THE JOHN ZINK HAMWORTHY

COMBUSTION HANDBOOK SECOND EDITION

Volume 3 APPLICATIONS

THE JOHN ZINK HAMWORTHY

COMBUSTION HANDBOOK SECOND EDITION

Volume 3 APPLICATIONS

Edited by

Charles E. Baukal, Jr.

vC**' J Taylor & Francis Croup

Boca Raton London New York

CRC Press is an imprint of the Taylor & Francis Group, an informa business

Contents

List of Figures ix List of Tables xxi Foreword to the First Edition xxiii Preface to the First Edition xxv Preface to the Second Edition xxvii Acknowledgments xxix Editor : xxxi Contributors xxxiii Prologue xxxvii

1. Process Burners 1 Erwin Platvoet, I.-Ping Chung, Michael G. Claxton, and Tami Fischer

2. Oil Burners 35 I.-Ping Chung, Steve Londerville, Michael G. Claxton, and William Johnson

3. Burners and Combustion Systems for Industrial and Utility Boilers 57 Vladimir Lifshits

4. Duct Burners 93 Peter F. Barry, Stephen L. Somers, and Steve Londerville.

5. Marine and Offshore Applications 117 Richard Price

6. Process Heaters 129 Erwin Platvoet, David Brown, and Rasik Patel

7. Air Heaters 149 Carl A. Connally, Lothar Schulz, and Timothy Webster

8. Thermal Oxidizer Basics 159 Jay Karan, Bernd Reese, Klaus-Dieter Zschorsch, and Wolfgang Klaus

9. Thermal Oxidizer Control and Configurations 211 Bernd Reese, Wolfgang Klaus, Jay Karan, and Juergen Foelting

10. Selected Pollution Control Equipment 239 Klaus-Dieter Zschorsch

11. Flares 251 Robert E. Schwartz, Jeff White, and Wes Bussman

12. Pilot, Ignition, and Monitoring Systems 299 Adam Bader and John Bellovich

13. Biogas Flaring 307 Tim W. Locke, Brandy S. Johnson, and Jason P. Rolf

viii Contents

14. Flare Gas Recovery 331 Jeff Peterson, Nick Tuttle, Harley Cooper, and Charles E. Baukal, Jr.

15. Hydrocarbon Vapor Control Technology 339 Roger E. Blanton

Appendix A: Units and Conversions 365

Appendix B: Physical Properties of Materials 369

Appendix C: Properties of Gases and Liquids 377

Appendix D: Properties of Solids 397

Appendix E: Trademark Disclaimer 401

Index 405

List of Figures

Figure 1.1 General burner construction 3

Figure 1.2 PVYD-M natural-draft, gas-only burner (with air inlet noise suppression) 4

Figure 1.3 PFFG gas-only flat-flame burner 4

Figure 1.4 PMA round flame combination gas and liquid burner 4

Figure 1.5 HEVD premix burner assembly. 4

Figure 1.6 Staged-air combustion 5

Figure 1.7 HAWAstar staged-air, gas-fired burner assembly. 5

Figure 1.8 LNC staged air combination gas/liquid burner assembly. 5

Figure 1.9 Hamworthy Enviromix 2000 staged-air burner assembly. 6

Figure 1.10 Hamworthy EEP flat-flame staged-air burner assembly. 7

Figure 1.11 Staged-fuel combustion 7

Figure 1.12 PSFG burner assembly. 8

Figure 1.13 PSFFG flat-flame staged-fuel burner assembly. 8

Figure 1.14 Ultralow-NOx stoichiometry. 9

Figure 1.15 Ultralow-NOx flame development 9

Figure 1.16 (a) PSMR ultralow-NOx burner assembly and (b) flame photo 10

Figure 1.17 Relative NOx emissions versus flame stoichiometry. 10

Figure 1.18 LPMF lean premix staged-fuel burner assembly. 11

Figure 1.19 The COOLstar folded flame (flower shape when looking down from the top of the tile) 12

