Operating Guidelines
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SAMSUNG TOTAL PETROCHEMICALS CO., LTD. SULFUR BLOCK NO. 2 AROMATICS COMPLEX DAESAN, KOREA
OPERATING GUIDELINES
Prepared by Ortloff Engineers, Ltd. Midland, Texas USA Project 507000 Fall 2011
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
Table of Contents 1. INTRODUCTION .......................................................................................................... 1-1 2. GENERAL SAFETY ..................................................................................................... 2-1 2.1 DEFINITION OF TERMS ....................................................................................... 2-1 2.2 HYDROGEN SULFIDE (H2S) ................................................................................ 2-3 2.2.1 Description and Properties ............................................................................. 2-3 2.2.2 First Aid .......................................................................................................... 2-7 2.2.3 Precautions (remember these facts) .............................................................. 2-8 2.2.4 Good Work Practices...................................................................................... 2-9 2.3 SULFUR DIOXIDE (SO2) ..................................................................................... 2-10 2.3.1 Description and Properties ........................................................................... 2-10 2.3.2 First Aid ........................................................................................................ 2-13 2.3.3 Precautions................................................................................................... 2-14 2.4 SULFUR .............................................................................................................. 2-15 2.4.1 Description and Properties ........................................................................... 2-15 2.4.2 Precautions................................................................................................... 2-20 2.4.3 Fire Fighting.................................................................................................. 2-21 2.5 AMMONIA (NH3) .................................................................................................. 2-22 2.5.1 Description and Properties ........................................................................... 2-22 2.5.2 First Aid ........................................................................................................ 2-26 2.5.3 Precautions................................................................................................... 2-26 2.6 METHYLDIETHANOLAMINE (MDEA, CH3-N-(CH2-CH2-OH)2)........................... 2-28 2.6.1 Description and Properties ........................................................................... 2-28 2.6.2 First Aid ........................................................................................................ 2-29 2.6.3 Precautions................................................................................................... 2-30 2.7 SODIUM HYDROXIDE (CAUSTIC SODA, NAOH) ............................................. 2-31 2.7.1 Description and Properties ........................................................................... 2-31 2.7.2 First Aid ........................................................................................................ 2-35 2.7.3 Precautions................................................................................................... 2-36 2.8 SULFUR PLANT SAFETY ................................................................................... 2-37 2.8.1 Hydrogen Sulfide .......................................................................................... 2-37 2.8.2 Sulfur Dioxide ............................................................................................... 2-37 2.8.3 Sulfur Storage Tank...................................................................................... 2-38 2.9 HOT WORK ......................................................................................................... 2-39 2.10 VESSEL ENTRY.................................................................................................. 2-39 2.11 PIPES AND LINES .............................................................................................. 2-41 2.11.1 General ......................................................................................................... 2-41 2.11.2 Before Breaking Lines .................................................................................. 2-42
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Table of Contents 2.11.3 When Breaking Lines ................................................................................... 2-42 2.12 ELECTRICAL EQUIPMENT ................................................................................ 2-42 2.12.1 Electrical Repairs.......................................................................................... 2-43 2.12.2 Grounding ..................................................................................................... 2-43 2.12.3 Conduit, Cables, and Wires .......................................................................... 2-43 2.12.4 Fuses ............................................................................................................ 2-43 2.12.5 Switching ...................................................................................................... 2-43 2.12.6 Hand Tools and Portable Equipment............................................................ 2-44 2.12.7 Miscellaneous ............................................................................................... 2-44 2.13 BOILERS AND OTHER DIRECT-FIRED EQUIPMENT ...................................... 2-45 2.13.1 General ......................................................................................................... 2-45 2.13.2 Boilers........................................................................................................... 2-45 2.13.3 Direct-Fired Equipment................................................................................. 2-46 2.14 LABORATORY SAFETY ..................................................................................... 2-47 2.14.1 Good Housekeeping ..................................................................................... 2-47 2.14.2 Equipment .................................................................................................... 2-47 2.14.3 Chemical Sorting and Identification .............................................................. 2-47 2.14.4 Chemical Handling ....................................................................................... 2-48 2.15 MATERIAL SAFETY DATA SHEETS (MSDS) .................................................... 2-49 3. GENERAL .................................................................................................................... 3-1 3.1 ORGANIZATION ................................................................................................... 3-1 3.2 GENERAL PRECOMMISSIONING PROCEDURES ............................................. 3-2 3.2.1 Mechanical ..................................................................................................... 3-2 3.2.2 Electrical ......................................................................................................... 3-3 3.2.3 Instrumentation ............................................................................................... 3-5 3.3 DESIGN BASIS ..................................................................................................... 3-7 3.3.1 Plant Capacity ................................................................................................ 3-7 3.3.2 Sulfur Block Feed Streams ............................................................................. 3-7 3.3.3 Effluent Stream Conditions ........................................................................... 3-12 3.3.4 Other Design Requirements ......................................................................... 3-13 3.3.5 Utility Information .......................................................................................... 3-14 3.3.6 Plant Site Conditions .................................................................................... 3-16 4. POWER DISTRIBUTION .............................................................................................. 4-1 4.1 PURPOSE OF SYSTEM ....................................................................................... 4-1 4.2 SAFETY ................................................................................................................. 4-1 4.2.1 General ........................................................................................................... 4-1 4.2.2 Hazardous (Classified) Areas ......................................................................... 4-1
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Table of Contents 4.3 EQUIPMENT DESCRIPTION ................................................................................ 4-2 4.3.1 Motors and Motor Controls ............................................................................. 4-2 5. PLANT CONTROL SYSTEMS ..................................................................................... 5-1 5.1 5.2 5.3 5.4
DISTRIBUTED CONTROL SYSTEM .................................................................... 5-1 PROGRAMMABLE LOGIC CONTROL SYSTEM ................................................. 5-2 EMERGENCY SHUTDOWN SYSTEMS ............................................................... 5-3 LOCAL CONTROL PANELS ................................................................................. 5-3
6. UTILITY SYSTEMS ...................................................................................................... 6-1 6.1 PURPOSE OF SYSTEM ....................................................................................... 6-1 6.2 SYSTEM DESCRIPTION ...................................................................................... 6-1 6.2.1 Nitrogen Supply .............................................................................................. 6-1 6.2.2 C4 LPG and Treated Fuel Gas Supply .......................................................... 6-2 6.2.3 Hydrogen Supply ............................................................................................ 6-2 6.2.4 Plant Air .......................................................................................................... 6-3 6.2.5 Instrument Air ................................................................................................. 6-3 6.2.6 Sour Water Disposal....................................................................................... 6-3 6.2.7 Steam, Condensate, Boiler Feed Water, and Blowdown ............................... 6-4 6.3 PRECOMMISSIONING, STARTUP, AND SHUTDOWN PROCEDURES............. 6-8 7. AMINE TREATING & AMINE REGENERATION ......................................................... 7-1 7.1 PURPOSE OF SYSTEM ....................................................................................... 7-1 7.2 SAFETY ................................................................................................................. 7-1 7.3 PROCESS DESCRIPTION.................................................................................... 7-2 7.3.1 General ........................................................................................................... 7-2 7.3.2 Water Washing ............................................................................................... 7-2 7.3.3 Sour Gas Contacting ...................................................................................... 7-3 7.3.4 Solvent Regeneration ..................................................................................... 7-3 7.4 EQUIPMENT DESCRIPTION ................................................................................ 7-6 7.4.1 Wash Water Column, A2-DA1510 .................................................................. 7-6 7.4.2 Amine Absorber, A2-DA1511 ......................................................................... 7-6 7.4.3 Flash Gas Contactor, A2-DA1512 .................................................................. 7-6 7.4.4 Stripper, A2-DA1513 ...................................................................................... 7-6 7.4.5 Wash Water Column Packing, A2-DB1510 .................................................... 7-7 7.4.6 Amine Absorber Trays, A2-DB1511 ............................................................... 7-7 7.4.7 Stripper Trays, A2-DB1513 ............................................................................ 7-7 7.4.8 Amine Absorber Overhead Cooler, A2-EA1510 ............................................. 7-8 7.4.9 Lean/Rich Exchanger, A2-EA1511A/B ........................................................... 7-8 7.4.10 Stripper Reboiler, A2-EA1512A/B .................................................................. 7-8
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Table of Contents 7.4.11 Stripper Reflux Condenser, A2-EC1511......................................................... 7-8 7.4.12 Lean Amine Cooler, A2-EC1510 .................................................................... 7-8 7.4.13 Wash Water Feed Knock-Out Drum, A2-FA1510 ........................................... 7-8 7.4.14 Amine Absorber Feed Knock-Out Drum, A2-FA1511 ..................................... 7-9 7.4.15 Amine Absorber Overhead Knock-Out Drum, A2-FA1512 ............................. 7-9 7.4.16 Rich Amine Flash Drum, A2-FA1513 ............................................................. 7-9 7.4.17 Stripper Reflux Accumulator, A2-FA1514..................................................... 7-10 7.4.18 Stripper Reboiler Condensate Pot, A2-FA1515A/B ...................................... 7-10 7.4.19 ATU Skim Oil Sump, A2-FA1516 ................................................................. 7-10 7.4.20 ATU Skim Oil Pump Sump, A2-FA1517A/B ................................................. 7-10 7.4.21 ATU Amine Drips Tank, A2-FA1580............................................................. 7-11 7.4.22 MDEA Storage Tank, A2-FB1580 ................................................................ 7-11 7.4.23 Wash Water Filter, A2-FD1510A/B ............................................................... 7-11 7.4.24 Rich Amine Filter, A2-FD1511A/B ................................................................ 7-11 7.4.25 Lean Amine Filter, A2-FD1512 ..................................................................... 7-11 7.4.26 Lean Amine Carbon Filter, A2-FD1513 ........................................................ 7-12 7.4.27 Lean Amine After-Filter, A2-FD1514 ............................................................ 7-12 7.4.28 ATU Amine Drips Filter, A2-FD1580 ............................................................ 7-12 7.4.29 Wash Water Pump, A2-GA1510A/B ............................................................. 7-13 7.4.30 Lean Amine Pump, A2-GA1511A/B ............................................................. 7-13 7.4.31 ATU Skim Oil Pump, A2-GA1512A/B ........................................................... 7-13 7.4.32 Rich Amine Pump, A2-GA1513A/B .............................................................. 7-13 7.4.33 Lean Amine Booster Pump, A2-GA1514A/B ................................................ 7-13 7.4.34 Stripper Reflux Pump, A2-GA1515A/B ......................................................... 7-13 7.4.35 MDEA Transfer Pump, A2-GA1580.............................................................. 7-14 7.5 INSTRUMENTATION AND CONTROL SYSTEMS ............................................. 7-15 7.5.1 Treated Fuel Gas H2S Analyzer ................................................................... 7-15 7.5.2 ATU Emergency Shutdown Systems ........................................................... 7-15 7.6 PROCESS PRINCIPLES AND OPERATING TECHNIQUES ............................. 7-19 7.6.1 Amine Absorber Operation ........................................................................... 7-19 7.6.2 Stripper Operation ........................................................................................ 7-22 7.6.3 Amine Water Balance ................................................................................... 7-24 7.6.4 Amine Loss ................................................................................................... 7-27 7.6.5 Operation at Low Flow Rates ....................................................................... 7-29 7.7 PRECOMMISSIONING PROCEDURES ............................................................. 7-30 7.7.1 Preliminary Check-out .................................................................................. 7-30 7.7.2 Shutdown System Check-out ....................................................................... 7-31 7.7.3 Leak Testing the Process Piping and Equipment ......................................... 7-31
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Table of Contents 7.7.4 Washing the Wash Water System ................................................................ 7-33 7.7.5 Washing the Amine System ......................................................................... 7-38 7.7.6 Purging the Low Pressure Columns ............................................................. 7-50 7.8 STARTUP PROCEDURES.................................................................................. 7-52 7.8.1 Wash Water and Amine Systems ................................................................. 7-52 7.8.2 Sour Fuel Gas Flow to the Columns............................................................. 7-53 7.9 SHUTDOWN PROCEDURES ............................................................................. 7-56 7.9.1 Planned Shutdown - ATU ............................................................................ 7-57 7.9.2 Planned Shutdown - ATU and ARU ............................................................. 7-60 7.9.3 Emergency Shutdown .................................................................................. 7-62 7.9.4 Effects of Shutdowns and Outages in Other Systems.................................. 7-63 7.10 ANALYTICAL PROCEDURES ............................................................................ 7-64 7.10.1 General Procedures for Analyzing ATU/ARU Solvent, ................................. 7-64 7.10.2 Determination of Amine Concentration in ATU/ARU Solvent ....................... 7-68 7.10.3 Determination of Total Acid Gas Loading in ATU/ARU Solvent ................... 7-70 7.10.4 Determination of H2S and CO2 Loading in ATU/ARU Solvent ...................... 7-72 7.10.5 Determination of Foaming Tendency of ATU/ARU Solvent .......................... 7-76 7.10.6 H2S Conc. in Amine Absorber Ovhd by the Tutweiler Method ..................... 7-78 7.10.7 H2S Conc. in Amine Absorber Ovhd Using Gas Detector Tubes ................. 7-79 8. SOUR WATER STRIPPING ......................................................................................... 8-1 8.1 PURPOSE OF SYSTEM ....................................................................................... 8-1 8.2 SAFETY ................................................................................................................. 8-1 8.3 PROCESS DESCRIPTION.................................................................................... 8-2 8.3.1 General ........................................................................................................... 8-2 8.3.2 Sour Water Collection..................................................................................... 8-2 8.3.3 Sour Water Stripping ...................................................................................... 8-3 8.4 EQUIPMENT DESCRIPTION ................................................................................ 8-5 8.4.1 Sour Water Stripper, A2-DA1520 ................................................................... 8-5 8.4.2 Sour Water Stripper Packing and Internals, A2-DB1520 ................................ 8-5 8.4.3 Stripper Trays, A2-DB1521 ............................................................................ 8-5 8.4.4 SWS Cross Exchanger, A2-EA1520 .............................................................. 8-5 8.4.5 Sour Water Stripper Reboiler, A2-EA1521 ..................................................... 8-6 8.4.6 SWS Quench Water Cooler, A2-EC1520 ....................................................... 8-6 8.4.7 SWS Bottoms Cooler, A2-EC1521 ................................................................. 8-6 8.4.8 Sour Water Flash Drum, A2-FA1520.............................................................. 8-6 8.4.9 SWS Skim Oil Sump, A2-FA1522 .................................................................. 8-7 8.4.10 SWS Skim Oil Pump Sump, A2-FA1523A/B .................................................. 8-7 8.4.11 Sour Water Tank, A2-FB1520 ........................................................................ 8-7
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Table of Contents 8.4.12 Sour Water Filter, A2-FD1520A/B .................................................................. 8-7 8.4.13 Sour Water Transfer Pump, A2-GA1520A/B .................................................. 8-7 8.4.14 SWS Feed Pump, A2-GA1521A/B ................................................................. 8-8 8.4.15 SWS Quench Water Pump, A2-GA1522A/B .................................................. 8-8 8.4.16 SWS Bottoms Pump, A2-GA1523A/B ............................................................ 8-8 8.4.17 SWS Skim Oil Pump, A2-GA1524A/B ............................................................ 8-8 8.5 INSTRUMENTATION AND CONTROL SYSTEMS ............................................... 8-9 8.5.1 SWS Shutdowns and Alarms ......................................................................... 8-9 8.6 PROCESS PRINCIPLES AND OPERATING TECHNIQUES ............................. 8-11 8.6.1 SWS Stripper Operation ............................................................................... 8-11 8.6.2 Quench Water Circulation ............................................................................ 8-12 8.6.3 pH Control .................................................................................................... 8-13 8.7 PRECOMMISSIONING PROCEDURES ............................................................. 8-14 8.7.1 Preliminary Check-out .................................................................................. 8-14 8.7.2 Washing the Sour Water System ................................................................. 8-15 8.8 STARTUP PROCEDURES.................................................................................. 8-19 8.8.1 Initial Startup of the SWS ............................................................................. 8-19 8.8.2 Normal Startup of the SWS .......................................................................... 8-23 8.9 SHUTDOWN PROCEDURES ............................................................................. 8-29 8.9.1 Planned Shutdown ....................................................................................... 8-29 8.9.2 Effects of Shutdowns and Outages in Other Systems.................................. 8-31 9. SULFUR RECOVERY .................................................................................................. 9-4 9.1 PURPOSE OF SYSTEM ....................................................................................... 9-4 9.2 SAFETY ................................................................................................................. 9-4 9.3 PROCESS DESCRIPTION.................................................................................... 9-5 9.3.1 Overview......................................................................................................... 9-5 9.3.2 General ........................................................................................................... 9-6 9.3.3 Feed Gas Processing ..................................................................................... 9-6 9.3.4 Thermal Processing........................................................................................ 9-7 9.3.5 Catalytic Processing ....................................................................................... 9-8 9.3.6 Air Control System.......................................................................................... 9-9 9.3.7 Molten Sulfur Handling ................................................................................. 9-10 9.3.8 Steam Production ......................................................................................... 9-10 9.4 EQUIPMENT DESCRIPTION .............................................................................. 9-11 9.4.1 Reactor Furnace, A2-BA1530 (A2-BA1540) ................................................. 9-11 9.4.2 Acid Gas Burner Assembly, A2-BA1531 (A2-BA1541) ................................ 9-12 9.4.3 Acid Gas Knock-Out Drum, A2-FA1530 (A2-FA1540) ................................. 9-12 9.4.4 SWS Gas Knock-Out Drum, A2-FA1531 (A2-FA1541) ................................ 9-12
