shaft ¥ 100 167.38 ¥ 100 = 70% = 238.5

Hydraulic power =

To reduce the energy consumption of a pump, following steps may be taken:

• Proper maintenance of the pump is to be done to avoid internal recirculation. Efficiency of worn out pumps can drop drastically. • Shaft alignment, coupling of motor and pump is to be properly done to minimise transmission loss. • Pump should not be operated at throttled discharge condition. In this case, correct size pump or VFD may be installed. • Any leakage of fluid is to be arrested. • There should not be excessive pressure drop. Select a suitable pipeline size and fittings. • Low efficiency pump may be replaced with a high efficiency pump.

Fan Different types of fans are used in thermal power plants. Some fans are overdesigned and found running with throttled damper condition hence consume more power. VFD may be installed in this case to reduce the power consumption. Following energy efficient methods are adopted for speed control of fans.

• VFD drive • Changing pulley size • Scoop tube hydraulic coupling

Fan efficiency calculation:  The efficiency of a running fan can be calculated easily. To measure the efficiency, following parameters are required:

• • • • •

Velocity of air flow in metre per second (measured by pitot tube) Cross section area of the duct in square metre Total static pressure in millimetre of water column Motor power consumption (electrical power can be measured by any energy meter) Density of gas in kilogramme per cubic metre Flow volume (m3 /s) ¥ Total pressure (mmwc) Efficiency of the fan = 102 ¥ Power input to fan shaft (kW)

536 

Practical Boiler Operation Engineering and Power Plant

Flow volume can be calculated as follows: Flow volume = Area of duct (m2)  Measured velocity (m/s)



Power at motor shaft can be calculated as follows: Power at motor shaft = Motor input power (measured by any energy meter)  Motor efficiency Some energy is lost during transmission from motor shaft to fan shaft. Transmission efficiency is to be multiplied by motor shaft to get the fan shaft power. EXAMPLE 23.2  During operation, following readings are measured from a cooling water pump of a thermal power plant. Velocity measured 8 m/s Area of the duct 4 m2 (Flow volume = 8  4 = 32 m3/s) Total static pressure 490 mmwc Measured motor power 250 kW Motor efficiency 90% Transmission efficiency 95% (Power input to fan shaft = 250  0.9  0.95 = 213.75 kW) Calculate the efficiency of the pump. Flow volume (m3 /s) ¥ Total pressure (mmwc) 102 ¥ Power input to fan shaft (kW) 32 ¥ 490 = = 72% 102 ¥ 213.75 Solution

Efficiency of fan =

To reduce the energy consumption of a fan, following steps may be taken:

• Proper maintenance of the fan is to be done to avoid internal recirculation (minimise cone clearance). • Minimise inlet and outlet flow restrictions. Clean screen, filter, fan blade, etc. Use well rounded cone at suction side. • Use low slip flat belt in place of V-belts and check tension regularly. • The fan should not be operated in throttled damper condition. In this case, correct size fan or VFD may be installed. Reducing pulley size can also solve the purpose. • Any leakage in the duct is to be arrested. • There should not be excessive pressure drop. A suitable duct design helps in this case. A circular duct reduces the pressure drop. • Butterfly valve in the duct increases the pressure drop. Guillotine damper may be used in this case. • Low efficiency fan may be replaced with high efficiency fan.

Compressor A lot of energy is required to get the compressed air for use in power plants. Saving in compressed air consumption and applying energy saving practices help in saving a significant amount of energy. Following methods may be utilised:

Scope of Energy Conservation in Thermal Power Plants 





537

• Different compressors are to be used for different pressure requirements. Compressing air at higher pressure and then, reducing the pressure consumes more power. • Any leakage in the compressed air line is to be arrested immediately. • Keep the suction filter clean to minimise the pressure drop across filter. • Power consumption of the compressor reduces by reducing the suction air temperature. • Compressor should run in loading condition most of the time. Loading and unloading pressure should be set accordingly. Unloading operation of compressor consumes unnecessary power. • Use auto moisture traps in the air receiver. • If possible, reduce discharge pressure to match the lowest acceptable limit at use point. • High energy efficient screw compressor is to be used in place of low efficient reciprocating compressor. • Stop the use of compressed air for inappropriate uses like equipment cooling, cleaning, etc.

EXERCISES

Roughly estimate the efficiency of a thermal power plant. What are the main energy conservation methods in a boiler? How does excess air increase the energy consumption? Why does waterside scaling makes a boiler inefficient and how can it be avoided? How does air ingress affect the efficiency of a boiler? How can the heat from blowdown water be recovered? What should be the boiler casing insulation surface temperature? How does leakage in air heater affect the efficiency of a boiler? How does soot deposition affect the efficiency of a boiler and how can it be controlled? What are the energy conservation methods in a boiler feed pump? Where does more pressure drop occur—across rectangular duct or circular duct? Why is the flow adjustment by adjusting the dampers, flaps or valves inefficient? How does the use of turbine extraction steam contribute in plant efficiency? What is the effect of low condenser vacuum? How does the steam turbine casing insulation affect the turbine efficiency? What is condensate subcooling? What is the effect of turbine interstage fin damage? What is the effect of condenser tube scaling? What are the methods of increasing the efficiency of (i) cooling tower? (ii) pump? (iii) fan? (iv) air compressor? 20. What are the methods to minimise the losses in a pipeline?

1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19.

Plant Calculations or Numericals Question 1:  Steam is generated in a boiler at 110 kg/cm2 and 520 °C. Drum pressure of the boiler is 118 kg/cm2. Calculate

(i) Saturated steam temperature (ii) Degree of superheat (iii) Enthalpy of steam

Answer: (i) From the steam table, saturated temperature corresponding to 118 kg/cm2 (drum pressure) is 322 °C. (ii) Degree of super heat = Superheated steam temperature – Saturated temperature = 520 – 322 = 198 °C. (iii) Enthalpy of the superheated steam as found from steam table corresponding to 110 kg/cm2 and 520 °C is 815.8 kcal/kg.