Figure 1.20 COOLstar® burner cutaway. 12

Figure 1.21 CFD simulation results for CO concentration contours on COOLstar burner 13

Figure 1.22 CFD simulation results for temperature contours of COOLstar burner. 13

Figure 1.23 COOLstar flame photo 13

Figure 1.24 Entrainment around a Coanda surface 14

Figure 1.25 Coanda tile surface 14

Figure 1.26 HALO flame photo 14

Figure 1.27 Freestanding burners 14

Figure 1.28 MDBP burner firing PSA off gas (view looking up at burner) 15

Figure 1.29 PDSMR MK-II tile and fuel tips 16

Figure 1.30 (a) PDSMR Mk-II burner assembly and (b) flame photo 16

Figure 1.31 (a) PXMR burner assembly and (b) flame photo 17

Figure 1.32 PSFFR burner assembly. 17

I •Si

x List of Figures

Figure 1.33 (a) LPMF burner assembly and (b) flame photo 18

Figure 1.34 (a) RTW test burner and (b) CFD-calculated result 18

Figure 1.35 (a) Modified RTW burner and (b) CFD-calculated result 19

Figure 1.36 (a) PXMR-DS burner and (b) flame photo 19

Figure 1.37 Premix radiant wall burner array. 20

Figure 1.38 PMS premix gas burner assembly. 20

Figure 1.39 PMS flame (front view) 21

Figure 1.40 PMS flame (side view) 21

Figure 1.41 Hamworthy Walrad burner assembly. 21

Figure 1.42 LPMW radiant wall burner array. 22

Figure 1.43 LPMW with elbowed venturi 23

Figure 1.44 LPMW with in-line venturi and staged-fuel adaptor/tip 23

Figure 1.45 LPMW with in-line venturi for RFS integration 23

Figure 1.46 FPMR radiant wall burner cutaway. 24

Figure 1.47 (a) FPMR burner assembly and (b) cutaway. 24

Figure 1.48 Oil gun with concentric tube design 25

Figure 1.49 MEA oil gun with dual (parallel)-tube design 25

Figure 1.50 John Zink EA oil atomizer and tip 25

Figure 1.51 John Zink MEA oil atomizer and tip 25

Figure 1.52 Hamworthy SAR oil atomizer and tip 26

Figure 1.53 Hamworthy DS oil atomizer and tip ! 26

Figure 1.54 John Zink PM atomization system (port mix) 27

Figure 1.55 The HERO gun 27

Figure 1.56 Standard combination burner 28

Figure 1.57 PLNC staged-air combination burner 29

Figure 1.58 DEEPstar low-NOx gas/oil combination burner 29

Figure 1.59 (a) DEEPstar oil flame and (b) gas flame 30

Figure 1.60 ST-l-S manual pilot 31

Figure 1.61 ST-l-SE electric ignition pilot. 31

Figure 1.62 ST-1-SE-FR electric ignition pilot with an integral flame rod : 31

Figure 1.63 KE-l-ST electric ignition pilot 31

Figure 1.64 ST-2 manual pilot 32

Figure 1.65 KE-2-ST electric ignition pilot 32

Figure 2.1 Typical liquid fuel atomizer-spray tip configurations 37

Figure 2.2 Oil gun capacity curves for heavy oil and light oil for one specific oil gun 38

Figure 2.3 Oil gun capacity curves for steam atomizing and air atomizing for one specific oil gun 38

List of Figures xi

Figure 2.4 Oil flame cone-type stabilizer 39

Figure 2.5 Oil tile to stabilize the oil flame 39

Figure 2.6 Round burner tile provides round oil flame 40

Figure 2.7 Rectangular burner tile provides flat oil flame 40

Figure 2.8 Coen Co. elliptical cap with slots for low NOx 42

Figure 2.9 CFI versus CCR, RCR, and asphaltenes 44

Figure 2.10 Combination oil and gas LoNOx burner 46

Figure 2.11 Secondary (outside) and primary (inside) tiles 46

Figure 2.12 Regen tile and one section of secondary tile 47

Figure 2.13 Regen oil tile with an oil gun in the center (secondary tile not shown) 47