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Table of Contents 9.4.5 Reactor, A2-DC1530 (A2-DC1540) .............................................................. 9-13 9.4.6 Catalyst for Sulfur Plant Reactors, A2-MC1530 (A2-MC1540) ..................... 9-13 9.4.7 Acid Gas Preheater, A2-EA1530 (A2-EA1540) ............................................ 9-13 9.4.8 Sulfur Condenser, A2-EA1531 (A2-EA1541) ............................................... 9-13 9.4.9 Reactor No. 1 Feed Heater, A2-EA1532 (A2-EA1542) ................................ 9-14 9.4.10 Reactor No. 2 Feed Heater, A2-EA1533 (A2-EA1543) ................................ 9-14 9.4.11 Reactor No. 3 Feed Heater, A2-EA1534 (A2-EA1544) ................................ 9-15 9.4.12 Sulfur Surge Tank, A2-FB1530 (A2-FB1540) ............................................... 9-15 9.4.13 Acid Gas Knock-Out Drum Pump, A2-GA1530A/B (A2-GA1540A/B) .......... 9-16 9.4.14 SWS Gas Knock-Out Drum Pump, A2-GA1531A/B (A2-GA1541A/B) ......... 9-17 9.4.15 Sulfur Storage Tank Vent Ejector, A2-EE1530 (A2-EE1540) ....................... 9-17 9.4.16 Process Air Blower, A2-GB1530A/B (A2-GB1540A/B)................................. 9-18 9.4.17 Air Blower Suction Screen/Silencer, A2-FD1530A/B (A2-FD1540A/B) ........ 9-19 9.4.18 Process Air Vent Silencer, A2-FG1530A/B (A2-FG1540A/B) ....................... 9-19 9.4.19 Sulfur Drain Seal Assembly, A2-ME1530A-D (A2-ME1540A-D) .................. 9-19 9.4.20 Refractory for Reactor Furnace and Waste Heat Boiler, A2-MR1530 (A2-MR1540) .............................................................................................................. 9-20 9.4.21 Ceramic Ferrules for Waste Heat Boiler, A2-MR1532 (A2-MR1542) ........... 9-20 9.4.22 Refractory for Waste Heat Boiler, A2-MR1533 (A2-MR1543) ...................... 9-20 9.4.23 Refractory for Sulfur Condenser, A2-MR1534 (A2-MR1544) ....................... 9-20 9.4.24 Refractory for Reactor, A2-MR1535 (A2-MR1545) ...................................... 9-21 9.4.25 Rainshield for Reactor Furnace, A2-ME1531 (A2-ME1541) ........................ 9-21 9.4.26 Ceramic Ferrule for Reactor Furnace, A2-MR1531 (A2-MR1541) ............... 9-21 9.4.27 Waste Heat Boiler, A2-BF1530 (A2-BF1540) ............................................... 9-22 9.5 INSTRUMENTATION AND CONTROL SYSTEMS ............................................. 9-24 9.5.1 SRU Air:Acid Gas Ratio Control Loop .......................................................... 9-24 9.5.2 Acid Gas Burner Management System ........................................................ 9-30 9.5.3 Process Air Blower Controls ......................................................................... 9-34 9.5.4 Reactor Furnace Temperature Control......................................................... 9-39 9.5.5 Knock-Out Drum Pump Control .................................................................... 9-41 9.5.6 "Ride-Through" System Considerations ....................................................... 9-41 9.5.7 Boiler Low-Low Level S/D Transmitter Testing ............................................ 9-44 9.5.8 SRU Emergency Shutdown Systems ........................................................... 9-46 9.6 PROCESS PRINCIPLES AND OPERATING TECHNIQUES ............................. 9-56 9.6.1 Equipment Damage ...................................................................................... 9-56 9.6.2 Cold Catalyst Bed Startup ............................................................................ 9-58 9.6.3 Sulfur Solidification ....................................................................................... 9-60 9.6.4 Ammonia Salt Formation .............................................................................. 9-61
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Table of Contents 9.6.5 Catalyst Fouling ............................................................................................ 9-62 9.6.6 Operation of SRUs in Parallel....................................................................... 9-62 9.6.7 Process air Blower Operation ....................................................................... 9-65 9.6.8 Reactor Furnace Temperature ..................................................................... 9-70 9.6.9 Ammonia Destruction Considerations .......................................................... 9-73 9.6.10 Sulfur Recovery Efficiency............................................................................ 9-76 9.6.11 Operation at Low Flow Rates ....................................................................... 9-78 9.6.12 Pressure Drop Surveys ................................................................................ 9-82 9.6.13 Boiler Water Treatment ................................................................................ 9-84 9.7 PRECOMMISSIONING PROCEDURES ............................................................. 9-86 9.7.1 Preliminary Check-out .................................................................................. 9-86 9.7.2 Shutdown System Check-out ....................................................................... 9-87 9.7.3 Leak Testing the Process Piping and Equipment ......................................... 9-88 9.7.4 Purging the Inlet Knock-Out Drums .............................................................. 9-93 9.7.5 Commissioning Fuel Gas and Instrument Air to the Process ....................... 9-95 9.7.6 Commissioning Nitrogen to the Process ...................................................... 9-99 9.7.7 Commissioning the Sulfur Surge Tank Heating and Ventilation ................. 9-102 9.7.8 Pre-filling the Sulfur Drain Seal Assemblies ............................................... 9-104 9.8 STARTUP PROCEDURES................................................................................ 9-105 9.8.1 Initial Firing / Refractory Cure-out............................................................... 9-105 9.8.2 Amine Acid Gas Flow ................................................................................. 9-117 9.8.3 SWS Gas Flow ........................................................................................... 9-124 9.8.4 Routing SRU Tailgas to the TGCU ............................................................. 9-127 9.8.5 Normal Startup - Cold System .................................................................... 9-129 Normal Startup - Hot System...................................................................... 9-146 9.8.6 9.8.7 Firing Supplemental Fuel Gas .................................................................... 9-158 9.9 SHUTDOWN PROCEDURES ........................................................................... 9-164 9.9.1 Planned Shutdown - No Reactor Entry....................................................... 9-165 9.9.2 Planned Shutdown for Reactor Entry ......................................................... 9-170 9.9.3 Shutting Down When Boiler Tubes Are Leaking ........................................ 9-180 9.9.4 Emergency Shutdown ................................................................................ 9-181 9.9.5 Effects of Shutdowns and Outages in Other Systems................................ 9-183 9.10 ANALYTICAL PROCEDURES .......................................................................... 9-187 9.10.1 Procedure for Sampling and Titrating with a Tutweiler Apparatus ............. 9-187 9.10.2 H2S Concentration in Acid Gas by the Tutweiler Method ........................... 9-189 9.10.3 H2S and SO2 Concentration in Tailgas by the Tutweiler Method ................ 9-192 9.10.4 Tailgas Analysis Table................................................................................ 9-196 9.10.5 Tailgas Analysis Operating Chart ............................................................... 9-197
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Table of Contents 9.10.6 Essential Apparatus for Tutweiler Analysis ................................................ 9-199 9.10.7 Materials for Tutweiler Analysis .................................................................. 9-200 9.10.8 H2S and SO2 Conc. in Tailgas Using Gas Detector Tubes ......................... 9-200 9.11 ADJUSTING STACKMATCH® IGNITOR/PILOTS ............................................. 9-205 10.
SULFUR DEGASSING, STORAGE & LOADING .................................................. 10-3
10.1 PURPOSE OF SYSTEM ..................................................................................... 10-3 10.2 SAFETY ............................................................................................................... 10-4 10.3 PROCESS DESCRIPTION.................................................................................. 10-5 10.4 EQUIPMENT DESCRIPTION .............................................................................. 10-7 10.4.1 Sulfur Degassing Reactor, A2-DC1550 ........................................................ 10-7 10.4.2 Sulfur Storage Tank, A2-FB1550 ................................................................. 10-7 10.4.3 Sulfur Feed Pump, A2-GA1532A/B (A2-GA1542A/B) .................................. 10-8 10.4.4 Sulfur Loading Pump, A2-GA1550A/B ......................................................... 10-8 10.4.5 Degassing Air Blower, A2-GB1550A/B ......................................................... 10-9 10.4.6 Bed Support and Limiter for Sulfur Degassing Reactor, A2-DC1551 ........... 10-9 10.4.7 Degassed Sulfur Drain Seal Assembly, A2-ME1550.................................... 10-9 10.5 INSTRUMENTATION AND CONTROL SYSTEMS ........................................... 10-11 10.5.1 Sulfur Feed Rate Control ............................................................................ 10-11 10.5.2 Degassing Air Flow..................................................................................... 10-12 10.5.3 Sulfur Degassing Unit Startup Interlock ...................................................... 10-13 10.5.4 Snuffing Steam ........................................................................................... 10-13 10.5.5 Sulfur Loading ............................................................................................ 10-14 10.5.6 Sulfur Loading Pump Local Stop Switches................................................. 10-17 10.5.7 Sulfur Degassing Shutdown System .......................................................... 10-18 10.5.8 Sulfur Loading ESD System ....................................................................... 10-21 10.6 PROCESS PRINCIPLES AND OPERATING TECHNIQUES ........................... 10-23 10.6.1 Equipment Damage .................................................................................... 10-23 10.6.2 Degassing Air Blower Operation ................................................................ 10-26 10.6.3 Sulfur Solidification ..................................................................................... 10-29 10.6.4 Sulfur Pumping ........................................................................................... 10-29 10.7 PRECOMMISSIONING PROCEDURES ........................................................... 10-31 10.7.1 Preliminary Check-out ................................................................................ 10-31 10.7.2 Commissioning the Heating and Ventilation Systems ................................ 10-32 10.7.3 Purging the Sulfur Degassing Reactor ....................................................... 10-37 10.8 STARTUP PROCEDURES................................................................................ 10-40 10.8.1 Initial Startup of the Sulfur Degassing Unit ................................................. 10-40 10.8.2 Normal Startup of the Sulfur Degassing System ........................................ 10-46 10.8.3 Initial Sulfur Loading Operation .................................................................. 10-51
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Table of Contents 10.8.4 Normal Sulfur Loading Operation ............................................................... 10-53 10.9 SHUTDOWN PROCEDURES ........................................................................... 10-54 10.9.1 Planned Shutdown - No Reactor Entry....................................................... 10-54 10.9.2 Planned Shutdown for Reactor Entry ......................................................... 10-55 10.9.3 Shutdown for Tank Entry ............................................................................ 10-57 11.
TAILGAS CLEANUP .............................................................................................. 11-1
11.1 PURPOSE OF SYSTEM ..................................................................................... 11-1 11.2 SAFETY ............................................................................................................... 11-2 11.3 PROCESS DESCRIPTION.................................................................................. 11-3 11.3.1 General ......................................................................................................... 11-3 11.3.2 Tailgas Hydrogenation/Hydrolysis ................................................................ 11-3 11.3.3 Process Gas Cooling .................................................................................... 11-4 11.3.4 Gas Contacting ............................................................................................. 11-5 11.3.5 Solvent Regeneration Section ...................................................................... 11-6 11.3.6 Steam Production/Consumption ................................................................... 11-7 11.4 EQUIPMENT DESCRIPTION .............................................................................. 11-8 11.4.1 TGCU Quench Column, A2-DA1560 ............................................................ 11-8 11.4.2 TGCU Quench Column Packing, A2-DB1560 .............................................. 11-8 11.4.3 TGCU Contactor, A2-DA1561 ...................................................................... 11-8 11.4.4 TGCU Contactor Packing & Internals, A2-DB1561 ...................................... 11-8 11.4.5 TGCU Stripper, A2-DA1562 ......................................................................... 11-9 11.4.6 TGCU Stripper Trays, A2-DB1562 ............................................................... 11-9 11.4.7 TGCU Reactor, A2-DC1560 ....................................................................... 11-10 11.4.8 TGCU Stripper Reflux Accumulator, A2-FA1560 ....................................... 11-10 11.4.9 Catalyst for TGCU Reactor, A2-MC1560 ................................................... 11-10 11.4.10 TGCU Stripper Reboiler Condensate Pot, A2-FA1562 ........................... 11-10 11.4.11 TGCU Reactor Feed Heater, A2-EA1560 ............................................... 11-11 11.4.12 TGCU Waste Heat Reclaimer, A2-EA1561 ............................................ 11-11 11.4.13 TGCU Quench Water Trim Cooler, A2-EA1562A/B ................................ 11-11 11.4.14 TGCU Lean/Rich Exchanger, A2-EA1564 .............................................. 11-11 11.4.15 TGCU Stripper Reboiler, A2-EA1565 ..................................................... 11-12 11.4.16 TGCU Lean Amine Trim Cooler, A2-EA1563 ......................................... 11-12 11.4.17 TGCU Quench Water Cooler, A2-EC1560 ............................................. 11-12 11.4.18 TGCU Stripper Reflux Condenser, A2-EC1562 ...................................... 11-12 11.4.19 TGCU Lean Amine Cooler, A2-EC1561 ................................................. 11-12 11.4.20 TGCU Quench Water Pump, A2-GA1560A/B......................................... 11-13 11.4.21 TGCU Rich Amine Pump, A2-GA1561A/B ............................................. 11-14 11.4.22 TGCU Stripper Reflux Pump, A2-GA1563A/B ........................................ 11-14
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SULFUR BLOCK
Table of Contents 11.4.23 TGCU Lean Amine Pump, A2-GA1562A/B ............................................. 11-14 11.4.24 TGCU Start-Up Blower, A2-GB1560 ....................................................... 11-14 11.4.25 Refractory for TGCU Reactor, A2-MR1560 ............................................ 11-15 11.4.26 TGCU Reactor Feed Mixer, A2-ME1560 ................................................ 11-16 11.4.27 TGCU Quench Water Filter, A2-FD1560A/B .......................................... 11-16 11.4.28 TGCU Rich Amine Filter, A2-FD1562A/B ............................................... 11-16 11.4.29 TGCU Lean Amine Filter, A2-FD1563 .................................................... 11-17 11.4.30 TGCU Amine Carbon Filter, A2-FD1564 ................................................ 11-17 11.4.31 TGCU Amine After-Filter, A2-FD1565 .................................................... 11-17 11.4.32 pH Meter Sample Filter, A2-FD1561A/B ................................................. 11-17 11.5 INSTRUMENTATION AND CONTROL SYSTEMS ........................................... 11-18 11.5.1 TGCU Reactor Feed Control Loops ........................................................... 11-18 11.5.2 Hydrogen and Hydrogen Sulfide Analyzer, A2-AE15858/A2-AE15859 ...... 11-23 11.5.3 Boiler Low-Low Level S/D Transmitter Testing .......................................... 11-24 11.5.4 Tailgas Switching Valve Controls ............................................................... 11-26 11.5.5 TGCU Shutdown System ........................................................................... 11-33 11.6 PROCESS PRINCIPLES AND OPERATING TECHNIQUES ........................... 11-39 11.6.1 Equipment Damage .................................................................................... 11-39 11.6.2 Catalyst Fouling .......................................................................................... 11-40 11.6.3 TGCU Reactor Operation ........................................................................... 11-41 11.6.4 TGCU Catalyst ........................................................................................... 11-43 11.6.5 TGCU Start-Up Blower Operation .............................................................. 11-44 11.6.6 TGCU Quench Column Operation.............................................................. 11-45 11.6.7 TGCU Contactor Operation ........................................................................ 11-48 11.6.8 TGCU Stripper Operation ........................................................................... 11-52 11.6.9 TGCU Amine Water Balance...................................................................... 11-55 11.6.10 TGCU Amine Loss .................................................................................. 11-59 11.6.11 Operation at Low Flow Rates.................................................................. 11-60 11.6.12 Pressure Drop Surveys ........................................................................... 11-61 11.6.13 Boiler Water Treatment ........................................................................... 11-63 11.7 PRECOMMISSIONING PROCEDURES ........................................................... 11-64 11.7.1 Preliminary Check-out ................................................................................ 11-64 11.7.2 Shutdown System Check-out ..................................................................... 11-65 11.7.3 Commissioning Nitrogen and Utility Air to the Process .............................. 11-66 11.7.4 Commissioning Hydrogen to the Process .................................................. 11-72 11.7.5 Leak Testing the Process Piping and Equipment ....................................... 11-75 11.7.6 Washing the Quench Water System .......................................................... 11-79 11.7.7 Washing the Amine System ....................................................................... 11-85
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SULFUR BLOCK
Table of Contents 11.7.8 Purging the Low Pressure TGCU Columns ................................................ 11-97 11.8 STARTUP PROCEDURES.............................................................................. 11-102 11.8.1 Initial Startup of the TGCU ....................................................................... 11-102 11.8.2 Pre-Sulfiding the TGCU Catalyst .............................................................. 11-107 11.8.3 Routing SRU Tailgas to the TGCU ........................................................... 11-115 11.8.4 Quench Water and Amine Systems ......................................................... 11-122 11.8.5 Process Gas Flow to the TGCU Columns ................................................ 11-124 11.8.6 Normal Startup of the TGCU .................................................................... 11-128 11.9 SHUTDOWN PROCEDURES ......................................................................... 11-144 11.9.1 Planned Shutdown - No Reactor Entry..................................................... 11-145 11.9.2 Planned Shutdown for Reactor Entry ....................................................... 11-151 11.9.3 Shutting Down When Boiler Tubes Are Leaking ...................................... 11-158 11.9.4 Special Precaution During Shutdowns ..................................................... 11-159 11.9.5 Emergency Shutdown .............................................................................. 11-163 11.9.6 Effects of Shutdowns and Outages in Other Systems.............................. 11-164 11.10 ANALYTICAL PROCEDURES ..................................................................... 11-167 11.10.1 General Procedures for Analyzing TGCU Solvent, ............................... 11-167 11.10.2 Determination of Amine Concentration in TGCU Solvent ..................... 11-171 11.10.3 Determination of Total Acid Gas Loading in TGCU Solvent ................. 11-173 11.10.4 Determination of H2S and CO2 Loading in TGCU Solvent .................... 11-175 11.10.5 Determination of Foaming Tendency of TGCU Solvent ........................ 11-179 11.10.6 H2S Conc. in TGCU Contactor Ovhd by the Tutweiler Method ............. 11-181 11.10.7 H2S Conc. in TGCU Contactor Ovhd Using Gas Detector Tubes ......... 11-182 11.10.8 Monitoring the Performance Level of TGCU Catalyst ........................... 11-185 12.