Question 2:  In a coal sample it is found that ash is 40%, inherent moisture is 3% and total moisture is 13%. Using a suitable empirical formula, calculate UHV and GCV of the coal. Answer:  By using the empirical formula, UHV = 8900 – 138 (Ash% + Inherent moisture%) = 8900 – 138(40 + 3) = 2966 kcal/kg (UHV + 3645 - 75.4 ¥ Total moist%) 1.466 2966 + 3645 - 75.4 ¥ 13 = = 3841 kcal/kg 1.466

GCV =

Question 3:  In a coal sample, it is found that the total moisture (TM) as received basis is 13%. Using a suitable formula, calculate GCV of the dried coal if the GCV of as received coal is 3400 kcal/kg. Answer:  To obtain GCV value of coal after drying, the GCV value as received basis is to be multiplied by [100/(100 – TM%)]. 539

540 

Plant Calculations or Numericals

100 Ê ˆ Ê 100 ˆ GCV of dry coal = 3400 Á = 3400 Á = 3908 kcal/kg ˜ Ë 100 - TM% ¯ Ë 100 - 13 ˜¯

Question 4:  Following parameters are noted from the ultimate analysis of a coal sample: Carbon Sulpher Hydrogen

40% 2% 4%

Calculate the theoretical quantity of air required in kilogrammes. If the boiler is operated at 4% excess oxygen, then calculate the actual air quantity in kilogrammes. Answer:  Quantity of theoretical air required (by weight) per kilogramme of fuel is given by ÈÊ 8 ˘ ˆ Ê8 ˆ 4.35 Í Á C + 8H 2 + S˜ - O 2 ˙ kg = 4.35 Á ¥ 0.4 + 8 ¥ 0.04 + 0.02˜ Ë ¯ Ë ¯ 3 Î 3 ˚ = 4.35(1.067 + 0.32 + 0.02)

= 4.35  1.407 = 6.12 kg

Excess air percentage =

Oxygen percentage in flue gas ¥ 100 21 - Oxygen percentage

Boiler is operated at 4% excess oxygen. 4 ¥ 100 = 23.5%. 21 - 4 Excess air% ˆ Ê Actual air quantity = Theoretical air Á1 + ˜¯ Ë 100 = 6.12  1.235 = 7.35 kg per kg of fuel So,

Excess air percentage =

Question 5:  TDS of 50 TPH boiler water is required to be maintained at 30 ppm. TDS of make-up feedwater is 2 ppm. Calculate percentage of blowdown required to maintain this TDS level. Calculate the quantity of blowdown water in TPH. Answer:  If

TDSfw = TDS (ppm) in feedwater TDSmax = Maximum permissible TDS of boiler water TDS fw

¥ 100 TDSmax - TDS fw 2 = ¥ 100 = 7.14% 30 - 2 Blowdown quantity (without considering leakages) = Evaporation quantity  Blowdown percentage = 50  0.0714 = 3.6 TPH. Then,

percentage of blowdown =

Question 6:  In a boiler, the exhaust flue gas temperature is 145 °C and that of ambient air is 35 °C. Calculate the energy loss in dry exhaust gas per kilogramme, if the specific heat of flue gas is 0.23 kcal/kg.

Plant Calculations or Numericals 



541

Answer:  Energy loss = Mass of flue gas  Cp (Tf – Ta) = 1  0.23(145 – 35) = 25.3 kcal/kg of flue gas Question 7:  Calculate the size of pipe required to transfer 100 t/hr of steam at 40 kg/ cm2 and 420 °C. Velocity in the pipeline is to be maintained at 30 m/sec. Answer:  Steam flow = 100  1000 kg/hr = 27.78 kg/s From the steam table, specific volume of steam at 40 kg/cm2 and 420 °C is found 0.078 m3/kg. So, the volume of steam flow per second = 27.78  0.078 = 2.17 m3/s So, or

Flow = Velocity  Cross section area of pipe p D2 4 4 D2 = 2.17 ¥ = 0.092 m2 30p

2.17 = 30 ¥

D = 0.092 = 0.30 m = 300 mm

So, 300 mm pipe may be used. Question 8:  In a 200 NB pipeline, the steam flows at 20 kg/cm2 and 380 °C. Its flow velocity is 20 m/s. Calculate the steam flow in m3/hr and t/hr. Answer:  Diameter D of the pipe is 200 mm = 0.2 m Velocity is given as 20 m/s Volumetric flow = Area of pipe  Velocity p D2 =  20 = 0.628 m3/s = 2261 m3/hr 4 From the steam table, specific volume of steam at 20 kg/cm2 and 380 °C = 0.149 m3/kg 2261 Weight of steam flow per hour = = 15174 kg/hr = 15.17 t/hr 0.149

Question 9:  Calculate the pressure drop in a 100 NB, 150 m long horizontal steam pipeline. Velocity of steam in the pipeline is 3 m/s. Consider the friction factor as 0.005. Answer:  Pressure drop (m) in horizontal pipeline is calculated by

=

4 fLU 2 2 gD

where, f is the friction factor, L is the Length of pipe (m), U is the flow velocity (m/s), g is the gravitational constant (9.81 m/s2) and D is the diameter of pipe (m). Putting all these values, we get 4 ¥ 0.005 ¥ 150 ¥ 32 2 ¥ 9.81 ¥ 0.1 = 13.76 m = 1.37 kg/cm2