Figure 2.14 Swirler for oil firing on forced draft 48

Figure 2.15 Diffuser cones for light oil firing 48

Figure 2.16 Typical rotary-type air registers 49

Figure 2.17 Air register with rollers for easy operation 49

Figure 2.18 Vane-type air register 50

Figure 2.19 Integral plenum box with inlet air damper and muffler 50

Figure 2.20 Oil gun insert and oil body receiver (with red caps) 51

Figure 2.21 EA oil gun parts 51

Figure 2.22 EA oil tip 51

Figure 2.23 MEA oil tip 51

Figure 2.24 MEA oil gun parts 51

Figure 2.25 Atomizer with labyrinth seals and steam ports 51

Figure 2.26 Checking atomizer location in the sleeve 52

Figure 2.27 Flame impingement on tubes 52

Figure 2.28 Fouled oil guns 53

Figure 2.29 Oil-firing problems and possible causes 54

Figure 3.1 Approximate rate of thermal (Zeldovich) NO formation 61

Figure 3.2 Approximate relation of NOx reduction with FGR for fuels without FBN 62

Figure 3.3 NOx performance of a typical Coen premix burner firing natural gas in a package boiler 65

Figure 3.4 QLA burner performance at high fire 65

Figure 3.5 Coen DAZ™ burner 68

Figure 3.6 Coen Variflame™ burner 68

Figure 3.7 Hamworthy DFL® burner 68

Figure 3.8 Coen DAF™ burner 69

Figure 3.9 Coen Delta-NOx™ burner 69

Figure 3.10 ECOjet® gas-only burners 69

xii List of Figures

Figure 3.11 (a) Hamworthy ECOjei® flame, (b) Natural gas firing at 30 MW (100 x 106 Btu/h) at Hamworthy test facility. 70

Figure 3.12 Schematic of a QLN™ burner. 70

Figure 3.13 Coen QLN burner flame with 20 ppm NOx firing natural gas without FGR 71

Figure 3.14 Coen RMB™ burner equipped with an air isolation sliding barrel damper 72

Figure 3.15 Fuel risers of a Coen RMB burner 72

Figure 3.16 Enhanced images of the gas-fired RMB flame 73

Figure 3.17 Coen D-RMB® burner mounted inside the wind box 73

Figure 3.18 Coen D-RMB™ burner performance in a large package boiler 74

Figure 3.19 Coen QLA burner schematic 74

Figure 3.20 Assembled Coen QLA burner (side) 75

Figure 3.21 Assembled Coen QLA burner (front) 75

Figure 3.22 Coen QLA burner flame with 7 ppm NOx (natural gas firing) 75

Figure 3.23 Peabody LVC™ burner for firing BFG 75

Figure 3.24 Modified Coen LCF burner for simultaneous low-NOx firing of multiple fuels of variable composition 75

Figure 3.25 NOx reduction with FGR mixed with combustion air or fuel 76

Figure 3.26 Large Coen QLN burners mounted inside wind boxes 77

Figure 3.27 Coen QLN-II burner inside a furnace 78

Figure 3.28 Row of boilers equipped with Coen QLN-IPM burners rated to 63 and 90 x 106 Btu/h (18.5-26 MWt) 78

Figure 3.29 Typical NOx performance of QLN-II™ burner with FGR 79

Figure 3.30 Large 350 x 106 Btu/h (103 MW) DAF™ burner for firing (a) syngas and (b) natural gas 79

Figure 3.31 Flames of DAF™ burner firing (a) natural gas and (b) syngas 80

Figure 3.32 Schematic of Coen Delta Power™ burner 80

Figure 3.33 Examples of NOx reduction with air staging and FGR in utility boilers when firing natural gas (various boilers) 82