TAILGAS THERMAL OXIDIZER ............................................................................ 12-2
12.1 PURPOSE OF SYSTEM ..................................................................................... 12-2 12.2 SAFETY ............................................................................................................... 12-2 12.3 PROCESS DESCRIPTION.................................................................................. 12-3 12.4 EQUIPMENT DESCRIPTION .............................................................................. 12-4 12.4.1 Thermal Oxidizer, A2-BA1570 ...................................................................... 12-4 12.4.2 Thermal Oxidizer Burner, A2-BA1571 .......................................................... 12-4 12.4.3 Steam Knock-out Drum, A2-FA1570 ............................................................ 12-4 12.4.4 Thermal Oxidizer Air Blower, A2-GB1570A/B .............................................. 12-4 12.4.5 Thermal Oxidizer Vent Stack, A2-ME1570 ................................................... 12-5 12.4.6 Refractory for Thermal Oxidizer, A2-MR1570 .............................................. 12-5 12.4.7 Thermal Oxidizer Waste Heat Boiler, A2-BF1570 ........................................ 12-5 12.5 INSTRUMENTATION AND CONTROL SYSTEMS ............................................. 12-7 12.5.1 Thermal Oxidizer Burner Management System ........................................... 12-7
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Table of Contents 12.5.2 Thermal Oxidizer Temperature Control ...................................................... 12-10 12.5.3 Thermal Oxidizer Excess Oxygen Control.................................................. 12-10 12.5.4 Boiler Low-Low Level S/D Transmitter Testing .......................................... 12-11 12.5.5 Thermal Oxidizer Shutdown System .......................................................... 12-13 12.6 PROCESS PRINCIPLES AND OPERATING TECHNIQUES ........................... 12-18 12.6.1 Equipment Damage .................................................................................... 12-18 12.6.2 Effect of Upstream Operations on the Thermal Oxidizer ............................ 12-21 12.6.3 "Swapping" Air Blowers During Operation .................................................. 12-23 12.6.4 Boiler Water Treatment .............................................................................. 12-24 12.7 PRECOMMISSIONING PROCEDURES ........................................................... 12-26 12.7.1 Preliminary Check-out ................................................................................ 12-26 12.7.2 Shutdown System Check-out ..................................................................... 12-27 12.7.3 Commissioning Fuel Gas, Pilot Gas, and I/A to the Process ..................... 12-28 12.8 STARTUP PROCEDURES................................................................................ 12-33 12.8.1 Initial Firing / Refractory Cure-out............................................................... 12-33 12.8.2 Normal Startup ........................................................................................... 12-48 12.9 SHUTDOWN PROCEDURES ........................................................................... 12-58 12.9.1 Planned Shutdown - No Entry .................................................................... 12-59 12.9.2 Planned Shutdown for Entry ....................................................................... 12-61 12.9.3 Shutting Down When Boiler Tubes Are Leaking ........................................ 12-65 12.9.4 Emergency Shutdown ................................................................................ 12-66 12.9.5 Effects of Shutdowns and Outages in Other Systems................................ 12-69
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SULFUR BLOCK
1. INTRODUCTION THE INFORMATION IN THESE GUIDELINES IS CONFIDENTIAL. SOME OF THE PROCESSES, DESIGNS, EQUIPMENT, AND/OR PROCEDURES DESCRIBED HEREIN ARE PROPRIETARY AND/OR LICENSED BY BP AMOCO CORPORATION, SHELL GLOBAL SOLUTIONS (US) INC., UOP LLC. AND/OR ORTLOFF ENGINEERS, LTD. DISCLOSURE, REPRODUCTION, OR USE OF THESE GUIDELINES FOR ANY REASON OTHER THAN OPERATION OF THIS FACILITY IS IN VIOLATION OF WRITTEN SECRECY AGREEMENTS. These Operating Guidelines have been prepared by Ortloff Engineers, Ltd. as a guide for the initial operation of the new Sulfur Block at Samsung Total Petrochemicals Co., Ltd.’s Daesan No. 2 Aromatics Complex. The new Sulfur Block consists of an Amine Treating Unit (ATU), an Amine Regeneration Unit (ARU), a Sour Water Stripper (SWS), two parallel Sulfur Recovery Units (SRUs), and a common Sulfur Degassing Unit (SDU), Tailgas Cleanup Unit (TGCU) and Tailgas Thermal Oxidation Unit (TTO). These units are to process sour gas and sour water streams to remove the contained sulfur and produce treated fuel gas for consumption in the complex, treated water safe for reuse or disposal, and commercial grade molten sulfur for sales. These guidelines contain information concerning the design, startup, operation, and shutdown of the new facility to assist plant personnel in developing familiarity with and understanding of the process, equipment, and overall plant operation, and to supplement equipment manufacturers' operating instructions. We have tried to present all of the information from an operations viewpoint by breaking the facility into separate systems for the ease of understanding and startup. The information for the systems is organized as follows, although some systems will not require every category: 1.
Purpose of System
2.
Safety
3.
Process Description
4.
Instrumentation and Control Systems
5.
Operating Principles and Techniques
6.
Precommissioning Procedures
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Introduction
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 7.
Startup Procedures
8.
Shutdown Procedures
9.
Setpoints (Controllers, Alarms, Shutdowns, PCVs, PSVs)
10.
Analytical Procedures
The instructions in these guidelines are based on past experience with similar plants and equipment. They are to be used as guidelines for developing detailed operating procedures customized for your plant and its actual operating conditions. These instructions are not intended in any way to supersede or supplant operating procedures and safety practices established by Samsung Total Petrochemicals Co., Ltd., nor are they intended to be used independently of equipment manufacturers’ operating instructions. In preparing these instructions, it has been assumed that all startup and operating personnel have been trained in and are knowledgeable of the operating instructions provided by the manufacturers of the equipment included in this facility. It is expected that Samsung Total Petrochemicals Co., Ltd. will revise and improve upon the operating instructions in this manual as operating experience is gained, and as required to incorporate any changes resulting from Samsung Total Petrochemicals Co., Ltd.'s Process Safety Management program. Update and maintenance of this manual is Samsung Total Petrochemicals Co., Ltd.'s responsibility and is not within Ortloff's scope of responsibility. Operating values and numbers quoted in this manual are design values. They are presented to enable the operator to have a "ball park" idea of plant operating values. Actual plant operating conditions may deviate from the design figures, yet yield satisfactory operations and products. We recommend that operating parameters such as temperatures, pressures, and flow rates be recorded on a routine basis. Good data, properly gathered and maintained, form a valuable base for plant studies and performance evaluations.
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SULFUR BLOCK
Table of Contents 2. GENERAL SAFETY ..................................................................................................... 2-1 2.1 DEFINITION OF TERMS ....................................................................................... 2-1 2.2 HYDROGEN SULFIDE (H2S) ................................................................................ 2-3 2.2.1 Description and Properties ............................................................................. 2-3 2.2.1.1 General.................................................................................................... 2-3 2.2.1.2 Toxicity Information ................................................................................. 2-3 2.2.1.3 Permissible Exposure Limits ................................................................... 2-3 2.2.1.4 Odor ........................................................................................................ 2-3 2.2.1.5 Physical Data .......................................................................................... 2-3 2.2.1.6 Reactivity Data ........................................................................................ 2-4 2.2.1.7 Corrosivity Data ....................................................................................... 2-5 2.2.1.8 Water Solubility ....................................................................................... 2-5 2.2.1.9 Other Characteristics............................................................................... 2-5 2.2.1.10 Fire and Explosion Hazard ...................................................................... 2-6 2.2.1.11 Life Hazard .............................................................................................. 2-6 2.2.2 First Aid .......................................................................................................... 2-7 2.2.3 Precautions (remember these facts) .............................................................. 2-8 2.2.4 Good Work Practices...................................................................................... 2-9 2.3 SULFUR DIOXIDE (SO2) ..................................................................................... 2-10 2.3.1 Description and Properties ........................................................................... 2-10 2.3.1.1 General.................................................................................................. 2-10 2.3.1.2 Toxicity Information ............................................................................... 2-10 2.3.1.3 Permissible Exposure Limits ................................................................. 2-10 2.3.1.4 Odor ...................................................................................................... 2-11 2.3.1.5 Physical Data ........................................................................................ 2-11 2.3.1.6 Reactivity Data ...................................................................................... 2-11 2.3.1.7 Corrosivity Data ..................................................................................... 2-12 2.3.1.8 Water Solubility ..................................................................................... 2-12 2.3.1.9 Fire and Explosion Hazard .................................................................... 2-12 2.3.1.10 Life Hazard ............................................................................................ 2-12 2.3.2 First Aid ........................................................................................................ 2-13 2.3.3 Precautions................................................................................................... 2-14 2.4 SULFUR .............................................................................................................. 2-15 2.4.1 Description and Properties ........................................................................... 2-15 2.4.1.1 General.................................................................................................. 2-15 2.4.1.2 Toxicity Information ............................................................................... 2-15 2.4.1.3 Permissible Exposure Limits ................................................................. 2-15
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 2.4.1.4 Odor ...................................................................................................... 2-15 2.4.1.5 Physical Data ........................................................................................ 2-15 2.4.1.6 Reactivity Data ...................................................................................... 2-16 2.4.1.7 Corrosivity Data ..................................................................................... 2-19 2.4.1.8 Other Characteristics............................................................................. 2-19 2.4.1.9 Fire and Explosion Hazard .................................................................... 2-19 2.4.1.10 Life Hazard ............................................................................................ 2-20 2.4.2 Precautions................................................................................................... 2-20 2.4.3 Fire Fighting.................................................................................................. 2-21 2.5 AMMONIA (NH3) .................................................................................................. 2-22 2.5.1 Description and Properties ........................................................................... 2-22 2.5.1.1 General.................................................................................................. 2-22 2.5.1.2 Toxicity Information ............................................................................... 2-22 2.5.1.3 Permissible Exposure Limits ................................................................. 2-22 2.5.1.4 Odor ...................................................................................................... 2-22 2.5.1.5 Physical Data ........................................................................................ 2-23 2.5.1.6 Reactivity Data ...................................................................................... 2-23 2.5.1.7 Corrosivity Data ..................................................................................... 2-25 2.5.1.8 Water Solubility ..................................................................................... 2-25 2.5.1.9 Fire and Explosion Hazard .................................................................... 2-25 2.5.1.10 Life Hazard ............................................................................................ 2-25 2.5.2 First Aid ........................................................................................................ 2-26 2.5.3 Precautions................................................................................................... 2-26 2.6 METHYLDIETHANOLAMINE (MDEA, CH3-N-(CH2-CH2-OH)2)........................... 2-28 2.6.1 Description and Properties ........................................................................... 2-28 2.6.1.1 General.................................................................................................. 2-28 2.6.1.2 Toxicity Information ............................................................................... 2-28 2.6.1.3 Permissible Exposure Limits ................................................................. 2-28 2.6.1.4 Odor ...................................................................................................... 2-28 2.6.1.5 Physical Data ........................................................................................ 2-28 2.6.1.6 Reactivity Data ...................................................................................... 2-28 2.6.1.7 Corrosivity Data ..................................................................................... 2-29 2.6.1.8 Water Solubility ..................................................................................... 2-29 2.6.1.9 Fire and Explosion Hazard .................................................................... 2-29 2.6.1.10 Life Hazard ............................................................................................ 2-29 2.6.2 First Aid ........................................................................................................ 2-29 2.6.3 Precautions................................................................................................... 2-30 2.7 SODIUM HYDROXIDE (CAUSTIC SODA, NAOH) ............................................. 2-31 2.7.1 Description and Properties ........................................................................... 2-31 2.7.1.1 General.................................................................................................. 2-31
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SULFUR BLOCK 2.7.1.2 Toxicity Information ............................................................................... 2-31 2.7.1.3 Permissible Exposure Limits ................................................................. 2-31 2.7.1.4 Odor ...................................................................................................... 2-31 2.7.1.5 Physical Data ........................................................................................ 2-32 2.7.1.6 Reactivity Data ...................................................................................... 2-32 2.7.1.7 Corrosivity Data ..................................................................................... 2-34 2.7.1.8 Water Solubility ..................................................................................... 2-34 2.7.1.9 Fire and Explosion Hazard .................................................................... 2-34 2.7.1.10 Life Hazard ............................................................................................ 2-35 2.7.2 First Aid ........................................................................................................ 2-35 2.7.3 Precautions................................................................................................... 2-36 2.8 SULFUR PLANT SAFETY ................................................................................... 2-37 2.8.1 Hydrogen Sulfide .......................................................................................... 2-37 2.8.2 Sulfur Dioxide ............................................................................................... 2-37 2.8.3 Sulfur Storage Tank...................................................................................... 2-38 2.8.3.1 Poisonous Gases .................................................................................. 2-38 2.8.3.2 Explosion and Fire................................................................................. 2-38 2.9 HOT WORK ......................................................................................................... 2-39 2.10 VESSEL ENTRY.................................................................................................. 2-39 2.11 PIPES AND LINES .............................................................................................. 2-41 2.11.1 General ......................................................................................................... 2-41 2.11.2 Before Breaking Lines .................................................................................. 2-42 2.11.3 When Breaking Lines ................................................................................... 2-42 2.12 ELECTRICAL EQUIPMENT ................................................................................ 2-42 2.12.1 Electrical Repairs.......................................................................................... 2-43 2.12.2 Grounding ..................................................................................................... 2-43 2.12.3 Conduit, Cables, and Wires .......................................................................... 2-43 2.12.4 Fuses ............................................................................................................ 2-43 2.12.5 Switching ...................................................................................................... 2-43 2.12.6 Hand Tools and Portable Equipment............................................................ 2-44 2.12.7 Miscellaneous ............................................................................................... 2-44 2.13 BOILERS AND OTHER DIRECT-FIRED EQUIPMENT ...................................... 2-45 2.13.1 General ......................................................................................................... 2-45 2.13.2 Boilers........................................................................................................... 2-45 2.13.2.1 Repair and Maintenance ....................................................................... 2-45 2.13.2.2 Operations ............................................................................................. 2-46 2.13.3 Direct-Fired Equipment................................................................................. 2-46 2.14 LABORATORY SAFETY ..................................................................................... 2-47 2.14.1 Good Housekeeping ..................................................................................... 2-47 2.14.2 Equipment .................................................................................................... 2-47
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 2.14.3 Chemical Sorting and Identification .............................................................. 2-47 2.14.4 Chemical Handling ....................................................................................... 2-48 2.15 MATERIAL SAFETY DATA SHEETS (MSDS) .................................................... 2-49 A. Hydrogen Sulfide B.