Pressure drop =

542 

Plant Calculations or Numericals

Question 10:  Calculate the efficiency of a 200 TPH, 100 kg/cm2, 520 °C boiler if 1050  t coal with GCV of 3700 kcal/kg is consumed per day. Feedwater inlet temperature is 135 °C and make-up water is negligible. Answer:  From the steam table, heat of steam at 100 kg/cm2 and 520 °C = 821 kcal/kg Heat in feedwater at 135 °C = 135 kcal/kg Coal consumption per hour = 1050/24 = 43.75 t/hr = 43750 kg/hr Efficiency of boiler = Steam generation (kg)[Total heat in steam (kcal/kg) - Total heat in feedwater (kcal/kg)] ¥ 100 Coal consumption (kg) ¥ GCV of coal (kcal/kg) Taking all the data on per hour basis, 200 ¥ 1000 (821 - 135) ¥ 100 43750 ¥ 3750 = 84.7%

Boiler efficiency =

Question 11:  The efficiency of a 100 TPH, 80 kg/cm2, 520 °C boiler is 82%. Calculate the quantity of coal required per day if the feedwater inlet temperature is 120 °C, makeup water is negligible and GCV of coal used is 3600 kcal/kg. Calculate the evaporation ratio of the boiler. Answer:  From the steam table, heat of steam at 80 kg/cm2 and 520 °C = 823.6 kcal/kg Heat in feedwater at 120°C = 120 kcal/kg Efficiency of boiler = Steam generation (kg)[Total heat in steam (kcal/kg) - Total heat in feedwater (kcal/kg)] ¥ 100 Coal consumption (kg) ¥ GCV of coal (kcal/kg) Taking all the data on per hour basis, or,

100 ¥ 1000(823.6 - 120) ¥ 100 = 82 Coal consumption (kg/hr) ¥ 3600 100 ¥ 1000(823.6 - 120) ¥ 100 Coal consumption (kg/Hr) = 0.82 ¥ 3600

Coal consumption per hour =

= 23835 kg/hr = 23.83 t/hr Coal consumption per day = 23.8  24 = 572 t per day Steam generation per hour Evaporation ratio = Coal consumption per hour 100 = 23.83 = 4.19 kg of steam per kilogramme of coal Question 12:  At a particular load condition, 58 t/hr of steam at 40 kg/cm2 (absolute) and 420 °C, enters a condensing steam turbine. The exhaust pressure of turbine is

Plant Calculations or Numericals 



543

–0.92 kg/cm2 (gauge) and the dryness fraction of exhaust steam is 90%. Calculate the quantity of heat used by turbine and its percentage. Answer:  From the steam table, heat of turbine inlet steam, i.e. at 40 kg/cm2 and 420 °C = 778.5 kcal/kg Total heat in the steam = Steam flow (kg)  Heat in per killogramme steam = 58000  778.5 = 45153000 kcal Absolute pressure at condenser = Atomospheric pressure – Gauge pressure = 1.03 – 0.92 = 0.11 kg/cm2 From steam table, the heat of turbine exhaust steam, i.e., at 0.11 kg/cm2 with 90% dryness fraction = 47.3 + 0.9  617.8 = 603.32 kcal/kg Total heat in the exhaust steam = Steam flow (kg)  Heat in per killogramme steam = 58000  603.32 = 34992560 kcal Quantity of heat used by turbine = Total heat supplied – Total heat exhausted = 45153000 – 34992560 = 10160440 kcal Heat used by turbine ¥ 100 Percentage of heat used = Heat input 10160440 ¥ 100 = 22.5% = 45153000 Question 13:  Calculate the cooling water quantity required for a surface condenser in the following case: Quantity of steam flow Condenser vacuum Dryness fraction of steam Condensate temperature Cooling water inlet temperature Cooling water out let temperature

50 t/hr 0.92 kg/cm2 (gauge) 85% 46 °C 30 °C 40 °C

Answer:  The cooling water required is calculated by

Ww =

Ws ( H - h1 ) T2 - T1

where, Ww is the cooling water flow in condenser (kg), Ws is the steam flow to condenser (kg), H is the total heat of steam flowing to condenser (kcal/kg), h1 is the heat in condensate (kcal/kg), T1 is the cooling water inlet temperature (°C) and T2 is the cooling water outlet temperature (°C). From steam table, heat of exhaust steam H at –0.92 kg/cm2 (gauge) or 0.11 kg/cm2 (absolute) with 85% dryness fraction = 47.3 + 0.85  617.8 = 572.43 kcal/kg

Heat in condensate at 46 °C = 46 kcal/kg

50000(572.43 - 46) 40 - 30 = 2632150 kg/hr = 2632 t/hr

Cooling water flow in condenser (kg) =

544 

Plant Calculations or Numericals

Question 14:  A 1500 rpm, 40 MW, 50 Hz, generator is connected to 8000 rpm steam turbine through a speed reducing gearbox. Calculate the speed of turbine when the frequency of the generator is 51 Hz. Answer:  Number of poles of generator = 120  50/1500 = 4 poles At 51 Hz, speed of the generator = 120  51/4 = 1530 rpm 8000 Speed ratio of gearbox = = 5.3333 1500 So, speed of turbine when the generator is running at 1530 rpm = 1530  5.3333 = 8160 rpm. Question 15:  The efficiency of a 50 MW thermal power plant is 32% (GCV basis). Calculate the quantity of coal required per month if the GCV of coal used is 3500 kcal/kg. The plant runs for 30 days on that month. Answer:  The efficiency of plant is 32%. So, to generate 1 kWh power, heat energy requirement =

860 = 2687.5 kcal 0.32

In one hour, plant will generate 50  1000 kWh. 860 ¥ 50 ¥ 1000 Heat energy requirement in one hour = 0.32 = 134375000 kcal. Given that GCV of coal is 3500 kcal/kg. So coal requirement per hour

134375000 = 38393 kg/hr = 38.39 t/hr 3500 Coal requirement per month (30 days) = 38.39  24  30 = 27641 t



=

Question 16:  How much heat will be required to increase 50 t of feedwater at 120°C to 240 °C. Given that the specific heat of water is 1. Answer:  Heat required = Mass of feed water (kg)  Specific heat of feedwater (Final heat on water per killogramme – Initial heat on water per kilogramme) = 50  1000  1(240 – 120) = 6000000 kcal/hr Question 17:  The online oxygen analyser of a boiler is showing 4.5% oxygen. Calculate the excess air percentage at which the boiler is operating. Answer: 

Excess air percentage =

Percentage of oxygen ¥ 100 21 - Percentage of oxygen

4.5 ¥ 100 21 - 4.5 = 27.27% =

Question 18:  A pump consumes 15 kW at 1480 rpm to deliver 20 m3/hr water at 4 kg/cm2. Calculate the power required by the same pump to run at 1200 rpm and what will be the flow and pressure obtained by the pump?