Figure 3.34 Effect of fuel biasing on the NOx 83

Figure 3.35 Effect of FGR on thermal portion of NOx in different utility boilers 84

Figure 3.36 NOx emissions firing #6 oil with 0.54% FBN 84

Figure 3.37 Low-NOx natural gas flame 85

Figure 3.38 Main components of a fixed geometry burner for a gas and oil T-fired boiler 86

Figure 3.39 Spinners for tilting burners 86

Figure 3.40 Flame stabilizers and buckets of tilting (a) gas-fired burner and (b) oil-fired burner 87

Figure 3.41 Corner of a T-fired boiler with tilting burners with some heat damage 87

Figure 3.42 Coen warm-up gas burners 88

Figure 3.43 Conceptual design of low-CO flue-gas reheat system for refinery gas firing 89

Figure 3.44 Coen ProLine™ burner flames at low- (left) and high-fire (right) operation 90

List of Figures xiii

Figure 4.1 Typical cogeneration plant schematic 95

Figure 4.2 Cogeneration plant at Teesside, England 96

Figure 4.3 Combination (oil and gas)-fired duct burners at Dahbol, India 97

Figure 4.4 Typical location of duct burners in an HRSG 97

Figure 4.5 Schematic of HRSG at Teesside, England 98

Figure 4.6 Fluidized bed startup duct burner 98

Figure 4.7 An inline burner 99

Figure 4.8 Linear burner elements 99

Figure 4.9 Gas flame from a grid burner 99

Figure 4.10 Oil flame from a side-fired oil gun 100

Figure 4.11 Approximate requirement for augmenting air 101

Figure 4.12 Drawing of a Duct burner arrangement 101

Figure 4.13 Comparison of flow variation with and without straightening device 102

Figure 4.14 Physical model of a duct burner array 103

Figure 4.15 Sample result of CFD modeling performed on an HRSG inlet duct 104

Figure 4.16 Drilled pipe duct burner 105

Figure 4.17 Low-emission duct burner 105

Figure 4.18 Flow patterns around flame stabilizer 105

Figure 4.19 Effect of conditions on CO formation 107

Figure 4.20 Typical main gas fuel train: single element or multiple elements firing simultaneously. 110

Figure 4.21 Typical main gas fuel train: multiple elements with individual firing capability. Ill

Figure 4.22 Typical pilot gas train: single element or multiple elements firing simultaneously. Ill

Figure 4.23 Typical pilot gas train: multiple elements with individual firing capability. 112

Figure 4.24 Typical main oil fuel train: single element 113

Figure 4.25 Typical main oil fuel train: multiple elements 114

Figure 4.26 Typical pilot oil train: single element 114

Figure 4.27 Typical pilot oil train: multiple elements 115

Figure 5.1 Hamworthy Combustion ElectroTec® rotary-cup burner 119

Figure 5.2 Hamworthy Combustion DF register burner 120

Figure 5.3 Heavy fuel-oil sprayer and twin-fluid Y-jet atomizer 120

Figure 5.4 Hamworthy Combustion HXG dual fuel register burner 121

Figure 5.5 Chentronics® high-energy igniter 121

Figure 5.6 Hamworthy Combustion AMOxsafe® GCU. (a) GCU system arrangement of aft deck and (b) GCU body 122

Figure 5.7 AMOxsafe® GCU flow schematic 123

xiv List of Figures

Figure 5.8 AMOxsafe® GCU temperature profile as predicted by CFD modeling 124

Figure 5.9 Hamworthy Combustion DF register burner 124

Figure 5.10 Fuel-gas valve enclosure for FPSO engine room boiler 125

Figure 5.11 Hamworthy Combustion's triple 120 metric-ton/h (132 U.S. ton/h) steam boiler module for FPSO 126

Figure 5.12 Hamworthy Combustion's high-pressure steam boiler module for power generation 126