Sulfur Dioxide
C.
Sulfur
D.
Ammonia
E.
Methyldiethanolamine
F.
Sodium Hydroxide
G.
UOP/ESM S-2001 Sulfur Conversion Catalyst
H.
Criterion 234 Tailgas Treating Catalyst
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SULFUR BLOCK
2. GENERAL SAFETY General The safety information published herein is for guidance only and is not intended to supersede or replace your company's safety procedures program where a conflict of terminology or procedure may exist. Safety Considerations An employee's knowledge of the hazardous chemicals and compounds with which he will be working is one of the most basic prerequisites for his own safety, the safety of others, and the protection of equipment. All employees should review the following information occasionally to refresh their memories. New employees should study this information until it is thoroughly understood.
2.1
Definition of Terms A.
Auto-Ignition Temperature The minimum temperature to which a substance (the substance may be solid, liquid, or gaseous) must be heated to ignite independent of other ignition sources.
B.
Flammability Limits (explosive limits) When flammable vapors are mixed in air, there is a minimum concentration below which the propagation of flame does not occur upon contact with a source of ignition. There is also a maximum concentration above which propagation of flame does not occur. These boundary line concentrations of vapor in air are called flammable or explosive limits. Many people are familiar with lower and upper flammability limits in connection with engine carburetors which, when adjusted improperly, will prevent the engines from running if the fuel mixture is either too "lean" or too "rich".
C.
Flash Point Flash point is the lowest temperature of a liquid at which sufficient vapors are evolved to form an ignitable mixture with air.
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK D.
Specific Gravity (solids and liquids) Specific gravity of solids and liquids is the ratio of the weight of any solid or liquid to the weight of an equal volume of water. Therefore, if the specific gravity of a substance is a number less than one, it is lighter than water, and if the number is greater than one, it is heavier than water.
E.
Specific Gravity (gases) Specific gravity of gases is the ratio of weight of any gas to the weight of an equal volume of air. Therefore, if the specific gravity of a gas is a number less than one, it is lighter than air, and if the number is greater than one, it is heavier than air.
F.
Specific Volume Specific volume of a substance is the volume of a unit mass of the substance, i.e., the reciprocal of its density. The units used in this manual are cubic feet per pound, unless otherwise noted.
G.
Toxicity Toxicity is the ability of a chemical or compound to produce injury once it reaches a susceptible site in or on the body.
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SULFUR BLOCK
2.2
Hydrogen Sulfide (H2S)
2.2.1 2.2.1.1
Description and Properties General Hydrogen sulfide is a colorless, very flammable, highly toxic gas.
2.2.1.2
Toxicity Information LCLo:
600 PPM / 30 minutes
(death of inhalation)
humans
after
LCLo:
800 PPM / 5 minutes
(death of inhalation)
humans
after
LCLo (Lethal Concentration Low) is the lowest concentration of a substance in air which has been reported to have caused death in humans or animals. In other words, exposure to 600 PPM of H2S for 30 minutes or to 800 PPM of H2S for 5 minutes can cause death. 2.2.1.3
Permissible Exposure Limits TLV:
10 PPM in air
TLV (Threshold Limit Value) is the highest level of exposure to a toxic chemical at which no deleterious effect is noted. The American Conference of Government Industrial Hygienists (ACGIH) has set such levels for human exposure in industry. OSHA now uses this 10 PPM limit as the maximum allowable concentration for continuous exposure during an eight hour working day. 2.2.1.4
Odor Higher In low concentrations, H2S smells like rotten eggs. concentrations quickly damage the ability to smell and cannot be detected by the characteristic rotten egg odor.
2.2.1.5
Physical Data a. b. c. d. e. f.
Issued 30 August 2011
Melting Point: Boiling Point: Lower Explosive Limit: Upper Explosive Limit: Auto-Ignition Temperature: Vapor Specific Gravity:
General Safety
-122°F (-86°C) -77°F (-61°C) 4.3% H2S (by volume) vapor in air 46% H2S (by volume) vapor in air 500°F (260°C) 1.2 (heavier than air)
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SULFUR BLOCK 2.2.1.6
Reactivity Data Hydrogen sulfide is dangerously reactive with the following substances: Formula
Name
C2H4O
acetaldehyde
BaO + Hg2O + air
barium oxide + mercury oxide in air
BaO + NiO + air
barium oxide + nickel monoxide in air
BaO2
barium peroxide
BrF5
bromine pentafluoride
C6H4BrN2Cl
p-bromobenzene diazonium chloride
ClO
chlorine monoxide
ClF3
chlorine trifluoride
CrO3
chromium trioxide (chromic anhydride, chromic acid)
Cu
copper
Fe2O3·nH2O
di-iron trioxide hydrate
F2
fluorine hydrated iron oxide lead dioxide (lead peroxide)
PbO2
metal oxides metals HNO3
nitric acid
NCl3
nitrogen trichloride
NF3
nitrogen trifluoride
NI3
nitrogen triiodide oxidizing materials
OF2
oxygen difluoride
ClO3F
perchloryl fluoride
C6H5N2Cl
phenyl diazonium chloride rust
Issued 30 August 2011
Ag2C2N2O2
silver fulminate
NaOH + CaO
soda lime (a mixture of sodium hydroxide and calcium oxide)
Na
sodium
NaOH + CaO + air
sodium hydroxide + calcium oxide (lime) in air
Na2O2
sodium peroxide
General Safety
Page 2-4
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 2.2.1.7
2.2.1.8
Corrosivity Data a.
H2S readily attacks copper and most copper alloys (brass, bronze, etc.), so such materials should not be exposed to the process gases in an SRU, or to the atmosphere around an SRU.
b.
H2S can cause sulfide stress cracking (SSC) in a variety of materials as discussed in NACE Standard Material Requirements MR-01-75, "Sulfide Stress Cracking Resistant Metallic Materials for Oilfield Equipment". Most sulfur plant equipment operates at sufficiently low pressure to be outside the conditions at which SSC would be expected and so is not constructed in accordance with NACE MR-01-75. The upstream equipment (including the Knock-Out drums and/or pumps in the SRU, in some cases) is generally constructed of carbon steel and stress relieved, or is constructed of austenitic stainless steel, in accordance with NACE MR-01-75.
c.
At elevated temperature (generally, above 650°F/343°C), H2S will cause rapid corrosion of carbon steel even under low pressure conditions like those in a sulfur plant. Such steel surfaces are usually protected by refractory linings, water cooling, and/or coating the steel surface with a protective coating (such as Alonizing).
d.
H2S is considered to be non-corrosive to aluminum, glass, and Teflon®.
Water Solubility Hydrogen sulfide is soluble in water. At 60°F (15°C), approximately 3 parts (by volume) H2S will dissolve in one part water.
2.2.1.9
Other Characteristics Hydrogen sulfide is soluble in liquid sulfur and many hydrocarbons. Many porous materials, such as muds and residues, tend to absorb hydrogen sulfide. Increased temperature or mechanical disturbance tends to release the absorbed gas.
Issued 30 August 2011
General Safety
Page 2-5
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 2.2.1.10
Fire and Explosion Hazard H2S is a dangerous fire hazard when exposed to an ignition source.
2.2.1.11
Life Hazard Hydrogen sulfide is extremely toxic even in very low concentrations. The maximum allowable concentration for continuous exposure during an eight hour working day (per current OSHA regulations) is 10 parts per million by volume, or 0.001%. Hydrogen sulfide poisoning is not cumulative like mercury, lead, and some other materials. Repeated exposure to small doses will not have the same effect as exposure to one long dose. Hydrogen sulfide is highly irritating to the eyes and mucous membranes. When inhaled, hydrogen sulfide is both an irritant and an asphyxiant. Low concentrations of 20-150 PPM cause irritation of the eyes; slightly higher concentrations may cause irritation of the upper respiratory tract, and, if exposure is prolonged, pulmonary edema may result. (Edema is a condition in which irritated tissues swell, collect fluid, and slowly excrete a watery fluid, in this case into the lungs or voice box.) The irritation action has been explained on the basis that H2S combines with the alkali present in moist surface tissues to form sodium sulfide, a caustic compound. (This compound is used by the leather industry to help remove hair from animal hides.) With higher concentrations, the action of H2S on the nervous system becomes more prominent. A 30 minute exposure to 500 PPM results in headache, dizziness, excitement, staggering gait, diarrhea, and dysuria, followed sometimes by bronchitis or bronchopneumonia. The action on the nervous system is, with small amounts, one of depression; in larger amounts, it stimulates; and, with very high amounts, the respiratory center is paralyzed. Exposure to 800-1000 PPM may be fatal in 30 minutes, and higher concentrations are instantly fatal. Fatal hydrogen sulfide poisoning may occur even more rapidly than that following exposure to a similar concentration of hydrogen cyanide. H2S does not combine with the hemoglobin of the blood; its asphyxiant action is due to paralysis of the respiratory center (which is usually the cause of death).
Issued 30 August 2011
General Safety
Page 2-6
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK With repeated exposures to low concentrations, conjunctivitis, photophobia, corneal bullae, tearing, pain, and blurred vision are the most common findings. Higher concentrations may cause rhinitis, bronchitis, and occasionally pulmonary edema. Exposure to very high concentrations results in immediate death. Chronic poisoning results in headache, inflammation of the conjunctivae and eyelids, digestive disturbances, loss of weight, and general debility. H2S is a common air contaminant. It is an insidious poison since sense of smell may be fatigued and fail to give warning of high concentrations. The following table from the U.S. Bureau of Mines represents the degree of inhalation hazard with varying concentrations of hydrogen sulfide: HYDROGEN SULFIDE INHALATION HAZARDS PERIOD OF EXPOSURE
EXPOSURE PPM
PERCENT
10
0.001
Slight symptoms after exposure of several hours
70-150
0.007-0.015
Maximum concentration that can be inhaled for one hour without serious consequences
170-300
0.017-0.03
Dangerous after exposure of thirty minutes to one hour
400-500
0.04-0.05
Fatal in exposures of thirty minutes or less
600 & above 0.06 & above
Maximum allowable prolonged exposure
concentration
for
Concentrations exceeding 0.1% are considered rapidly fatal.
2.2.2
First Aid Anyone overcome by H2S should be removed immediately to fresh air, preferably a warm, well ventilated room. If breathing has stopped, begin artificial respiration immediately. The arm lift-back pressure method of artificial respiration is recommended. Since H2S paralyzes the respiratory system, time is very important. Administer oxygen (or carbogen, 97% oxygen and 3% carbon dioxide) if available and if someone trained with oxygen inhalation apparatus is present. Attempts to give oxygen by someone unfamiliar with the use of the apparatus may result in the loss of valuable time or may be harmful to the patient.
Issued 30 August 2011
General Safety
Page 2-7
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK For severe irritation of the eyes, hold the lids open and pour clean water over the eyeball and lids (or use an eye irrigation fountain). Wash thoroughly in this fashion for 15 minutes. A physician, preferably an eye specialist, should be summoned immediately.
2.2.3
Issued 30 August 2011
Precautions (remember these facts) 1.
Odor is not a reliable test for the presence of hydrogen sulfide.
2.
Since hydrogen sulfide is heavier than air, it settles when released into the atmosphere and becomes more concentrated near the ground and in low places.
3.
Water at room temperature will dissolve approximately three times its volume of hydrogen sulfide. Heating or agitation of the water will cause the hydrogen sulfide to be released.
4.
Hydrogen sulfide dissolves in liquid sulfur and is a hazard in storage tanks and pits.
5.
H2S is a serious fire and explosion hazard.
6.
Low concentrations of hydrogen sulfide hinder the ability of an individual to think clearly and function properly.
7.
H2S concentrations higher than 0.06% can be fatal within 30 minutes and concentrations higher than 0.1% are rapidly fatal.
8.
In the Sulfur Block, H2S will always be present in the following locations: a.
In most of the process gas streams.
b.
In the rich and lean amine streams in the Amine Treating Unit.
c.
In the rich and lean amine streams in the Amine Regeneration Unit.
d.
In the Sour Water Stripper liquid streams.
e.
In the Acid Gas Knock-Out Drum and the SWS Knock-Out Drum liquids, TGCU quench water, TGCU solvent, and the TGCU Stripper reflux.
f.
In the amine acid gas, the TGCU recycle gas, and the SWS gas (the feed gases for the Sulfur Recovery Unit).
General Safety
Page 2-8
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
2.2.4
g.
In all of the Sulfur Recovery, Tailgas Cleanup, Tailgas Thermal Oxidation, and Sulfur Degassing system process gases, with the exception of the incinerated vent gas.
h.
In the vapors from the molten sulfur storage tank.
Good Work Practices Know the above facts and use caution when working around any equipment that may contain H2S. If H2S will be a hazard in any operation:
Issued 30 August 2011
1.
Make adequate plans to cope with any situation that may develop.
2.
Adequate respiratory protective equipment is essential; have it available and use it. Persons who must work in an atmosphere contaminated with H2S should use either a self-contained breathing unit or a hose mask with a hand-operated blower.
3.
Observe the wind direction. Stay upwind if possible and warn others who may be downwind.
4.
Keep ignition sources away from the area.
5.
Two men should always be present when opening a flange or performing any other work where the release of H2S is possible.
6.
When one man is working in an area of potential H2S exposure, the other man should concentrate on the wind direction and on the action of the man performing the work. At the first sign of loss of coordination or illogical action, the worker should be removed immediately to fresh air. If a man is being overcome by H2S, he will be outwardly sluggish and poorly coordinated (although inwardly he will be peacefully unconcerned) and he will then begin illogical actions as his mind begins to imagine things. Any sign of actions that are out of the ordinary is a last minute warning.
General Safety
Page 2-9
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
2.3
Sulfur Dioxide (SO2)
2.3.1 2.3.1.1
Description and Properties General Sulfur dioxide is a colorless, nonflammable, highly toxic gas.
2.3.1.2
Toxicity Information LCLo:
400 PPM / 1 minute
(death of inhalation)
humans
after
LCLo (Lethal Concentration Low) is the lowest concentration of a substance in air which has been reported to have caused death in humans or animals. In other words, exposure to 400 PPM of SO2 for 1 minute can cause death. TCLo:
3 PPM / 5 days
(pulmonary system effects on humans after inhalation)
TCLo:
4 PPM / 1 minute
(pulmonary system effects on man after inhalation)
TCLo (Toxic Concentration Low) is the lowest concentration of a substance in air to which humans or animals have been exposed for any given period of time that has produced any toxic effect in humans or produced a carcinogenic, neoplastigenic, or teratogenic effect in animals or humans. In other words, exposure to 3 PPM SO2 for 5 days or to 4 PPM SO2 for 1 minute have both been reported to have toxic effects on the human pulmonary system. 2.3.1.3
Permissible Exposure Limits TLV:
2 PPM in air
TLV (Threshold Limit Value) is the highest level of exposure to a toxic chemical at which no deleterious effect is noted. The American Conference of Government Industrial Hygienists (ACGIH) has set such levels for human exposure in industry. OSHA regulations set a limit of 5 PPM TWA (Time Weighted Average) concentration for continuous exposure during an eight hour working day.