Plant Calculations or Numericals 



545

Answer:  As per affinity law of pump

q1 n1 p1 Ê n1 ˆ = , = q2 n2 p2 ÁË n2 ˜¯ Power required at 1200 rpm =

=

2

kW1 Ê n1 ˆ and = kW2 ÁË n2 ˜¯

3

15 (1480/1200)3 15 = 8.02 kW 1.87

20 (1480/1200) 15 = = 12.16 m3/hr 1.23 4 Pressure at 1200 rpm = (1480/1200) 2 4 = = 2.66 kg/cm2 1.5

Flow at 1200 rpm =

Question 19:  The safety valve of a boiler is set at 42 kg/cm2. During testing, it is found that the valve lifts at 45 kg/cm2 and reset at 39.5 kg/cm2. Calculate

(i) Overpressure percentage (ii) Blowdown Percentage

Answer: (i) Overpressure = Lifting pressure – Set pressure = 45 – 42 = 3 kg/cm2 Overpressure ¥ 100 Over pressure percentage = Set pressure 3 ¥ 100 = 42 = 7.14% Set pressure - Reset pressure ¥ 100 (ii) Blowdown percentage = Set pressure 42 - 39.5 ¥ 100 = 42 = 5.95% Question 20:  Following readings are noted from a power plant Cooling tower: Cooling water flow Cooling water inlet temperature Cooling water outlet temperature Wet bulb temperature

1500 m3/hr 38 °C 30 °C 27 °C

546 

Plant Calculations or Numericals

Dry bulb temperature TDS of cooling water TDS of make-up water Evaporation loss Windage loss

45 °C 1500 ppm 250 ppm 2% negligible

Calculate (i) Approach (ii) Range (iii) Heat load of the cooling tower (iv) COC (v) Blowdown (vi) Make-up water required Answer:  (i) Approach = Outlet cold water temperature – Wet bulb temperature = 30 – 27 = 3 °C (ii) Range = Inlet hot water temperature – Outlet cold water temperature = 38 – 30 = 8 °C (iii) Heat load = Flow rate (kg)  Specific heat (Inlet temperature – Outlet temperature) = 1500  1000  1(38 – 30) = 12000000 kcal/hr. TDS of cooling water (iv) COC = = 1500/250 = 6 TDS of make-up water (v) As windage loss is negligible, so

Blowdown percentage =

Evaporation percentage 2 = = 0.4% COC - 1 6 -1

1500 ¥ 0.4 3 m /hr = 6 m3/hr 100 (vi) Make-up water required = Evaporation loss + Blowdown = 1500  0.02 + 6 = 30 + 6 = 36 m3/hr

Blowdown quantity =

Question 21:  HCV of a liquid fuel is 9500 kcal/kg. Hydrogen percentage in the fuel is 10%. Calculate LCV of the fuel. Answer:  LCV = HCV – (9H2  586) kcal/kg = 9500 – (9  0.1  586) = 9500 – 527 = 8973 kcal/kg Question 22:  In a blast furnace gas-fired boiler, 70000 nm3/hr blast furnace gas is used. Calculate the gas consumption in m3/hr if the gas temperature is 200 °C and pressure is 2 kg/cm2 (absolute). Answer:  The gas flow (nm3/hr) is expressed standard temperature and pressure, i.e., at 273 K and 1.03 kg/cm2. To convert it into m3/hr the following condition is used:

Plant Calculations or Numericals 



547

P2 ¥ V2 P1 ¥ V1 = T2 T1



2 ¥ V2 1.03 ¥ 70000 = 273 273 + 200



1.03 ¥ 70000 ¥ 473 273 ¥ 2 = 62460 m3/hr V2 =

or

Question 23:  Following readings are noted from a 55 MW coal-fired thermal power plant. Steam generation in the boiler Steam pressure Steam temperature Boiler feed pump load Coal consumption GCV of coal used Feedwater temperature at boiler inlet Plant auxiliary load Units generated in the month of April 2011

210 TPH 100 kg/cm2 530 °C 1.8 MW 1200 t per day 3500 kcal/kg 140 °C 4 MW 38304000 kWh

If steam and feedwater loss in the system are negligible, calculate (i) Gross turbine heat rate (ii) Net turbine heat rate (iii) Boiler efficiency (iv) Gross plant heat rate or station heat rate (v) Net plant heat rate (vi) Evaporation ratio (vii) Specific steam consumption (viii) Specific coal consumption (ix) PLF in the month of April 2011 (x) Gross plant efficiency Answer:  (i) From the steam table, total heat of steam at 100 kg/cm2 and 520 °C is 818.4 kcal/kg. Gross turbine heat rate (considering generation for one hour) Steam flow to turbine (kg) (Total heat of steam - Total heat of feedwater at boiler inlet) = Kilowatt output 210 ¥ 1000(818.4 - 140) = = 2590 kcal/kWh 55 ¥ 1000 (ii) Net Turbine heat rate Steam flow to turbine (kg) (Total heat of steam - Total heat of feedwater at boiler inlet) = Kilowatt hour generated - Kilowatt hour consumed by feed pump