Figure 5.13 Hamworthy Combustion's fuel-gas knockout pot on an FSO 127

Figure 5.14 Hamworthy Combustion's DFL low-NOx register burner 127

Figure 6.1 Typical heater types 132

Figure 6.2 Vertical cylindrical furnace arrangement 133

Figure 6.3 Two vertical cylindrical fireboxes with common convection section 133

Figure 6.4 Box-type heater with horizontal tubes 134

Figure 6.5 Box-type heater with horizontal tubes 134

Figure 6.6 Cabin heater 135

Figure 6.7 Typical coker furnace 136

Figure 6.8 Double wide coker furnace 136

Figure 6.9 Top-fired reformer 137

Figure 6.10 Side-fired reformer 138

Figure 6.11 Terrace wall-fired reformer 138

Figure 6.12 Bottom-fired reformer 139

Figure 6.13 Typical cracking furnace firebox layout 140

Figure 6.14 Variations of typical cracking furnace firebox layout 140

Figure 6.15 Radiant wall burners t 141

Figure 6.16 Large heat release floor burners 141

Figure 6.17 Example of flame rollover in a pilot-scale cracking furnace 141

Figure 6.18 Spectral absorptivity of C02 at 830 K and 10 atm for a path length of 38.8 cm 143

Figure 6.19 Radiation to a single row of tubes backed by a refractory wall 144

Figure 6.20 Incident radiation to a single-tube row, which is backed by a refractory wall 145

Figure 6.21 Effective emissivity of a single-tube row backed by a refractory wall, plotted for various tube emissivities 145

Figure 6.22 Relationship of reduced firing density and reduced efficiency. 146

Figure 7.1 Direct-fired air heater 150

Figure 7.2 Horizontal direct-fired air heater with side outlet 150

Figure 7.3 Direct-fired air heater with separate combustion air inlet 150

Figure 7.4 Oil-fired air heater 151

Figure 7.5 All-metal air heater 151

Figure 7.6 AH 11/2 pilot with retractable igniter 153

Figure 7.7 Retractable high-energy igniter 153

List of Figures xv

Figure 7.8 Plume pilot 154

Figure 7.9 Splitter damper 154

Figure 7.10 Combustion chamber with tube bundle 155

Figure 7.11 GSX heater with housing 156

Figure 7.12 VTK heater with air inlet and outlet sockets 156

Figure 7.13 VTK heater in sectional view. 156

Figure 7.14 VTN heater, view to the cleaning door 156

Figure 7.15 VTN heater in sectional view. 156

Figure 7.16 HG-WT heater 157

Figure 7.17 HG-WT heater in sectional view 157

Figure 8.1 Example of a comprehensive thermal oxidizer system 161

Figure 8.2 Typical natural draft burner 166

Figure 8.3 Typical medium-pressure-drop burner 167

Figure 8.4 Typical high-pressure-drop burner 167

Figure 8.5 Schematic of a KEU combustor 168

Figure 8.6 KEU Combustor 168

Figure 8.7 Typical horizontal system with a preheat exchanger 173

Figure 8.8 Water-tube boiler 174

Figure 8.9 Fire-tube boiler 176

Figure 8.10 Typical all-welded shell-and-tube heat exchanger 176

Figure 8.11 Regenerative preheat exchanger 177

Figure 8.12 Organic fluid transfer system configuration 178

Figure 8.13 Vertical, downflow conditioning section 179

Figure 8.14 Direct spray contact quench 180

Figure 8.15 Submerged quench 182

Figure 8.16 Adjustable-plug venturi quench 183

Figure 8.17 Baghouse 185

Figure 8.18 Dry ESP. 186

Figure 8.19 Horizontal venturi scrubber 188

Figure 8.20 Wet ESP. 189

Figure 8.21 Simple packed column 190

Figure 8.22 Two-stage acid-gas removal system 192

Figure 8.23 Combination quench/two-stage acid removal system 193

Figure 8.24 Three-stage NOx reduction process 194

Figure 8.25 Two-stage NOx reduction process 196

Figure 8.26 Results of three different DENOX units 197

Figure 8.27 Scheme regarding catalytic reaction of NOx and NH3 on the catalyst 198

xvi List of Figures

Figure 8.28 Schematic process diagram for SCR of NOx 199

Figure 8.29 Control parameter/control of reducing agent (NH3) 200

Figure 8.30 Ammonia maldistribution 201

Figure 8.31 Example of ammonium bisulfate formation and reversible plugging of the pores at low operation temperature 202