Issued 30 August 2011
General Safety
Page 2-10
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 2.3.1.4
Odor Sulfur dioxide has a pungent, suffocating odor that can be detected at very low concentrations, 0.3 to 1.0 PPM, possibly by taste rather than odor.
2.3.1.5
Physical Data a. b. c. d. e. f.
2.3.1.6
Melting Point: Boiling Point: Lower Explosive Limit: Upper Explosive Limit: Auto-Ignition Temperature: Vapor Specific Gravity:
-104°F (-76°C) 14°F (-10°C) N/A (SO2 will not burn) N/A N/A 2.2 (heavier than air)
Reactivity Data Sulfur dioxide is dangerously reactive with the following substances: Formula
Name
C3H4O
acrolein
Al
aluminum
CsHC2
cesium hydrogencarbide
Cs2O
cesium oxide
x-ClO3
chlorates
ClF3
chlorine trifluoride
Cr
chromium
FeO
ferrous oxide
F2
fluorine lithium acetylene carbide diammino
Issued 30 August 2011
Mn
manganese
KHC2
potassium carbide
KClO3
potassium chlorate
Rb2C2
rubidium carbide
Na
sodium
Na2C2
sodium carbide
SnO
tin monoxide
General Safety
Page 2-11
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK Sulfur dioxide is incompatible with the following substances: Formula
Name halogens or interhalogens
LiNO3
lithium nitrate
x-C2H
metal acetylides metal oxides metals polymeric tubing sodium hydride
NaH
2.3.1.7
2.3.1.8
Corrosivity Data a.
Dry SO2 causes only mild corrosion of carbon steel and stainless steel.
b.
Wet SO2 (sulfurous acid) is very corrosive to carbon steel and most stainless steels. Certain alloy materials (Carpenter ® 20Cb-3 , for instance) are relatively impervious to attack by wet SO2.
c.
SO2 is considered to be non-corrosive to graphite, glass, and Teflon®.
Water Solubility Sulfur dioxide will dissolve readily in water to form a weak solution of sulfurous acid (H2SO3). At 60°F (15°C), about 50 parts (by volume) SO2 will dissolve in one part water.
2.3.1.9
Fire and Explosion Hazard None
2.3.1.10
Life Hazard Like hydrogen sulfide, sulfur dioxide is extremely toxic in very low concentrations. The serious life threat is through paralysis of the respiratory system. The maximum allowable concentration for continuous exposure during an eight hour working day (per current OSHA regulations) is 5 parts per million by volume, or 0.0005%. Sulfur dioxide is highly irritating to skin, eyes, and mucous membranes. When inhaled, sulfur dioxide is very irritating and can cause pulmonary distress. This gas is dangerous to the eyes, as it
Issued 30 August 2011
General Safety
Page 2-12
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK causes irritation at 20 PPM and inflammation of the conjunctiva. It has a suffocating odor and is a corrosive and poisonous material. In moist air or fogs, it combines with water to form sulfurous acid, but is only slowly oxidized to sulfuric acid. Concentrations of 6-12 PPM cause immediate irritation of the nose and throat, while 0.3-1 PPM can be detected by the average individual, possibly by taste rather than by sense of smell. 3 PPM has an easily noticeable odor and 20 PPM is the least amount which is irritating to the eyes. 10,000 PPM is an irritant to moist areas of the skin within a few minutes of exposure. SO2 chiefly affects the upper respiratory tract and the bronchi. It may cause edema of the lungs or glottis, and can produce respiratory paralysis. (Edema is a condition in which irritated tissues swell, collect fluid, and slowly excrete a watery fluid, in this case into the lungs or voice box.) This material is so irritating that it provides its own warning of toxic concentrations. 400-500 PPM is immediately dangerous to life, and 50-100 PPM is considered to be the maximum permissible concentration for exposures of 30-60 minutes. Excessive exposures to high enough concentrations of this material can be fatal. Its toxicity is comparable to that of hydrogen chloride. However, less than fatal concentrations can be borne for fair periods of time with no apparent permanent damage. It is used as a fumigant, insecticide and fungicide, and a chemical preservative food additive. It is a common air contaminant.
2.3.2
First Aid In cases of inhalation, remove the victim to fresh air and begin artificial respiration immediately if breathing has ceased. The arm lift-back pressure method of artificial respiration is recommended. If an oxygen apparatus is available, oxygen (100%) should be administered only by someone trained in the use of the apparatus. Preferably, oxygen should be administered against a positive exhalation pressure of 1.25 inches of water. Oxygen inhalation must be continued as long as necessary to maintain the normal color of the skin and mucous membranes. In cases of severe exposure, the patient should breathe 100% oxygen under positive exhalation pressure for 30 minute periods every hour for at least 3 hours.
Issued 30 August 2011
General Safety
Page 2-13
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK If there are no signs of lung congestion at the end of this period, and if the breathing is easy and the color is good, oxygen inhalation may be discontinued. Throughout this time, the patient should be kept comfortably warm, but not hot. For irritation of the eyes, flush them with large amounts of warm water for at least 15 minutes. It is advisable to irrigate the eyes gently with water at room temperature in order to minimize additional pain and discomfort. Take the patient to a physician, preferably an eye specialist, at once.
2.3.3
Precautions Special precautions should be observed when fighting sulfur fires. Sulfur fires should be approached from an upwind direction if possible, and respiratory equipment should be used in the case of larger fires or when fires are in enclosed areas. SO2 is always present in the following locations:
Issued 30 August 2011
1.
In all of the Sulfur Recovery Unit process gases downstream of the Reactor Furnace, up through and including the TGCU Reactor in the TGCU Unit.
2.
In the stack or flare gases in any process where sulfur or hydrogen sulfide is being burned, including the Thermal Oxidizer.
3.
In the vapors from the molten sulfur storage tank.
4.
In the fumes from sulfur fires.
General Safety
Page 2-14
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
2.4
Sulfur
2.4.1 2.4.1.1
Description and Properties General Sulfur is a yellow solid at normal ambient temperatures. However, it is normally handled in bulk quantities in plant operations as a liquid.
2.4.1.2
Toxicity Information Sulfur is nontoxic. Sulfur dust in air can produce irritation of the human eye at concentrations of 6 PPM or above, resulting in its classification as a nuisance dust. Repeated inhalation can cause irritation to the mucous membranes.
2.4.1.3
Permissible Exposure Limits There are no standards or regulations concerning sulfur.
2.4.1.4
Odor Pure sulfur is odorless.
2.4.1.5
Physical Data a. b. c.
d. e. f.
Issued 30 August 2011
Melting Point: 246°F (119°C) Boiling Point: 832°F (444°C) Auto-Ignition Temperature: 450°F (232°C) for liquid sulfur 374°F (190°C) for sulfur dust suspended in air Flash Point: 405°F (207°C) Liquid Specific Gravity: 1.8 (almost twice as heavy as water) Color Pure sulfur is bright yellow when solid. Sulfur produced by Claus sulfur plants may be contaminated with hydrocarbons, causing the color to be orange, green, tan, brown, gray, or black. The color of liquid sulfur ranges from bright yellow to dark orange (almost red), depending on its temperature.
General Safety
Page 2-15
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 2.4.1.6
Reactivity Data Sulfur can react violently with the following substances: Formula
Name alkali metal nitrides
Issued 30 August 2011
Al
aluminum
Al + Cu
aluminum + copper
Al + Nb2O5
aluminum + niobium pentoxide
NH3
ammonia
NH4NO3
ammonium nitrate
NH4ClO4
ammonium perchlorate
Ba(BrO3)2·H2O
barium bromate
BaC2
barium carbide
Ba(ClO3)2·H2O
barium chlorate
Ba(IO3)2
barium iodate
B
boron
BrF5
bromine pentafluoride
BrF3
bromine trifluoride
Cd
cadmium
Ca
calcium
Ca(BrO3)2·H2O
calcium bromate
CaC2
calcium carbide
Ca(ClO3)2
calcium chlorate
Ca(ClO)2
calcium hypochlorite
Ca(IO3)2
calcium iodate
Ca3P2
calcium phosphide
Ca + VO + H2O
calcium + vanadium oxide + water carbides
Cs3N
cesium nitride
C + impurities
charcoal
ClO2
chlorine dioxide
ClO
chlorine monoxide
ClF3
chlorine trifluoride
ClO3
chlorine trioxide
Cr(ClO)2
chromium oxychloride (chromyl chloride)
CrO3
chromium trioxide (chromic acid) anhydride, chromic
Cu + x-ClO3
copper + chlorates
As2S3
diarsenic trisulfide
General Safety
Page 2-16
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK Formula
Name
Cl2O
dichlorine monoxide
(C2H5)2O
diethyl ether fiberglass + iron filings fluorine
F2
halogenates halogenites halogens Ag7NO11
heptasilver nitrate octaoxide
CxHy
hydrocarbons
In
indium interhalogens
IF5
iodine pentafluoride
IO5
iodine pentoxide
C
lampblack (carbon black)
Pb(ClO3)2
lead chlorate
PbCl2
lead chloride
Pb(ClO2)2
lead chlorite
PbCrO4
lead chromate
PbO2
lead dioxide (lead peroxide)
Li
lithium
Li + NH3
lithium dissolved in ammonia
Li2C2
lithium carbide
Mg
magnesium
Mg(BrO3)2·6H2O
magnesium bromate
Mg(ClO3)2
magnesium chlorate
Mg(IO3)2·4H2O
magnesium iodate
Hg(NO3)2·H2O
mercuric nitrate
HgO
mercury(II) oxide (mercuric oxide)
Hg2O
mercury(I) oxide (mercurous oxide)
x-C2H
metal acetylides of carbides
x-(ClO3)n
metal chlorates
x-(zO3)n
metal halogenates
x-On
metal oxides metals
Issued 30 August 2011
RbC2H
monorubidium acetylide (rubidium acetylene carbide)
Ni
nickel
General Safety
Page 2-17
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK Formula
Name
NO2
nitrogen dioxide
Os
osmium oxidants
Issued 30 August 2011
Pd
palladium
x-(ClO4)n
inorganic perchlorates
x-(MnO4)n
permanganates
P
phosphorus (phosphorus, red)
P4
phosphorus, white (phosphorus, yellow)
P2O3
phosphorus trioxide
K
potassium
KBrO3
potassium bromate (bromic acid)
KClO3
potassium chlorate
KClO
potassium chlorite (potassium hypochlorite)
KIO3
potassium iodate
KNO3 + As2S3
potassium nitrate (saltpeter) + arsenic sulfide
K3N
potassium nitride
KClO4
potassium perchlorate
KMnO4
potassium permanganate
K + SnI4
potassium + tin(IV) iodide (stannic iodide)
Rh
rhodium
Rb
rubidium
Se
selenium
SeC2
selenium carbide
AgBrO3
silver bromate
AgClO3
silver chlorate
AgClO2
silver chlorite
AgNO3
silver nitrate
Ag2O
silver oxide
Na
sodium
NaBrO3
sodium bromate
NaClO3
sodium chlorate
NaClO2
sodium chlorite
NaH
sodium hydride
NaIO3
sodium iodate
NaNO3 + charcoal
sodium nitrate + charcoal
Na2O2
sodium peroxide
General Safety
Page 2-18
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
2.4.1.7
Formula
Name
Na + SnI4
sodium + tin(IV) iodide (stannic iodide)
SrC2
strontium carbide
SrC2+ Se
strontium carbide + selenium
SCl2
sulfur dichloride
(C6H5)4Pb
tetraphenyl lead
Tl2O3
thallic oxide (thallium peroxide)
Th
thorium
ThC2
thorium carbide
Sn
tin
U
uranium
UC2
uranium carbide (uranium dicarbide)
Zn
zinc
Zn(BrO3)2·6H2O
zinc bromate
Zn(ClO3)2
zinc chlorate
Zn(IO3)2
zinc iodate
Corrosivity Data Dry sulfur is not corrosive but in the presence of moisture it will attack steel rapidly.
2.4.1.8
2.4.1.9
Other Characteristics a.
Both hydrogen sulfide and sulfur dioxide will dissolve in liquid sulfur.
b.
At temperatures up to about 317°F (158°C), the viscosity of pure liquid sulfur decreases as the temperature increases. As the temperature increases from 317°F to 370°F (158°C to 188°C), the viscosity of pure liquid sulfur rises rapidly to a tremendously high maximum, causing the liquid to become a dark, sticky, plastic material impossible to pump. However, sulfur produced by Claus sulfur plants contains dissolved H2S that lowers the viscosity of the molten sulfur so that fluidity is not normally a concern, regardless of the temperature.
Fire and Explosion Hazard a.
Solid Sulfur The primary hazard in handling solid sulfur results from the fact that sulfur dust suspended in the air ignites easily. Even though
Issued 30 August 2011
General Safety
Page 2-19
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK the explosion hazard is considered moderate, an explosion occurring in a confined area could cause considerable damage. Sulfur, being a very poor conductor of electricity, tends to develop static electric charges when it is in motion. Ignition of sulfur dust by static-caused sparks is not uncommon. Frictional heat in equipment has also been responsible for starting sulfur fires. b.
Liquid Sulfur The fire hazards of liquid sulfur result primarily from the low ignition point of sulfur and from the presence of hydrogen sulfide.
2.4.1.10
Life Hazard a.
Solid Sulfur Solid elemental sulfur is considered to be more of a nuisance dust with a very low toxicity. Occasionally, sulfur dust will irritate the inner surfaces of the eyelids.
b.
Molten Sulfur Molten sulfur is capable of inflicting severe burns.
2.4.2
Issued 30 August 2011
Precautions 1.
Employees operating equipment containing molten sulfur should wear clothing capable of protecting the chest and arms, trousers without cuffs, high top shoes, safety glasses with side shields, and heat resistant gloves. When making connections or other changes in molten sulfur piping, full-face shields (in addition to safety glasses) and leather protective clothing may be needed.
2.
Every reasonable step should be taken to minimize formation of dust during the handling of solid sulfur.
3.
Eliminate ignition sources where sulfur dust may be produced. Enclosed areas are considered Class II hazardous locations according to the United States National Electrical Code. Where static electricity is a hazard, equipment should be grounded.
4.
Eliminate ignition sources near liquid sulfur where H2S may be liberated.
General Safety
Page 2-20
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 5.
2.4.3
Issued 30 August 2011
Sulfur spills and drips should be cleaned up to avoid accumulations of sulfur. Sulfur dust should never be allowed to accumulate in buildings.
Fire Fighting 1.
Small sulfur fires may be extinguished by smothering them with dirt or sand or by using a fire extinguisher. Water is the most satisfactory extinguishing agent but should be used as a fine spray or fog. Steam smothering can be used in storage pits and in other relatively small enclosures. Carbon dioxide is also a satisfactory fire extinguishing agent.
2.
Sulfur fires should be approached very carefully, from the upwind side if possible, because burning sulfur emits highly toxic fumes of sulfur dioxide.
General Safety
Page 2-21
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
2.5
Ammonia (NH3)
2.5.1 2.5.1.1
Description and Properties General Ammonia is a colorless, flammable, toxic gas.
2.5.1.2
Toxicity Information LCLo:
5,000 PPM / 1 minute
(death of inhalation)
mammals
after
LCLo (Lethal Concentration Low) is the lowest concentration of a substance in air which has been reported to have caused death in humans or animals. In other words, exposure to 5,000 PPM of NH3 for 1 minute can cause death. TCLo:
20 PPM
(toxic and irritant effects on humans after inhalation)
TCLo (Toxic Concentration Low) is the lowest concentration of a substance in air to which humans or animals have been exposed for any given period of time that has produced any toxic effect in humans or produced a carcinogenic, neoplastigenic, or teratogenic effect in animals or humans. In other words, exposure to 20 PPM NH3 has been reported to have toxic and irritant effects on humans. 2.5.1.3
Permissible Exposure Limits TLV:
25 PPM in air
TLV (Threshold Limit Value) is the highest level of exposure to a toxic chemical at which no deleterious effect is noted. The American Conference of Government Industrial Hygienists (ACGIH) has set such levels for human exposure in industry. OSHA regulations set a limit of 50 PPM TWA (Time Weighted Average) concentration for continuous exposure during an eight hour working day. 2.5.1.4
Odor Ammonia has a pungent odor that can be detected at low concentrations, 20 to 50 PPM.