=

210 ¥ 1000(818.4 - 140) = 2678 kcal/kWh 55 ¥ 1000 - 1.8 ¥ 1000

548 

Plant Calculations or Numericals



(iii) Coal consumption per hour = 1200/24 = 50 t Boiler efficiency = Steam generation (kg) (Total heat of steam - Total heat of feedwater at boiler inlet) ¥ 100 Coal consumption per hour (kg) ¥ GCV of coal 210 ¥ 1000 (818.4 - 140) ¥ 100 = 81% = 50 ¥ 1000 ¥ 3500 Coal consumption (kg/hr) ¥ GCV (iv) Gross plant heat rate = Kilowatt hour generation per hour

=

(v) Net plant heat rate =

Coal consumption (kg/hr) ¥ GCV Kilowatt hour generation per hour - Kilowatt hour consumed by plant auxiliary

=

50 ¥ 1000 ¥ 3500 = 3431 kcal/kg (55 ¥ 1000) - (4 ¥ 1000)

(vi) Evaporation ratio =



50 ¥ 1000 ¥ 3500 = 3182 kcal/kWh 55 ¥ 1000

=

Steam generation per hour (kg) Coal consumption per hour (kg) 210 ¥ 1000 = 4.2 kg of steam per kilogramme of coal 50 ¥ 1000

(vii) Specific steam consumption =

Steam flow to turbine per hour (kg) Kilowatt hour generated per hour

210 ¥ 1000 = 3.8 kg of steam per kilowatt hour 55 ¥ 1000 Coal consumption per hour (kg) (viii) Specific coal consumption = Kilowatt hour generated per hour

=



(ix) PLF =



=

=

Units generated in the period ¥ 100 Maximum unit that could have been generated during that period 38304000 ¥ 100 = 96.7% 55 ¥ 24 ¥ 30 ¥ 1000

(x) Gross plant efficiency =



50 ¥ 1000 = 0.91 kg of coal per kilowatt hour 55 ¥ 1000

=

Kilowatt hour generated in one hour ¥ 860 ¥ 100 Coal consumption per hour (kg) ¥ GCV 55 ¥ 1000 ¥ 860 ¥ 100 = 27% 50 ¥ 1000 ¥ 3500

Plant Calculations or Numericals 



549

Question 24:  A boiler generates 200 TPH steam at 100 kg/cm2 pressure and 500 °C temperature. If the feedwater inlet temperature is 135 °C and 52 t of coal is consumed per hour, then calculate

(i) Equivalent evaporation from and at 100 °C (ii) Equivalent evaporation from and at 100 °C per ton of coal. (iii) Boiler horsepower

Answer: (i) Equivalent evaporation is the quantity of water evaporated from and at 100 °C to produce dry saturated steam at 100 °C by absorbing the same amount of heat equal to the actual operating condition. This is given by M act ( H - H fw ) Meq = 539 where, Meq is the Equivalent evaporation from and at 100 °C, Mact is the actual steam generation in the boiler, H is the heat of steam and Hfw is the heat of feedwater. Latent heat of dry saturated steam at 100°C is 539 kcal/kg Heat in steam at 100 kg/cm2 pressure and 500 °C temperature is 809 kcal/kg.



(ii)



200(809 - 135) = 250 TPH 539 To find equivalent evaporation from and at 100 °C per ton of coal, Mact is taken as actual steam generation per unit quantity of fuel. 200 Mact in this case = = 3.85 t per ton of coal 52 3.85(809 - 135) So,      Meq = = 4.814 t of steam per ton of coal 539 One boiler horsepower is the capacity to evaporate 15.653 kg of feedwater per hour at 100°C into dry saturated steam at 100 °C. Equivalent evaporation from and at 100 ∞C(kg/hr) or, Boiler horsepower = 15.663 250 ¥ 1000 Here, boiler horsepower = = 15971 hp 15.663 Meq =



(iii)



Appendix I

UNIT CONVERSION Length

1 cm 12 in 1 in 1 ft 3 ft 1760 ft 1 yard 1 m 1 km 1 km 1 µ or µm 1 thou or mil 1 thou or mil 1 thou or mil 1 mm

Area 1 in2 1 m2 1 m2

Mass 1 kg 1 mt 1 t

Flow

1 m3/hr 1 L/hr 1 m3/hr 1 ft3/hr

Power and Energy 1 hp

0.3937 in 1 ft 2.54 cm 0.3048 m 1 yd 1 mil 0.9144 m 3.28033 ft 3281 ft 0.6214 mil 10–6 m 0.001 in 0.0254 mm 25.4 µ or µm 39.37 thou 6.4516 cm2 1550.003 in2 10.76391 ft2 2.204 lb 1000 kg 907.1847 kg 35.314 ft3/hr 1000 cm3/hr 264.17 gal/hr 7.48 gal/hr 0.754 kW

1 W 3.415 BTU/hr 1 kWh 860.4 kcal 1 BTU 0.252 kcal 1 kJ 0.2388 kcal 1 BTU/s 1.055 kW 1 kWh 3412.14 BTU 1 BTU/lb 0.556 kcal/kg 1 boiler hp 8450 kcal/hr (1 boiler hp is the evaporation of 15.65 kg of water per hour and at 100 °C.) (3600 kJ = 860 kcal = 1 kWh = 3412.14 BTU)

Pressure 1 ata 1 bar 1 kpsa 1 psi 1 mmHg 1 mmwc

Temperature °C °F

Particle Size 10 mesh 50 mesh 100 mesh 200 mesh 550 mesh 1250 mesh

1.033 kg/cm2 1.019 kg/cm2 0.01 kg/cm2 0.07 kg/cm2 0.0013 kg/cm2 1  10–4 kg/cm2 (°F – 32)5/9 °C  9/5 + 32 2000 µ 297 µ 149 µ 74 µ 25 µ 10 µ