Figure 8.32 Corrugated catalyst and elements 204

Figure 8.33 (a) Fan wheel designs, (b) outlet damper flow control, (c) radial inlet damper flow/inlet box damper flow control, and (d) blower speed control 206

Figure 9.1 Typical control schematic of a combined fuel/air controller suitable for set points coming from an external calculation 213

Figure 9.2 Example of a two-stage combustion unit (PFD) 214

Figure 9.3 Example process and instrumentation diagram for a typical multipurpose TO application 216

Figure 9.4 Example for the difference between conventional combustion air supply and energy-optimized operation in a TO unit with one combustible waste liquid 217

Figure 9.5 Typical automation concept with separated BMS and DCS 217

Figure 9.6 Example for a combined automation concept 218

Figure 9.7 Simple vertical TO 219

Figure 9.8 TO system generating steam 219

Figure 9.9 Heat recovery thermal oxidation system 220

Figure 9.10 Bypass recuperative system 221

Figure 9.11 Horizontal TO with fire-tube boiler and HC1 removal system 226

Figure 9.12 Vertical TO with 180° turn quench section 227

Figure 9.13 CI reaction equilibrium versus operating temperature 227

Figure 9.14 Computer model of a Combustor-based TO system for explosive waste gases with boiler and scrubber 229

Figure 9.15 Combustor with a waste gas organ for explosive waste gas 230

Figure 9.16 Computer model of a TO system with GPR technology. 230

Figure 9.17 Schematic of explosion protection for Zone 0 232

Figure 9.18 Cutaway photo of a static detonation arrestor 233

Figure 9.19 Sectional drawing of a static detonation arrestor 233

Figure 9.20 Arrangement drawing of a liquid seal vessel 234

Figure 9.21 Molten salt system 235

Figure 9.22 On-line cleaning with soot blowers 236

Figure 9.23 Three-stage NOx system with packed column scrubber 237

Figure 10.1 Combination of an SCR and a catalytic oxidizer for two streams containing high load of VOCs and NH3/ and stream containing low NOx load 240

Figure 10.2 Combination of an SCR and a catalytic oxidizer for a flue gas stream containing a high load of NOx and CO and a low load of NOx and ammonia 241

List of Figures xvii

Figure 10.3 Combination of an SCR and a catalytic oxidizer for a greenhouse application 242

Figure 10.4 FRIGOSOLVER® unit 243

Figure 10.5 Cooling coil 244

Figure 10.6 Direct condensation in a liquid bath of deep cooled solvents, here called the FRIGOSOLVER® unit 246

Figure 10.7 Combination of condensation unit and catalytic waste combustion 247

Figure 10.8 Saturated concentration in accordance with saturation temperature 248

Figure 11.1 Typical early 1950s flare performance 252

Figure 11.2 An early model smokeless flare 253

Figure 11.3 Major flaring event 253

Figure 11.4 Typical elevated single-point flare 254

Figure 11.5 Typical pit flare installation 254

Figure 11.6 A grade-mounted, multipoint LRGO flare system 254

Figure 11.7 Elevated multipoint LRGO flare system 254

Figure 11.8 Multiple ZTOF installation in an ethylene plant 255

Figure 11.9 Combination elevated flare system (left) and ZTOF (right) 255

Figure 11.10 Combination elevated LRGO and utility flare system 255

Figure 11.11 Comparison of the flame produced by burning (a) 25 MW wellhead natural gas, (b) propane, and (c) propylene 258