Issued 30 August 2011
General Safety
Page 2-22
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 2.5.1.5
Physical Data a. b. c. d. e. f.
2.5.1.6
Melting Point: Boiling Point: Lower Explosive Limit: Upper Explosive Limit: Auto-Ignition Temperature: Vapor Specific Gravity:
-108°F (-78°C) -28°F (-33°C) 15% NH3 (by volume) in air 28% NH3 (by volume) in air 1204°F (651°C) 0.6 (lighter than air)
Reactivity Data Ammonia is incompatible with the following substances: Formula
Name
C2H4O
acetaldehyde
C3H4O
acrolein
H8N2O8S2
ammonium peroxo disulfate
Sb
antimony
SbH3
antimony hydride
B
boron boron halides
BI3
boron triiodide
BrF5
bromine pentafluoride
HClO3
chloric acid
ClN3
chlorine azide
ClO
chlorine monoxide
ClF3
chlorine trifluoride
x-ClO2
chlorites
SiHxCl4-x
chlorosilane
CrO3
chromium trioxide (chromic anhydride, chromic acid)
CrCl2
chromyl chloride
Cl2O
dichlorine oxide
C2H4Cl2 + NH3 (liq)
ethylene dichloride + liquid ammonia
C2H4O
ethylene oxide
Au
gold
AuCl3
gold (III) chloride halogens
Issued 30 August 2011
C3N6Cl6
hexachloromelamine
H4N2 + Li, Na, etc.
hydrazine + alkali metals
HBr
hydrogen bromide (hydrobromic acid)
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK Formula
Name
HOCl
hypochlorous acid
H2O2
hydrogen peroxide
Mg(ClO4)2
magnesium perchlorate
Hg
mercury
HNO3
nitric acid
NO2
nitrogen dioxide (nitrogen peroxide)
N2O4
nitrogen tetraoxide
NCl3
nitrogen trichloride
NF3
nitrogen trifluoride
NO2Cl
nitryl chloride
OF2
oxygen difluoride
O2 + Pt
oxygen + platinum
P2O5
phosphorus pentoxide
P2O3
phosphorus trioxide
C6H3N3O7
picric acid
K + AsH3
potassium + arsine
KClO3
potassium chlorate
K3Fe(CN)6
potassium ferricyanide
K2Hg(CN)4
potassium mercuric cyanide
K + PH3
potassium + phosphine
K + NaNO2
potassium + sodium nitrite
Ag
silver
AgCl
silver chloride
AgNO3
silver nitrate
Ag2O
silver oxide
Na + CO
sodium + carbon monoxide
S
sulfur
SCl2
sulfur dichloride
TeCl4
tellurium chloride tellurium hydropentachloride
Issued 30 August 2011
(CH3)4N2COH2
tetramethyl ammonium amide
SOCl2
thionyl chloride
N3S4Cl
thiotrithiazyl chloride
C3H3N6Cl3
trichloromelamine
O3F2
trioxygen difluoride
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SULFUR BLOCK 2.5.1.7
2.5.1.8
Corrosivity Data a.
Iron and carbon steel are recommended for ammonia service.
b.
Moist ammonia will rapidly attack copper, tin, zinc, and their alloys.
c.
Mixtures of ammonia and hydrogen sulfide are often very corrosive to carbon and stainless steels when wet. The corrosivity appears to increase when hydrogen cyanide (HCN) is present. (Hydrogen cyanide is a common contaminant in the sour water processed in many refineries.)
d.
Ammonia is considered to be non-corrosive to glass and Teflon®.
Water Solubility Ammonia will dissolve very readily in water. At 60°F (15°C), about 800 parts (by volume) NH3 will dissolve in one part water.
2.5.1.9
Fire and Explosion Hazard Ammonia is a low fire hazard when exposed to heat or flame because it is difficult to ignite. It is a moderate explosion hazard when exposed to flame or fire. Air-ammonia mixtures can detonate in a fire.
2.5.1.10
Life Hazard Ammonia is toxic in moderate concentrations. However, its pungent odor will provide ample warning of its presence, so it is unlikely that an individual would unknowingly become overexposed. The maximum allowable concentration for continuous exposure during an eight hour working day (per current OSHA regulations) is 50 parts per million by volume, or 0.005%. Ammonia is highly irritating to the eyes and mucous membranes. When inhaled, ammonia is both an irritant and an asphyxiant, and can cause respiratory distress. This gas is dangerous to the eyes, as it causes irritation at 40-100 PPM. Prolonged exposure to 700 PPM or more can cause extensive injuries to the eyes - irritation, hemorrhages, swollen lids, corneal ulcers, even partial or total loss of sight. Ammonia will also irritate the skin, particularly if the skin is moist, to the point of causing chemical burns from prolonged exposure.
Issued 30 August 2011
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SULFUR BLOCK The life hazard from ammonia is due to its damage to the lungs when inhaled. This material is so irritating that it provides its own warning well below toxic concentrations. Ammonia can usually be detected at levels of 20-50 PPM. There will be noticeable irritation of the eyes and nasal passages when exposed to 100 PPM, severe irritation of the throat, nasal passages, and upper respiratory tract at 400 PPM, and severe eye irritation at 700 PPM. At 1700 PPM, there will be severe coughing and bronchial spasms, and an exposure of 30 minutes or less may be fatal. Concentrations of 5000 PPM and above are fatal almost immediately, causing serious edema of the lungs, strangulation, and asphyxiation. (Edema is a condition in which irritated tissues swell, collect fluid, and slowly excrete a watery fluid, in this case into the lungs.)
2.5.2
First Aid Anyone overcome by ammonia should be removed immediately to fresh air, preferably a warm, well-ventilated room. If breathing has stopped, begin artificial respiration immediately (by trained personnel only). The arm lift-back pressure method of artificial respiration is recommended. Be aware that excessive force during artificial respiration will further injure the lungs. Administer oxygen if available and if someone trained with oxygen inhalation apparatus is present. For severe irritation of the eyes, hold the lids open and pour clean water over the eyeball and lids (or use an eye irrigation fountain). Wash thoroughly in this fashion for 15 minutes. A physician, preferably an eye specialist, should be summoned immediately.
2.5.3
Precautions In this part of the complex, ammonia will usually be found mixed with hydrogen sulfide. Ammonia will always be present in the following locations:
Issued 30 August 2011
1.
In the process gas and liquid streams in the Sour Water Stripping Unit.
2.
In the Sour Water Stripper off-gas feeding the sulfur plant.
3.
In the SWS Gas Knock-Out Drum liquids, the TGCU quench water, and the TGCU Stripper reflux.
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SULFUR BLOCK 4.
Issued 30 August 2011
In the overhead gas from the TGCU Stripper, and possibly in the TGCU recycle gas.
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
2.6
Methyldiethanolamine (MDEA, CH3-N-(CH2-CH2-OH)2)
2.6.1 2.6.1.1
Description and Properties General MDEA is a colorless, viscous liquid.
2.6.1.2
Toxicity Information Ingestion of MDEA is moderately toxic, and may cause nausea, vomiting, and abdominal discomfort. Single dose oral toxicity is low. MDEA can cause moderate irritation of the eyes, with possible corneal damage. Prolonged or repeated exposure can cause skin irritation or burns. Inhalation of vapors is unlikely at room temperature due to its low vapor pressure. MDEA at elevated temperature may produce sufficient vapor to cause moderately severe eye and upper respiratory irritation.
2.6.1.3
Permissible Exposure Limits There are no standards or regulations concerning MDEA.
2.6.1.4
Odor MDEA has a slight odor of amine.
2.6.1.5
Physical Data a. b. c. d. e. f. g. h.
2.6.1.6
Melting Point: Boiling Point: Vapor Pressure: Flash Point: Lower Explosive Limit: Upper Explosive Limit: Specific Gravity: Color:
-6°F (-21°C) 477°F (247°C) <0.01 mm Hg @ 68°F (20°C) 260°F (127°C) not determined not determined 1.042 (about the same as water) Clear to light straw color
Reactivity Data MDEA is incompatible with strong oxidizers and strong acids. MDEA should not be allowed to contact sodium nitrite (NaNO2) or other nitrosating agents, as nitrosamines (suspected cancer-causing agents) could be formed.
Issued 30 August 2011
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 2.6.1.7
Corrosivity Data
2.6.1.8
a.
MDEA and MDEA-water solutions are generally non-corrosive to carbon and stainless steels.
b.
Acid gas (H2S and/or CO2) dissolved in MDEA-water solutions can cause appreciable corrosion of carbon steel, particularly in areas subjected to erosion.
c.
Copper, copper alloys, and galvanized steel should not be exposed to MDEA. Aluminum should not be exposed to MDEA at elevated temperatures.
d.
Oxygen will degrade MDEA by forming corrosive organic acids.
e.
MDEA is considered to be non-corrosive to glass, asbestos, Teflon®, and EPDM.
Water Solubility MDEA is completely soluble in water.
2.6.1.9
Fire and Explosion Hazard MDEA is considered a slight fire hazard when exposed to heat or flame.
2.6.1.10
Life Hazard The toxicity of MDEA is low. Ingestion of MDEA can cause nausea and vomiting. MDEA will irritate the skin and eyes, and can cause damage to the eyes. If heated, sufficient MDEA vapor may be evolved to irritate the nose and/or eyes.
2.6.2
First Aid If large amounts of MDEA are ingested, induce vomiting, then take the patient to a physician. If MDEA vapors are inhaled, remove the patient to fresh air. A physician should be consulted. In case of eye contact, flush the eyes with large amounts of water for at least 15 minutes. Take the patient to a physician, preferably an eye specialist, at once. In case of skin contact, flush the affected area with plenty of water. If exposure has produced a burn, it should be treated like a thermal burn,
Issued 30 August 2011
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SULFUR BLOCK with treatment based on the physician's judgment. Contaminated clothing should be removed and washed before reuse.
2.6.3
Issued 30 August 2011
Precautions 1.
When handling MDEA, employees should wear protective clothing resistant to MDEA. The choice of gloves, boots, apron, or full-body suit will depend on the tasks to be performed. Chemical-resistant goggles should always be worn.
2.
Good general ventilation should be sufficient for most operations. If vapor concentrations are high, use local exhaust ventilators.
3.
If irritation of the nose and/or respiratory system is experienced, use an approved air-purifying respirator.
4.
Minimize the exposure of MDEA to oxygen to avoid forming organic acids.
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SULFUR BLOCK
2.7
Sodium Hydroxide (Caustic Soda, NaOH)
2.7.1 2.7.1.1
Description and Properties General Pure sodium hydroxide is a white solid. When dissolved in water, NaOH forms a clear, colorless or water-white, strongly alkaline liquid.
2.7.1.2
Toxicity Information Sodium hydroxide has acute oral toxicity if ingested. It will cause severe burns, including perforation and scarring, on the mouth, throat, esophagus, and stomach, and death may result. Cases of squamous cell carcinoma of the esophagus have occurred years after ingestion. Sodium hydroxide, both solid and in solution, has a markedly corrosive action on all body tissues. Inhalation of dust or mist can cause injury to the entire respiratory tract. The effects of inhalation depend on the severity of the exposure, ranging from mild irritation of the mucous membranes to severe pneumonitis. Contact with the eyes may cause irritation and, with greater exposure, severe burns and possible blindness. Skin contact may cause burns, frequently with deep ulceration and scarring. Prolonged contact, even with dilute solutions, can cause tissue damage.
2.7.1.3
Permissible Exposure Limits TLV:
2 mg/m3 in air (approximately 2 PPM by weight)
TLV (Threshold Limit Value) is the highest level of exposure to a toxic chemical at which no deleterious effect is noted. The American Conference of Government Industrial Hygienists (ACGIH) has set such levels for human exposure in industry. OSHA regulations set a limit of 2 mg/m3 TWA (Time Weighted Average) concentration for continuous exposure during an eight hour working day. 2.7.1.4
Odor Sodium hydroxide has no odor, in pure form or when dissolved in water.
Issued 30 August 2011
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SULFUR BLOCK 2.7.1.5
Physical Data Solid Form a. b. c. d. e.
Melting Point: Boiling Point: Auto-Ignition Temperature: Flash Point: Specific Gravity:
f.
Color:
608°F (320°C) 2534°F (1390°C) Not combustible N/A 2.1 (more than twice as heavy as water) White
Water Solutions a. b. c. d. e. f.
2.7.1.6
Melting Point: Boiling Point: Auto-Ignition Temp.: Flash Point: Specific Gravity: Color:
25 wt% -2°F (-19°C) 232°F (111°C) Not combustible N/A 1.27 Colorless or water-white
50 wt% 50°F (10°C) 288°F (142°C) Not combustible N/A 1.53 Colorless or water-white
Reactivity Data Adding water to sodium hydroxide or sodium hydroxide solutions may cause localized overheating and spattering. Under the proper conditions, sodium hydroxide can react violently with the following substances:
Issued 30 August 2011
Formula
Name
C2H2O
acetaldehyde
C2H2O2
acetic acid
C2H6O3
acetic anhydride
C3H4O
acrolein
C3H3N
acrylonitrile
C3H6O
allyl alcohol
C3H5Cl
allyl chloride
Al
aluminum
ClF3
chlorine trifluoride
CHCl3 + CH3OH
chloroform + methanol
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK Formula
Name
C3H7ClO2
chlorohydrin (chlorhydrin)
C7H7ClO
4-chloro-2-methylphenol
C7H6ClNO2
chloronitrotoluene
ClHSO3
chlorosulfonic acid (chlorosulfuric acid)
C9H8O
cinnamaldehyde
Cu
copper
CN4
cyanogen azide
B2H6
diborane (boron hydride)
C2H2Cl2
1,2-dichloroethylene
C2H4F2
difluoroethane
C3H5NO
ethylene cyanohydrin (hydracrylonitrile)
C2H2O2
glyoxal
HCl
hydrochloric acid (hydrogen chloride)
HF
hydrofluoric acid (hydrogen fluoride)
C6H6O2
hydroquinone
Mg
magnesium
C4H2O3
maleic anhydride
CH3OH + C6H2Cl4
methanol + tetrachlorobenzene
C7H7NO3
4-methyl-2-nitrophenol 3-methyl-2-penten-4-yn-1-ol
HNO3
nitric acid
C2H5NO2
nitroethane (forms shock-sensitive salts)
CH3NO2
nitromethane (forms shock-sensitive salts)
CxH2x+1NO2
nitroparaffins (forms shock-sensitive salts)
C3H7NO2
nitropropane (forms shock-sensitive salts)
H2SO4 SO3
oleum (fuming sulfuric acid)
C5H12O
pentol
P
phosphorus
P2O5
phosphorus pentoxide
C3H4O2
ß-propiolactone (2-oxetanone) strong mineral or organic acids
Issued 30 August 2011
H2SO4
sulfuric acid
C6H2Cl4
1,2,4,5-tetrachlorobenzene
C4H8O
tetrahydrofuran
Sn
tin
C2H3Cl3O
1,1,1-trichloroethanol
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SULFUR BLOCK
2.7.1.7
2.7.1.8
Formula
Name
C2HCl3
trichloroethylene
CCl3NO2
trichloronitromethane
H2O
water
Zn
zinc
Zr
zirconium
Corrosivity Data a.
At ambient temperature, sodium hydroxide solutions will cause only slight corrosion of carbon steel.
b.
Carbon steel can experience caustic embrittlement and intergranular corrosion when exposed to sodium hydroxide solutions at elevated temperature. Stress relieving the carbon steel after fabrication may reduce the susceptibility to this.
c.
If sodium hydroxide solutions must be handled at elevated temperatures, special resistant alloys should be used. Nickel and copper are common components in such alloys.
d.
Aluminum, tin, zinc, and their alloys are rapidly attacked by sodium hydroxide solutions, and should not be allowed to come in contact with NaOH.
e.