Air Compressor Capacity 1 m3/min 1 CFM 551

35.315 CFM 28.317 LPM

552

*Size < 50 NB **Size > 50 NB

Material

Pipe Fittings Flanges Valves Material Schedule Standard Material Standard Class Material Standard Class Material Standard SpeciSpeciSpeciSpecification fication fication fication ANSI Main Alloy steel ASTM 80 ANSI ASTM 182 ANSI 3000* ASTM ANSI 600* ASTM Steam 335, P11, B36.10 F11, F22* B16.11* 182 F11, B16.5 800** 182 F11*, B16.34 Line P22, P91 ASTM 234 ANSI F22 F22*, WP11, B16.9** ASTM WP22 ** 217 WC6, WC9** ANSI 3000* ASTM ANSI 300 ASTM ASTM 40 ANSI ASTM 105* ANSI Auxiliary Carbon B16.34 A105 B16.5 105* steel 106 Gr B B36.10 ASTM 234 B16.11* Steam WPB ** ANSI ASTM Line B16.9** 216 WCB** Conden- Carbon ASTM 40 ANSI ASTM 105* ANSI 3000* ASTM ANSI 300 ASTM ANSI sate Line steel 106 Gr B B36.10 ASTM 234 B16.11* A105 B16.5 105* B16.34 WPB ** ANSI ASTM B16.9** 216 WCB** Feedwater Carbon ASTM 80 ANSI ASTM 105* ANSI 3000* ASTM ANSI 900 ASTM ANSI Line steel 106 Gr B B36.10 ASTM 234 B16.11* A105 B16.5 105* B16.34 WPB ** ANSI ASTM B16.9** 216 WCB** ANSI ASTM 40, 80 ANSI ASTM 105, ANSI 3000* ASTM ANSI 900 ASTM Cooling Carbon A105 B16.5 105* B16.34 Water steel 106 Gr B36.10 ASTM 234 B16.11 ASTM Line B/IS 3589 WPB 216 Gr. 330 WCB** (spral weld) ANSI Air Line Galvanised IS 1239 Heavy IS 1239 ASTM 105* ANSI 3000* ASTM ANSI 150 ASTM A105 B16.5 105* B16.34 steel/ Part I/ Grade IS 1239 Part B16.9 ASTM Carbon IS 1239 II, **/A234 216 steel Gr. WPB** WCB**

Pipeline

Various Pipelines used at Thermal Power Plant Fastners

800* ASTM 150** 1363/ 1367

800* ASTM 150** 193 B7, ASTM 194 2H

1500* ASTM 900* 193 B7, ASTM 194 2H

800* ASTM 600** 193 B7, ASTM 194 2H

800* ASTM 600** 193 B7, ASTM 194 2H

800* ASTM 600** 193 B7, ASTM 194 2H

Class

Appendix II

Appendix III

SYLLABUS FOR BOE EXAMINATION [As per Notification by Government of India, Ministry of Commerce and Industry under The Boiler Operation Engineer’s Rules, 2011]

Paper 1 (Written)





• To calculate loads, areas, volumes, quantities and weights • To give description of the principal types of steam boilers used on land and to state the purposes and reasons for which different types of boilers are employed; and from the data and formulae supplied, calculate the safe working pressure for any part of a boiler in accordance with the Indian Boiler Regulations • To calculate the direct stress, the torsional stress and the bending stress in round bars and shafts and the bending stress in rectangular bars and levers with given load • To understand the working and management of steam boilers, super heaters and economizers • To understand the use and purpose of various valves, cocks, mountings, fitting and other safety devices • To give a description of and explain the functions of feed pumps, feed injectors, feed regulators, feedwater filters and softeners, feed heaters, air heaters, calorifiers, steam accumulators, forced draught, induced draught and automatic draught control devices • To answer questions on fact relating to combustion, heat and steam and calculate consumption of coal and water and quantity of steam that may be generated from a given heating surface under the various systems of draught in any land boiler and also calculate the overall efficiency of the boiler plant • To explain jet and surface condensation, reheating and the working of steam expansion

Paper 2 (Written)

• To explain the general methods employed in laying foundation for boilers and chimneys and the suitable area and height of chimneys promote efficient combustion

553

554 

Appendix III

• To explain the significance of principal appliances in use for the prevention of smoke and the principle on which they work and give description of the principal mechanical stokers, pulveriser, gas, oil and pulverised fuel systems in use • To understand the need for periodical cleaning, the methods used for prevention of scale or other deposits on heating surfaces and the necessity for maintaining a certain pH value in feedwater • To detect defects in the boilers and state the means and methods of rectifying them • To understand the precautions to be taken for starting a boiler and economizer from cold or from banked fire condition • To understand the procedure to be adopted in putting an economizer out of commission while the boiler is on steam • To explain the methods adopted for the achievement of fuel economy and the use of various instruments used in a boiler house • To know about the materials used in boiler components and piping

Drawing (Written)

• To read and prepare a working sketch and drawing of boilers and boiler mounting or parts thereof

Oral Examination

• To answer questions pertaining to boiler practices and if required to demonstrate in the examination room or in a workshop, his ability to carry out the practical aspects of his duties in a boiler house

Eligibility

• Degree in mechanical or electrical or chemical or power plant or production or instrumentation engineering with two years experience in boiler operation or maintenance • Degree or post graduate diploma from a National Power Training Institute (NPTI) with one year experience in boiler operation or maintenance • Diploma in mechanical or electrical or chemical or power plant or production or instrumentation engineering with five years experience in boiler operation or maintenance

Index

Absolute pressure, 4 Acid cleaning, 167, 421 Acid injection, 61 Activated carbon filter, 54 Ad700 project, 390 Afbc boiler, 90 Air cylinder, 514 Air ingress, 531 Air nozzles, 92 Air to open type control valve, 511 Air vent, 173 Alignment, 475 Alkali boil-out, 422 Alkanity, 69 Aluminum cladding, 198 Anion exchanger, 59 Aspect ratio, 231 Attemperator, 182 Austenitic steel, 268 Automatic recirculation valve (arc), 151 Automatic voltage regulator (avr), 407 Auxiliary oil burners, 88 Auxiliary oil pump (aop), 349 Axial flow fan, 130