Figure 11.12 General arrangement of a staged flare system, including a ZTOF and an elevated flare 260

Figure 11.13 Flare test at the John Zink Co. test facility in Tulsa, Oklahoma 261

Figure 11.14 Liquid carryover from an elevated flare 263

Figure 11.15 Thermogram of a flare flame 266

Figure 11.16 API radiation geometry. 266

Figure 11.17 Comparison of stack height and relative cost for various radiation calculation methods 267

Figure 11.18 Effectiveness of steam in smoke suppression 268

Figure 11.19 Effectiveness of air in smoke suppression 268

Figure 11.20 Steamizer™ steam-assisted smokeless flare 269

Figure 11.21 Typical nonassisted flare 270

Figure 11.22 ZDR severe service flare tip 270

Figure 11.23 Simple steam-assisted flare 271

Figure 11.24 Perimeter/area ratio as a function of tip size for a simple steam-assisted flare 271

Figure 11.25 Schematic of an advanced steam-assisted flare 272

Figure 11.26 A comparison of the perimeter/area ratio for simple and advanced steam-assisted flares 273

Figure 11.27 Steamizer® flare burner and muffler 273

Figure 11.28 State-of-the-art Steamizer® XP™ 273

Figure 11.29 Air-assisted smokeless flare with two blowers in a refinery. 274

xviii List of Figures

Figure 11.30 Annular air flare 274

Figure 11.31 Hydra flare burner in an offshore location 275

Figure 11.32 LRGO staging sequence during a flaring event from inception (a) to full load (g) 276