Sodium hydroxide is considered to be non-corrosive to glass, natural rubber, EPDM, and Teflon®.
Water Solubility Sodium hydroxide will dissolve readily in water, with the amount depending on the solution temperature. If a solution of sodium hydroxide is cooled below its saturation temperature, it will precipitate solid hydrates. At 60°F (15°C), sodium hydroxide will dissolve in water to produce solutions exceeding 50 wt% NaOH.
2.7.1.9
Fire and Explosion Hazard Sodium hydroxide and its water solutions are not flammable. However, adding water to NaOH or solutions of NaOH can cause localized overheating due to its heat of dilution. Sodium hydroxide will generate gaseous hydrogen (which is flammable and/or explosive) when in contact with aluminum, copper, tin, zinc, and their alloys.
Issued 30 August 2011
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 2.7.1.10
Life Hazard Sodium hydroxide will cause damage to any tissue it contacts. It is acutely toxic if swallowed, causing severe burns and scarring to the mouth, throat, esophagus, and stomach, and may lead to death. Squamous cell carcinoma of the esophagus can occur years after the exposure. Contact with the skin, eyes, nose, or respiratory passages can result in severe burns and scarring. In the case of eye contact, blindness can occur rapidly.
2.7.2
First Aid If swallowed, do not induce vomiting - this will cause further damage to the throat and esophagus. Dilute by giving water to the patient immediately. Vinegar, 1% acetic acid solution, citrus fruit juices, or 5% citric acid solution may also be administered to help neutralize the alkaline solution. Follow this with milk, egg white in water, or milk of magnesia. Keep the patient warm and still, and summon a physician immediately. If dust or mist is inhaled, remove the patient to fresh air at once. If breathing has stopped, begin artificial respiration immediately. The air lift-back pressure method of artificial respiration is recommended. Keep the patient warm and still, and summon a physician immediately. In case of eye contact, immediately begin flushing the eyes with large amounts of water, preferably with an eye wash fountain. Continue flushing for at least 15 minutes, forcibly holding the eyelids apart and rotating the eyeball, to ensure complete irrigation of all eye and lid tissue. A physician, preferably an eye specialist, should be summoned immediately. In case of skin contact, immediately flush the affected areas with large amounts of water. If large areas of the body are contaminated, or if clothing has been penetrated to the skin, immediately use a safety shower, preferably removing clothing while under the shower. Continue flushing the areas for at least 15 minutes. If available, follow the water flush with a generous application of vinegar or 1% acetic acid solution to neutralize the residual NaOH. After the acid treatment, apply a good protective dressing as with any other burn and take the patient to a physician. Contaminated clothing should be washed before reuse. Contaminated leather articles (shoes, belts, etc.) should be discarded.
Issued 30 August 2011
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SULFUR BLOCK 2.7.3
Issued 30 August 2011
Precautions 1.
Employees should wear impervious rubber, neoprene, or vinyl gloves, boots, and overalls or full-body suits, plus tightly fitting goggles and face shields.
2.
If dust or mist is present, use an appropriate respirator.
3.
When diluting sodium hydroxide, use agitation (mixing) and add the concentrated sodium hydroxide to water at a controlled rate to control the heat of dilution and avoid spattering. Never add water to sodium hydroxide.
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SULFUR BLOCK
2.8
Sulfur Plant Safety
2.8.1
Hydrogen Sulfide Hydrogen sulfide will be present in all of the process gas streams flowing in the ATU, the SWS, the SRU, the SDU, the TGCU, and the Thermal Oxidizer. The hydrogen sulfide content will decrease as the sulfur is extracted from the gas stream and will reach its lowest concentration in the incinerated vent gas. Some hydrogen sulfide will be dissolved in the liquid sulfur produced. Review the characteristics of this poisonous gas often, and be fully familiar with them. Avoid all possibility of exposure to hydrogen sulfide. Plan and think ahead, so that when there is a possibility of hydrogen sulfide release, you will know what to do. Plant safety procedures should be established that require the presence of at least two men before a flange is loosened, or any other opening is created, to allow a possible H2S release. The man doing the work should either wear a gas mask with canister, manufactured specifically for hydrogen sulfide protection, or a fresh air pack. The second man should stand on the side a few yards away, upwind, with the oxygen supply in his hands. If the job requires entering a vessel or enclosure which might contain some hydrogen sulfide, a safety harness with lifeline shall be attached to the man entering the vessel. Two men should remain outside the vessel to pull the man who entered the vessel to safety if he should be overcome. If a man who is working in a hydrogen sulfide exposure should begin moving sluggishly or lose coordination, the man who is standing by should remove him immediately to fresh air. Any sign of actions that are out of the ordinary is a last minute warning. After an extended exposure, a man will be unusually sensitive to even small concentrations of H2S gas.
2.8.2
Sulfur Dioxide Sulfur dioxide will not be present within the SRU, the SDU, the TGCU unit, and the Thermal Oxidizer as a pure gas but will be present in the following:
Issued 30 August 2011
1.
Most process gas streams (reactor gases, tailgas, and stack gas).
2.
Sulfur tank gases.
3.
Smoke from any sulfur fire.
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK The maximum allowable concentration in which it is safe to work is 5 PPM. Reactor gases, tailgas, and stack gas may have concentrations up to 10,000 PPM and vapors from sulfur fires may have concentrations up to 100,000 PPM. The most likely source of sulfur dioxide in sufficient concentration to cause problems is a fire in the sulfur storage tank. The simplest way to stop such a fire is to smother it by covering all openings to the air, then putting water into the storage tank. This water will vaporize to steam and help smother the fire. Smothering a sulfur fire with plant steam is also effective.
2.8.3
Sulfur Storage Tank Molten sulfur produced in each SRU flows through the drain seals and is stored in the sulfur surge tanks. These drain seals and tanks present a combination of principle hazards.
2.8.3.1
Poisonous Gases Hydrogen sulfide and sulfur dioxide are present in the vapor space above the molten sulfur. They should not be inhaled as they are extremely toxic.
2.8.3.2
Explosion and Fire The surge tanks are equipped with steam-powered eductors to provide ventilation of the vapor space. Each tank also has a steam-jacketed stack that can provide natural-draft ventilation if its eductor system is not functioning. These ventilation systems are designed to sweep sufficient fresh air through the vapor space to prevent hydrogen sulfide liberated from the sulfur from reaching explosive concentrations. However, common sense dictates that no ignition sources should be allowed near the tanks in case some obstruction of the ventilation system should occur and allow an explosive concentration of H2S to build up. Therefore, tools which might cause a spark or open flame, should not be brought into the area around the sulfur surge tanks without special review and precautions, and smoking must be prohibited in the area. Operators should be aware of the possible existence of an explosive mixture in the sulfur surge tanks, as there is some history of explosions in European sulfur pits and at least one U.S. pit. The breather vents, where the air is sucked into the tanks, should be
Issued 30 August 2011
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SULFUR BLOCK checked regularly for adequate air flow. The motive steam supply to the eductors, as well as the steam supply to and condensate from the ventilation system jacketing, should also be monitored. Sulfur fires may occur in the tanks. Molten sulfur has an auto-ignition temperature of approximately 450°F (232°C). This is a spontaneous reaction; no spark or flame is required. Steam system temperatures are normally well below the auto-ignition point of sulfur. However, some iron-sulfur corrosion compounds are unstable and can ignite, or decompose, at lower temperatures to create localized hot spots and sulfur burning. SECTIONS 2.9 THROUGH 2.14 LIST SOME IMPORTANT SAFETY CONSIDERATIONS THAT PERSONNEL SHOULD KEEP IN MIND WHEN WORKING IN THE PLANT. THESE SECTIONS ARE NOT A COMPLETE LIST OF SAFETY CONSIDERATIONS AND DO NOT OUTLINE COMPLETE OPERATING OR MAINTENANCE PROCEDURES. ALL PERSONNEL SHOULD FOLLOW THEIR EMPLOYER'S DETAILED SAFETY PROCEDURES FOR ANY WORK DONE IN THE PLANT.
2.9
Hot Work Any work which requires the use of equipment that is capable of being an ignition source in an area where flammable vapors or materials may be present is defined as "Hot Work". Examples of equipment considered as ignition sources are: welding equipment, open lights, gasoline engines, grinders, etc. "Hot Work" normally requires specific approval by plant management and should be implemented by following detailed instructions for obtaining "Hot Work" permits.
2.10 Vessel Entry The procedures used for vessel entry shall be in conformance with ANSI Z117.1 (latest edition), the "American National Standard Safety Requirements for Confined Spaces". The discussion in this section is a general information supplement to ANSI Z117.1. In all cases, consult ANSI Z117.1 and any applicable Samsung Total Petrochemicals policies for specific precautions and procedures regarding each instance of vessel entry. Vessel entry refers to any tank, vessel, equipment, or other enclosed place where there is a hazard of: 1) a toxic, corrosive, or flammable substance;
Issued 30 August 2011
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SULFUR BLOCK 2) insufficient oxygen; or 3) severe restrictions that would hinder escape or rescue. Vessel entry normally requires specific approval by plant management. Almost all of the vessels in this facility fit at least one of the three categories mentioned above, due to the potential presence of hydrocarbon gas, caustic or corrosive chemicals, or toxic H2S and SO2. All vessels should be assumed unsafe for normal entry until prescribed vessel entry procedures have been followed. Consider the precautions advised for vessel entry when gauging tanks, sampling, and blowing down lines or instruments. Some or all of the following items should be considered for most vessel entry jobs: A.
Disconnect and blank off all lines to the vessel.
B.
Remove all sources of ignition before removing manway covers.
C.
Check all internal lines and liquid traps to verify they are free of hazardous liquid.
D.
Clean the vessel as thoroughly as possible by draining, purging with inert gas, steaming, ventilating, or other suitable means. If steam is used, guard against static electricity by grounding the steam nozzle. After steaming, allow the vessel to cool slowly. Sudden cooling with water spray may cause a static electric charge. Also, it is not good practice to allow the inside surfaces of the sulfur plant process piping and vessels to become water wetted. Excessive corrosion occurs when oxygen and water are present.
E.
Issued 30 August 2011
Test the Atmosphere for: (1)
Oxygen - The atmosphere must contain 19.5-23.5% oxygen and the vessel should have adequate ventilation, either forced or natural.
(2)
Explosive mixture - A vessel may not be entered if the testing instrument indicates an air-vapor mixture that exceeds 10% of the lower explosive limit, or the value specified in your organization's safety procedures.
(3)
Toxic fumes - The presence of any toxic fumes requires the use of respiratory protective equipment, normally an air supplied mask with
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SULFUR BLOCK hand blower, or a self-contained breathing unit; otherwise, additional cleaning or purging of the vessel is indicated. F.
A safety harness and a lifeline shall be worn by the person entering the vessel if respiratory equipment is required.
G.
Personal protective clothing suitable for the job inside the vessel should be worn.
H.
An observer should be stationed outside the vessel. His duty should be to watch the person inside the vessel. When respiratory equipment is required for the person entering the vessel, the observer should also have the suitable respiratory equipment available.
I.
Fire extinguisher and other emergency equipment should be available as required.
2.11 Pipes and Lines In the discussion that follows, line breaking is defined as the opening of any line, the contents of which are flammable, corrosive, toxic, or under high pressure. All other line opening jobs or work are excluded from this definition. Line breaking usually requires specific approval by plant management. The following items should be considered in all work involving lines and valves:
2.11.1
Issued 30 August 2011
General 1.
Know the contents of each line being worked on.
2.
Know the pressure ratings of the pipes and fittings. Never install low pressure connections on high pressure lines.
3.
Never hammer on high-pressure lines.
4.
Use extreme caution when thawing frozen lines.
5.
Never use fire to locate leaks of flammable materials.
6.
Be very cautious when attempting to tighten steam pipe fittings while pressure is on a line.
7.
When opening valves, do so slowly to allow pressure to equalize before opening the valve fully.
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SULFUR BLOCK 8.
2.11.2
2.11.3
When removing blinds, loosen bolts and allow any pressure to bleed down. Gas sometimes leaks into the space between the blind and the valve.
Before Breaking Lines 1.
Drain the contents into a tank or to the lowest point.
2.
Lock out, tag out, and try the pump. All gauges and sight glasses should be checked for zero readings.
3.
Close and tag the nearest upstream and downstream valves.
When Breaking Lines 1.
Wear suitable personal protective equipment, such as full clothing. At times, rubber suits should be worn to guard against chemical splash. Goggles should be worn to protect eyes against chemical splash and flying particles.
2.
Always assume a line is full and under maximum possible pressure.
3.
The placement of a deflector over the flange joint is usually desirable for the initial "cracking" of flanges in lines containing corrosive or toxic material.
4.
The worker should slowly open the bolts on the far side, so that if there is a spray it will be away from him.
5.
Sections that have been removed should be handled carefully until they are inspected for trapped material or residues and flushed if required.
2.12 Electrical Equipment Everyone recognizes that high voltages can be very dangerous. However, some people fail to realize that so-called "low-voltage" can be hazardous and under certain conditions can produce fatal injuries. Deaths have occurred because of contact with circuits of less than 50 volts. It is not voltage but amperage that kills. Under certain conditions, as little as 1/10 ampere is sufficient to cause death. The following may be used as a guide when working with electrical equipment.
Issued 30 August 2011
General Safety
Page 2-42
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 2.12.1
Electrical Repairs When electrical equipment is to be repaired, switches must be locked open, tagged, and the circuit "tried" to confirm the power is off. Working on "hot circuits" normally requires the permission of plant management. Refer to detailed plant tag-out procedures before proceeding.
2.12.2
2.12.3
2.12.4
2.12.5
Issued 30 August 2011
Grounding 1.
All electrical equipment is to be grounded.
2.
If it is necessary to move any equipment, the ground should be replaced before the equipment is used.
Conduit, Cables, and Wires 1.
Electrical conduits should not be used to support other equipment.
2.
Exposed ends of electrical wires must be taped.
3.
Unused and abandoned electric wires must be removed or disconnected at each end.
Fuses 1.
Fuses should be replaced only by authorized personnel.
2.
Fuse tongs and/or rubber electrical gloves should be used and the disconnect should be opened. Rubber gloves must always be used for voltages in excess of 150 volts.
3.
Never use coins or tin foil in lieu of fuses.
4.
Never use fuses of greater capacity than is specified by the equipment manufacturer.
Switching 1.
When starting electric motors, handle all switches according to instructions. Make contact so as to prevent arcs. Stand in a safe position.
2.
Never pull a disconnect switch under load except in an emergency.
3.
Always be certain that hands are dry and that the footing is dry when operating switches or plugging in electrical appliances.
4.
Keep rubber mats in front of switchboards where possible.
General Safety
Page 2-43
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
2.12.6
2.12.7
Issued 30 August 2011
5.
Switch-panel fronts should be kept closed.
6.
Maintain clear access to disconnects/switches.
Hand Tools and Portable Equipment 1.
Extension lights without bulb protectors must not be used. Use only low voltage lights with isolating transformers in boilers and similar places.
2.
All extension cords should be the grounded type. Before each period of use, examine extension cords carefully for any failure of the outer insulation, particularly at terminal points where the cord enters a plug or a fixture.
3.
Lights and tools should not be disconnected from an extension cord while the other end of the cord is in a socket or receptacle.
4.
The ground cable with which each tool is equipped should be secured to a suitable ground before the tool is plugged into a source of electricity.
Miscellaneous 1.
Contact with electrical conductors should be avoided whether they are energized or not.
2.
Fenced sub-station areas should be entered only by authorized personnel.
3.
Faulty electrical equipment must not be used. Report it immediately.
4.
Before changing broken light bulbs, be certain the current is turned off.
5.
No employee may work within 15 feet of a high voltage power line except by special authorization of plant management.
General Safety
Page 2-44
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
2.13 Boilers and Other Direct-Fired Equipment 2.13.1
2.13.2
General 1.
In this facility, the Waste Heat Boiler, Sulfur Condenser, TGCU Waste Heat Reclaimer, and Thermal Oxidizer Waste Heat Boiler are classified as boilers, but they are not direct-fired. The Reactor Furnace and Thermal Oxidizer are the direct-fired pieces of equipment.
2.
Work on the Waste Heat Boiler, Sulfur Condenser, TGCU Waste Heat Reclaimer, Thermal Oxidizer Waste Heat Boiler, Reactor Furnace, and Thermal Oxidizer should be approved as required by local procedures.