Barring device, 324 Basket type strainer, 298 Bearing, 470 Bed material, 93 Bed tubes, 96 Belt sway switch, 119 Bend pulley, 117 Bi-drum boilers, 151 Biomass, 127 Blackout, 379 Boiler feed pump, 150 Boiler maximum continuous rating (bmcr), 83,  527 Boiler waterside, 169 Boiler waterside corrosion, 169 Boiling temperature, 46 Bowl mill, 85 Brayton cycle, 18 Breakdown maintenance, 440 Bucket elevator, 120 Butterfly valve, 292 Butt weld end, 289 Carbon steel, 267 Carnot cycle, 12 Carryover, 170 Castable, 197 Cation exchanger, 59, 60 Central processing unit (cpu), 519 Centrifugal discharge, 121 Centrifugal discharge bucket elevator, 121 Centrifugal fan, 130 Centrifugal pump, 143 Cfbc boiler, 98 Clarification mode, 351

Back pressure turbine, 307 Backwash, 60 Baffle plates, 175 Bag filter, 224 Bag house, 224 Balancing piston, 310 Ball float trap, 286 Ball mill, 84 Ball race mill, 86 Ball valve, 292 555

556 

Index

Classifier, 84 Closed drying system, 125 Closed loop control system, 508 Coagulation, 55 Coal beneficiation, 115 Coal burner, 87 Coal feeder, 83, 121 Coal washery, 115 Collecting plate area, 230 Collecting plates, 227 Combined cycle power plant, 385 Communicator, 492 Compartments, 90 Concentric reducer, 278 Condition-based maintenance, 443 Constant support/hanger, 276 Contact mills, 85 Controlled extraction, 337 Cooling tower, 366 Corrosion, 448 Corrosion inhibitor, 168 Counter flow cooling tower, 363 Coupling, 472 Cross flow cooling tower, 364 Crusher, 122 Cyclone separator, 175, 222 Deaerator, 141 Deaerator column, 142 Definite time overcurrent relay, 415 Degasifier unit, 60 Degasser, 61 Demineralisation (dm) plant, 58 Design pressure, 253 Dew point, 137 Diaphragm valve, 291 Differential pressure (dp), 151 Differential protection, 415 Diffuser, 145 Discharge electrode, 227 Disodium phosphate, 56 Displacement, 483 Distributed control system (dcs), 522 Distributor plate, 92 Dome valve, 218 Double acting cylinder, 515 Down comers, 157

Downcomer tubes, 173 DP test, 455 Drive pulley, 117 Drum air vent, 241,  245 Drum internals, 175 Dry bulb temperature, 365 Earth fault protection relay, 415 Eccentric reducer, 278 Economiser, 75, 156 Economiser vent, 238 Electrical tracer, 113 Electrode, 464 Electromagnetic separator, 120 Emergency oil pump (eop), 349 Emergency stop valve, 320 Erosion, 448,  449 Erosion of tubes, 208 Evaporator, 157 Excess air, 44, 138 Excess air percentage, 526 Excess oxygen, 139 Expansion bellow, 274 Extraction turbine, 307 Fabric bags, 224 Fabric separator, 224 Fan curve, 131 Ferritic steel, 268 Filler rod, 467 Filtration, 54 Fireside scaling, 447 Fire tube boiler, 77 First law of thermodynamics, 7 Fixed carbon, 36 Flame sensor, 192 Flanged end, 289 Flash steam, 530 Flash tank, 162 Flexible couplings, 144 Flip flow screen, 125 Flue gas, 189 Flue gas recirculation (fgr), 206 Flue gas velocity, 208 Fluid coupling, 474 Fluorescent magnetic test, 456

Index 

Fly ash-based portland pozzolana cement (fappc), 234 Fly ash brick, 235 Foaming, 171 Forced draft, 202 Forced draught (fd) fan, 129 Furnace depth, 192 Furnace explosion, 250 Furnace height, 193 Furnace width, 193 Gagging, 187 Gas-fired boiler, 79 Gas metal arc welding (gmaw), 463 Gas tungsten arc welding (gtaw), 463 Gas turbine, 386 Gate valve, 289 Gauge glass, 162 Gauge pressure, 3 Gear couplings, 473 Gland seal condenser, 324 Glass wool, 276 Globe valve, 290 Grade of refractory, 197 Gravimetric feeder, 83 Grid couplings, 473 Gross plant heat rate, 384 Guide rollers, 118 Hammer crusher, 122 Hardness, 68 Head pulley, 117 Heat recovery area (hra), 106 Heat recovery steam generator (hrsg), 385 History book, 442 Hmi, 523 Hogger ejector, 356 Hold back device, 119 Hp heater, 338 Hybrid filter, 233 Hydraulic cylinder, 515 Hydraulic test, 461 Hydraulic test pressure, 253 Hydrazine, 67 Hydrastep, 165 Hydro test, 238, 420

557

Igcc plant, 391 Impact crusher, 123 Impact idlers, 118 Impeller, 143 Impulse turbine, 301 Induced draft, 202 Inputs and outputs (i/os), 518 Insulating materials, 198 Insulation, 198 Insulation resistance (ir) values, 432 Inverse time over current relay, 415 Inverted bucket trap, 287 I/o module, 520 I/p converter, 512 Jaw crusher, 122 Ladder logic, 521 Laminar flow, 272 Lift check valve, 297 Linear movement valve, 289 Load cell, 506 Loss of ignition (loi), 528 Low idle speed, 376 Low pressure (lp) dosing, 67 Lp heater, 338 Magnetic separators, 116 Main oil pump (mop), 349 Main steam stop valve (mssv), 176 Maintenance schedule, 441 Manifolds, 493 Master fuel trip, 249 Maximum allowable working pressure (mawp), 253 Mean time between failures (mtbf), 442 Mechanical ash handling system, 217 Mechanical draft, 201 Metal inert gas (mig), 463 Metal inert gas (mig) welding, 463 Methyl orange alkanity, 69 Mineral wool, 276 Mixed bed, 59 Monolithic refractories, 197 Monosodium phosphate, 56