Figure 11.33 Multipoint LRGO system with a radiation fence 279

Figure 11.34 A RIMFIRE® endothermic flare 280

Figure 11.35 OWB liquid flare test firing 150 gpm (570 L/min) 280

Figure 11.36 Forced-draft Dragon liquid flare 281

Figure 11.37 Poseidon flare: water-assisted Hydra 282

Figure 11.38 Horizontal settling drum at the base of an air-assisted flare 283

Figure 11.39 Cyclone separator 283

Figure 11.40 Schematic of a vertical liquid seal 284

Figure 11.41 "Smoke signals" from a surging liquid seal 285

Figure 11.42 Various liquid seal head types 285

Figure 11.43 AIRRESTOR velocity-type purge reduction seal 286

Figure 11.44 Molecular seal density-type purge reduction seal 286

Figure 11.45 Schematic of a ZTOF. 287

Figure 11.46 Self-supported flare 288

Figure 11.47 Guy wire-supported flare 289

Figure 11.48 Derrick-supported flare 289

Figure 11.49 Demountable derrick 290

Figure 11.50 Flare support structure selection guide 290

Figure 11.51 Steam control valve station 291

Figure 11.52 Staging control valve assembly. 292

Figure 11.53 Loop seal 292

Figure 11.54 Purge control station 293

Figure 11.55 Geometry for plume dispersion calculations 296

Figure 12.1 Pilot schematic 300

Figure 12.2 Pilot operating in high wind and rain conditions 301

Figure 12.3 Slipstream-type ignition 302

Figure 12.4 Flame ionization 303

Figure 12.5 John Zink infrared grade-mounted camera 304

Figure 12.6 Pilot operating at night 304

Figure 12.7 Acoustic pilot monitoring 305

Figure 13.1 Solar powered passive flare 310

Figure 13.2 Elevated flare 311

Figure 13.3 Unconfined flame extending beyond the windshield 312

Figure 13.4 Enclosed flare 312

Figure 13.5 Elevated flare inlet and riser 313

•-MS*

List of Figures xix

Figure 13.6 Elevated flare pilot and main flame thermocouples 314

Figure 13.7 Radiation isoplot (Btu/h-ft2) 314

Figure 13.8 Enclosed flare gas manifold 314

Figure 13.9 Enclosed flare gas manifold with flanged flare tips 315

Figure 13.10 Enclosed flare air damper louvers 315

Figure 13.11 Enclosed flare interior insulation and thermocouples 315

Figure 13.12 Landfill gas flame 316

Figure 13.13 Flame lengths 316

Figure 13.14 Sample ports 317

Figure 13.15 Zink Ultra Low Emission (ZULE®) enclosed flare 318

Figure 13.16 ZULE static mixing chamber. 318

Figure 13.17 View inside ZULE enclosed flare 319

Figure 13.18 Single-stage fans in a landfill application 324

Figure 13.19 Multistage blowers 324

Figure 13.20 A cutaway of a multistage blower showing eight impellers 325

Figure 13.21 As the gas travels through each impeller, it increases temperature 325

Figure 13.22 1-2-3 Fan law. 326

Figure 13.23 Siloxane removal system 327

Figure 13.24 P&ID of gas utilization and a single flare 328

Figure 13.25 P&ID of gas utilization and dual flares 329

Figure 14.1 Example of an air-assisted flare during testing 332

Figure 14.2 Example of a flare being oversteamed during testing 333

Figure 14.3 Example of waste-gas flows to a flare in a typical refinery over approximately an 8-month period 333

j Figure 14.4 Generalized flare-gas recovery process schematic 335

Figure 14.5 FGRS at FHR West Plant in Corpus Christi, Texas : 337

Figure 15.1 Splash loading method 342

Figure 15.2 Submerged fill pipe 342

Figure 15.3 Bottom loading 343

Figure 15.4 Vapor control stage 1 343

Figure 15.5 Summary of U.S. VOC emissions 345

Figure 15.6 Adsorption versus absorption 346

Figure 15.7 Single particle of granular activated carbon 347

Figure 15.8 Pore structure with adsorbate molecules in the pores of the activated carbon 347

Figure 15.9 Carbon adsorption-absorption (ADAB™) process 351

Figure 15.10 Three carbon bed zones 352

Figure 15.11 John Zink DVP VRU 353

xx List of Figures

Figure 15.12 Process schematic for an S3-AAD VRU 354

Figure 15.13 John Zink LRVP VRU 355

Figure 15.14 Diagram of a vapor combustor 356

Figure 15.15 Photos of vapor combustors 357

Figure 15.16 Stratification of vapors in a tank truck 358

Figure 15.17 Truck rack vapor control system block diagram 358

Figure 15.18 Vapor stratification in a vessel 359

Figure 15.19 Marine vapor control block diagram 359

Figure 15.20 Internal floating roof tank vent control system block diagram 360

Figure 15.21 Cross section of a detonation arrestor 361

Figure 15.22 Pressure waves generated by a flame front in a pipe 361

List of Tables

Table 1.1 Burner Classifications 3

Table 4.1 Typical NOx and CO Emissions from Duct Burners 109

Table 6.1 Typical Firing Splits 139

Table 6.2 Favored Flame Shape for Various Reformer Types 139

Table 8.1 Typical TO Operating Conditions 169

Table 8.2 Types of Mixing Elements and Related NH3/NOx Maldistribution 200

Table 8.3 Advantages and Disadvantages of Various Types of Fan Wheel Designs 208

Table 10.1 Plant Attribute 245

Table 12.1 Recommendation for Minimum Number of Pilots from API SP 537 Document 301

Table 12.2 Comparison of Flare Pilot Detection Systems 305

Table 14.1 Example of Waste-Gas Compositions at a Typical Plant 334

Table 15.1 Vacuum Conversion Chart 341

Table 15.2 Typical Chemical Composition of Gasoline Vapors 342

Table 15.3 Comparison of Allowable Vapor Emissions at 90% Control Efficiency 344

Table 15.4 Comparison of U.S. Emission Regulations versus Recovery Efficiency 344

Table 15.5 Current European VOC Emission Limits 345

Table 15.6 Groups of Various Hydrocarbons 361

xxi