558 

Index

Mortar, 197 Motorised valve, 513 Moving grate, 80 Natural circulation, 157 Natural draft, 201 Needle valve, 292 Negative phase sequence relay, 416 Net plant heat rate, 384 Net positive suction head (npsh), 146 Net positive suction head required (npshr), 146 Net turbine heat rate, 384 Nitrogen oxides (nox), 205 Non-adherent sludge, 161 Non-boiling type economiser, 156 Non-return valve (nrv), 296 Normal turbidity unit (ntu), 68 Nucleate boiling, 159

Positive displacement pump, 149 Post-weld heat treatment (pwht), 468 Predictive maintenance, 443 Preheating, 468 Pressure filter, 54 Preventive maintenance, 441 Primary air, 81 Primary air (pa) fan, 129 Proactive maintenance, 443 Process control, 507 Programmable logic control (plc), 518 Provisional order (po), 459 Pull cord switch, 119 Pulverised coal (pc) boilers, 81 Pulveriser, 84 Purification mode, 351 P–V diagram, 9 Pyrometric cone equivalent (pce), 196 Qcnrv, 337

Offline cleaning method, 225 Oil accumulator, 352 Oil-fired boilers, 79 Oil flushing, 424 Once through boilers, 152 Online cleaning method, 225 Online oxygen analyser, 526 Open drying system, 125 Output device, 487 Overhead tank, 352 Overspeed test, 428 Package boilers, 78 Parting plane, 309 Parts per million (ppm), 205 Perforated diffuser plates, 229 Permanent magnet generator (pmg), 407 pH, 68 Phenolphthalein alkanity, 69 Phosphate hide-out, 58 Phosphate treatment, 56 Pid controller, 509 Pin bush coupling, 473 Pneumatic ash handling system, 217 Pneumatic control valves, 510 Pneumatic cylinder, 514

Radiation zone, 194 Raisers, 157 Raiser tubes, 173 Rankine cycle, 13 Rapper, 227 Rapture disc, 359 Reaction turbine, 304 Read only memory (rom), 519 Recuperative air preheater, 136 Refractoriness, 196 Regeneration, 59 Regenerative air preheater (raph), 135 Regenerative rankine cycle, 15 Reheat rankine cycle, 14 Relative humidity, 363 Resistance temperature device (rtd), 495 Return idler, 118 Reverse air bag house (rabh), 225 Reverse jet bag filter, 225 Reverse power relay, 413 Rigid couplings, 144 Rigid supports/hangers, 274 Roll crusher, 123 Rotary movement valve, 289 Rotary vane feeder, 122

Index 

Rotating diodes, 407 Rubber lagging, 117 Scaling, 166 Schedule of the pipe, 263 Screen, 124, 175 Screw feeder, 122 Secondary air, 81 Secondary air (sa) fan, 129 Second law of thermodynamics, 7 Sedimentation, 54 Self-aligning troughing set, 118 Self-cleaning magnet, 120 Sensor, 487 Shaft sleeve, 144 Shield metal arc welding (smaw), 463 Shield metal arc welding (smaw), 464 Sieve analysis, 532 Silica slippage, 63 Single acting cylinder, 514 Single element level controller, 152 Slip on flange, 282 Smart transmitter, 491 Snub pulley, 117 Socket weld flange, 282 Socket welding end, 289 Soda ash (Na2CO3) treatment, 56 Solenoid valve, 513 Solid separator (cyclone separator), 98 Spider coupling, 472 Spiral wall, 104 Spray type attemperator, 182 Spreader stoker-fired boiler, 80 Start-up vent, 242 Static bed layer, 93 Static excitation system, 406 Steam blowing, 425 Steam coil air preheater (scaph), 137 Steam drum, 173 Steam impingement, 251 Steaming economiser, 156 Steam tracer, 113 Steam trap, 284, 277 Straight condensing turbine, 306 Straightedge and filler gauge method, 477 Strainer, 150 Strain gauge, 506

Stratospheric ozone, 205 Studding, 97 Supercritical (sc) boiler, 101 Surface condenser, 357 Swing check valve, 297 Syngas, 391 Synthesis gas, 391 Take-up pulley, 117 Tangentially-fired boiler, 87 Target plate, 425 Tertiary air, 87 Theoretical air, 138 Thermal conductivity, 23 Thermocouples, 495 Thermostatic trap, 286 Thermowell, 496 Three-element level controller, 153 Three Ts, 190 Thrust bearing, 318 Total acid number (tan), 348 Total dissolved solid, 69 Transformer rectifier (tr) set, 227 Transition boiling, 160 Transition header, 104 Traveling grate-fired boiler, 80 Travel of support/hanger, 274 Trisector raph, 135 Trisodium phosphate, 56 Tropospheric ozone, 205 Troughing idler, 118 T–S diagram, 9 Tungsten inert gas welding (tig), 463, 466 Turbidity, 68 Turbine bypass system, 339 Turbine overspeed, 332 Turbovisory, 333 Turbulent flow, 272 U-loops, 273 Ultrasonic test, 456 Undercut, 469 Vacuum break valve, 359 Valve, 288

559

560 

Index

Variable scoop tube, 154 Variable speed drive, 516 Variable spring support/hanger, 274 Vector surge relay, 413 Vibrating feeder, 122 Vibrating screen, 124 Volatile matter, 36 Volatile organic compounds (voc), 207 Volumetric feeder, 83 Volute, 145

Water tube boiler, 77 Water wall, 158 Wear ring, 146 Weigh feeder, 116 Weld neck flange, 281 Wet bulb temperature, 365 White body, 26 Woodward, 505, 329

Y-type strainer, 298 Waste heat recovery boilers, 77 Waterbox, 358 Waterside scaling, 447

Zero speed switch, 119 Zeroth law of thermodynamics, 6