3.
Control valves should be operated only when necessary by the operator in charge.
4.
Refer to detailed vendor instructions for specific descriptions of actual safety procedures and equipment on the direct-fired equipment in this plant.
Boilers
2.13.2.1
Repair and Maintenance a.
Only boiler inspectors or the State boiler agency should determine a new setting for safety relief valves. Seals on safety relief valves should never be removed. If a valve leaks, remove it to a Code-authorized shop for repairs.
b.
Before entering a boiler fire box:
c.
Issued 30 August 2011
(1)
Ventilate the fire box.
(2)
Lock, tag, and try the blower valve.
(3)
Blank or disconnect fuel gas lines.
Before entering the drum or shell: (1)
Feed water lines and blow-off lines should be blinded or suitably locked.
(2)
Blank the steam line between the stop valve and the boiler.
General Safety
Page 2-45
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK (3)
2.13.2.2
2.13.3
Issued 30 August 2011
If blinding is prevented by piping connections, non-return and main stop valves should be locked and vents between valves should be opened.
d.
If valves are to be locked, the man entering the boiler shall supervise the operations and retain the keys to the locks.
e.
After repairs, examine the boiler carefully for tools and other matter before replacing the manhole cover.
f.
Before filling begins, all locks should be removed by the man, or men, who have retained keys to the locks.
Operations a.
Open steam valves very slowly to allow cold lines to heat up and water to drain out before pressure builds.
b.
Open blow-off valves or cocks slowly. Before a boiler is blown out, it is advisable to attain a high water level so that scale and sediment can be blown out without lowering the water to a dangerous level.
Direct-Fired Equipment 1.
Before attempting to light burners, be certain that combustible gases are purged from the system.
2.
Stand to one side of openings when lighting burners.
3.
Ignite each burner or pilot as described in operating instructions.
4.
Observation ports should be used with care when lighting burners because of the chance of high positive pressures and explosion.
5.
Before entering a fire box: a.
Ventilate the fire box.
b.
Lock, tag, and try the blower valve.
c.
Blank or disconnect fuel gas and tailgas lines.
General Safety
Page 2-46
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
2.14 Laboratory Safety 2.14.1
2.14.2
2.14.3
Issued 30 August 2011
Good Housekeeping 1.
Cleanliness and orderliness are essential to the operations of laboratories.
2.
A continuous program should be in effect to prevent the accumulation of rubbish, rags, partly used samples, dismantled equipment, etc.
Equipment 1.
Inspect all gas hoses for leaks each day that they are used.
2.
Extinguish all gas burners when they are not in use.
3.
Glassware a.
Discard all cracked, broken, or scrap glassware.
b.
Fire-polish all chipped edges on burettes, beakers, graduates, etc.
c.
Avoid thermal shock with all glassware.
d.
Use only glass tubing with fire-polished ends.
e.
Before attempting to insert glass tubing into stopper holes, be certain that the holes are the proper size. Always moisten the stopper hole and the glass tubing with water, and rotate the glass tube as it is inserted, pushing it away from the body. When rubber tubing or stoppers stick on glassware, cut them away.
f.
Do not drink or eat out of laboratory glassware.
Chemical Sorting and Identification 1.
Adequately label or mark bottles and containers to identify the chemical within.
2.
Keep chemicals stored in their proper place. Solvents should not be brought into laboratory in quantities greater than five gallons.
3.
Keep volatile combustible liquids in safety containers and away from direct flames or sources of heat.
General Safety
Page 2-47
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 2.14.4
Issued 30 August 2011
Chemical Handling 1.
When handling acids or caustics in quantities, always wear protective clothing and eye protection.
2.
Always pour acids and caustics into water, never the reverse.
3.
If acids or caustics enter the eye, flush with plenty of water and report for first aid treatment.
4.
Wash hands immediately after handling chemicals bearing poison labels. Wash hands after handling mercury and clean up mercury spills at once.
5.
Use large quantities of water when disposing of acids or caustic materials through the drains.
6.
Refer to vendor information for specifics on the safe handling of individual types of chemicals and first aid steps for accidents involving them.
General Safety
Page 2-48
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
2.15 Material Safety Data Sheets (MSDS) This section contains Material Safety Data Sheets (MSDS) for the hazardous chemicals listed below that operating personnel in this part of the complex may encounter while operating the unit and systems described in this manual. Of necessity, these MSDS are generic in nature. As they become available, Samsung Total Petrochemicals Co. should replace and/or supplement the MSDS provided in this manual with those prepared by the manufacturers and/or suppliers of the specific chemicals used in the complex. A.
Hydrogen Sulfide
B.
Sulfur Dioxide
C.
Sulfur
D.
Ammonia
E.
Methyldiethanolamine
F.
Sodium Hydroxide
G.
UOP/ESM S-2001 Sulfur Conversion Catalyst
H.
Criterion 234 Tailgas Treating Catalyst
Issued 30 August 2011
General Safety
Page 2-49
MATERIAL SAFETY DATA SHEET HYDROGEN SULFIDE SECTION I - PRODUCT IDENTIFICATION Substance:
HYDROGEN SULFIDE
CAS Number: 7783-06-4
Trade Names / Synonyms:
Hepatic Gas; Hydrosulfuric Acid; Stink Damp; Sulfureted Hydrogen; Sulfur Hydride
Molecular Formula:
H2S
General or Generic ID:
Inorganic Gas
Molecular Weight: 34.08
SECTION II - COMPONENTS Component:
Hydrogen Sulfide
Percent: > 99.0
Other Contaminants:
Methyl Mercaptan; Carbon Disulfide; Oxides of Carbon and Sulfur
Exposure Limits:
Hydrogen Sulfide 20 PPM OSHA acceptable ceiling concentration 50 PPM / 10 minutes OSHA peak 10 PPM ACGIH TWA 10 PPM ACGIH STEL 15 mg/m3 (10 PPM) NIOSH recommended 10 minute ceiling SECTION III - PHYSICAL DATA
Description:
Colorless gas at atmospheric temperature and pressure, with the odor of rotten eggs.
Melting Point:
-122°F (-86°C)
Boiling Point:
-77°F (-60°C)
Liquid Specific Gravity: (water = 1.0)
1.54
Vapor Specific Gravity: (air = 1.0)
1.18
Vapor Pressure:
294 PSI (20 atm) @ 78°F (25°C)
Odor Threshold:
0.05 PPM
Solubility in Water:
4.2 g/l @ 60°F (15°C), 3.2 g/l @ 78°F (25°C)
Other Solvents
Carbon Disulfide, Weak Acids, Ethanol, Gasoline, Kerosene, Crude Oil, Liquid Sulfur
Other Physical Data:
Solubility decreases with increasing temperature or with mechanical disturbance (agitation), causing evolution of dissolved gas.
ISSUE DATE: 06/12/95
SUPERSEDES: 02/19/93
PAGE 1 OF 6
MATERIAL SAFETY DATA SHEET HYDROGEN SULFIDE SECTION IV- FIRE AND EXPLOSION INFORMATION Fire and Explosion Hazard:
Highly flammable gas when exposed to heat, flame, or oxidizers. Moderate explosion hazard. Gas-air mixtures are explosive. Vapors are heavier than air, and may travel a considerable distance to a source of ignition and flash back.
Auto-Ignition Temperature:
500°F (260°C)
Flash Point Temperature: N/A
Explosive Limits in Air:
Lower: 4.3%
Upper: 46%
Extinguishing Media:
Let burn unless leak can be stopped immediately. (1984 Emergency Response Guidebook, DOT P 5800.3). For larger fires, use water spray, fog, or foam. (1984 Emergency Response Guidebook, DOT P 5800.3).
Fire-Fighting Procedures:
Extinguish only if flow can be stopped; use water in flooding amounts as fog. Apply from as far a distance as possible. Avoid breathing poisonous vapors, keep upwind. Evacuate to a radius of 2500 feet for uncontrollable fires. Evacuate downwind areas as required for leaks.
Fire-Fighting Phases:
Stop flow of gas. Use water to keep fire-exposed containers cool and to protect personnel effecting the shut off. (NFPA 49, Hazardous Chemicals Data, 1975). SECTION V - HEALTH HAZARD DATA
Permissible Exposure Level:
10 PPM
Threshold Limit Value:
10 PPM
Health Effects from Exposure Swallowing:
Ingestion of a gas is unlikely.
Inhalation:
Corrosive/Neurotoxin/Toxic. 300 PPM immediately dangerous to life or health. Acute Exposure - Low concentrations may produce nasal and respiratory tract irritation. At 50 PPM, anosmia, anoxia, headache, nausea, dizziness, vomiting, confusion, weakness, ataxia, irritability, and insomnia may occur. Rhinitis, pharyngitis, coughing, bronchitis, and pneumonitis are also possible. At 500-1000 PPM, coma, convulsions, and death may occur within 30 minutes. At extremely high concentrations, respiratory paralysis and death from asphyxia may be immediate. Non-fatal exposures may result in sequelae including residual cough, cardiac dilation, slow pulse, peripheral neuritis, albuminuria, amnesia, psychic disturbances, and permanent brain damage.
ISSUE DATE: 06/12/95
SUPERSEDES: 02/19/93
PAGE 2 OF 6
MATERIAL SAFETY DATA SHEET HYDROGEN SULFIDE SECTION V- HEALTH HAZARD DATA (continued) Inhalation: (continued)
Chronic Exposure - Prolonged or repeated exposure to low concentrations may cause hypotension, nausea, anorexia, weight loss, incoordination, and chronic cough. Prolonged exposure to 250 PPM has led to pulmonary edema.
Eye Contact:
Corrosive. Acute exposure - 50 PPM for one hour has caused conjunctivitis, pain, lacrimation, photophobia, and appearance of haloes around lights. Within a few hours or days, symptoms may progress to keratoconjunctivitis and vesiculation of the corneal epithelium. Higher concentrations may cause severe irritation, lacrimation, and intense pain. Chronic Exposure - Prolonged or repeated exposure may cause conjunctivitis.
Skin Contact:
Corrosive. Acute Exposure - High vapor concentrations may cause severe irritation of the skin. Chronic Exposure - A high incidence of furunculosis has been reported in industrial hydrogen sulfide workers.
First Aid Measures Swallowing:
Treat symptomatically and supportively. Get medical attention immediately. If vomiting occurs, keep head lower than hips to prevent aspiration.
Inhalation:
Remove from exposure area to fresh air immediately. If breathing has stopped, give artificial respiration. Maintain airway and blood pressure and administer oxygen if available. Keep affected person warm and at rest. Administration of oxygen should be performed by qualified personnel. Get medical attention immediately.
Eye Contact:
Wash eyes immediately with large amounts of water, occasionally lifting upper and lower lids, until no evidence of chemical remains (at least 15-20 minutes). In case of burns, apply sterile bandages loosely without medication. Get medical attention immediately.
Skin Contact:
Flush affected areas with large amounts of water. Consult a physician for further treatment.
Antidote:
Amyl nitrite or sodium nitrite can be used to aid in the formation of sulfmethemoglobin, thus removing sulfide from combination in tissues. Pyridoxine 25 mg/kg intravenously, or 10% urea, 1 g/kg intravenously, has been suggested as a sulfide acceptor. Administration of antidotes should be performed by qualified medical personnel. The nitrite antidote is toxic; therapy is dangerous. (Dreisbach, Handbook of Poisoning, 11th ed.)
ISSUE DATE: 06/12/95
SUPERSEDES: 02/19/93
PAGE 3 OF 6
MATERIAL SAFETY DATA SHEET HYDROGEN SULFIDE SECTION VI- REACTIVITY DATA Reactivity:
Stable under normal temperatures and pressures.
Incompatibilities:
Acetaldehyde: Barium Oxide, Mercurous Oxide, and Air: Barium Oxide, Nickel Oxide, and Air: Barium Peroxide: Bromine Pentafluoride: Chlorine Monoxide: Chlorine Trifluoride: Chromic Anhydride: Copper: Copper Powder: Diiron Trioxide Hydrate: Fluorine: Metals: Metal oxides: Lead Dioxide: Nitric Acid: Nitric Acid (Fuming or Concentrated): Nitrogen Trichloride: Nitrogen Trifluoride: Nitrogen Triiodide and Ammonia: Oxidants: Oxygen Difluoride: Perchloryl Fluoride: Phenyl Diazonium Chloride: Rust: Silver Fulminate: Soda Lime and Air: Sodium: Sodium Peroxide:
Violent reaction. Incandescent reaction or explosion. Incandescent reaction or explosion. Ignition reaction. Fire and explosion hazard. Ignition reaction on contact. Explosive reaction. Incandescent reaction on heating. Intense exothermic reaction. Intense reaction. Formation of combustible substance. Ignition reaction. Attacks most metals, especially in the presence of water. Combustion, incandescent reaction, or explosion. Combustion reaction. Incandescent reaction. Violent reaction. Explosive reaction. Formation of explosive mixture. Explosive reaction. Violent reaction. Explosive reaction on mixing. Ignition or explosion at 100-300°C. Formation of explosive substance. Hydrogen sulfide may ignite if passed through rusty iron pipes. Violent reaction at ambient temperatures. Incandescent reaction. Rapid reaction on contact with moist gas. Violent reaction or ignition, even in the absence of air.
Decomposition:
Thermal decomposition products may include toxic and hazardous hydrogen, sulfur, and oxides of sulfur.
Polymerization:
Hazardous polymerization has not been reported to occur under normal temperatures and pressures.
ISSUE DATE: 06/12/95
SUPERSEDES: 02/19/93
PAGE 4 OF 6
MATERIAL SAFETY DATA SHEET HYDROGEN SULFIDE SECTION VII- SPILL OR LEAK PROCEDURES Steps to Be Taken in Case Material is Released or Spilled Shut off ignition sources. Stop leak if you can do it without risk. Use water spray to reduce vapors. Isolate area until gas has dispersed. No smoking, flames, or flares in hazard area! Keep unnecessary people away; isolate hazard area and deny entry. Ventilate closed spaces before entering. Evacuate area endangered by gas. Waste Disposal Method Water used to knock-down vapors is corrosive and toxic, and should be diked for containment. Add suitable agent to neutralize to 7 pH prior to disposal.
SECTION VIII - PROTECTIVE EQUIPMENT TO BE USED Ventilation:
Provide local exhaust or process enclosure ventilation to meet the published exposure limits. Ventilation equipment must be explosion-proof.
Respirator:
The following respirators and maximum use concentrations are recommendations by the U.S. Department of Health and Human Services; NIOSH Pocket Guide to Chemical Hazards or NIOSH Criteria Documents; or, Department of Labor, 29CFR1910, Subpart Z. The specific respirator selected must be based on contamination levels found in the work place and be jointly approved by the National Institute of Occupational Safety and Health and the Mine Safety and Health Administration. Hydrogen Sulfide: 100 PPM Supplied-air respirator. Self contained breathing apparatus.
ISSUE DATE: 06/12/95
250 PPM -
Supplied-air respirator operated in continuous flow mode. Self-contained breathing apparatus.
300 PPM -
Self-contained breathing apparatus. Supplied-air respirator with full facepiece.
Escape -
Air-purifying full facepiece respirator (gas mask) with chin-style or frontor back-mounted canister. Escape-type self-contained breathing apparatus.
SUPERSEDES: 02/19/93
PAGE 5 OF 6
MATERIAL SAFETY DATA SHEET HYDROGEN SULFIDE SECTION VIII - PROTECTIVE EQUIPMENT TO BE USED (continued) Respirator (continued):
For firefighting and other immediately dangerous to life or health conditions: Self-contained breathing apparatus with full facepiece operated in pressure-demand or other positive pressure mode. Supplied-air respirator with full facepiece and operated in pressure-demand or other positive pressure mode in combination with an auxiliary self-contained breathing apparatus operated in pressure-demand or other positive pressure mode.
Clothing:
Wear protective clothing. Prevent any possibility of repeated or prolonged vapor contact with skin.
Gloves:
Wear full protective gloves.
Eye Protection:
Employee must wear splash-proof or dust-resistant safety goggles and a faceshield to prevent contact with this substance. Where there is any possibility that an employee's eyes may be exposed to this substance, the employer shall provide an eye-wash fountain within the immediate work area for emergency use.
SECTION IX - SPECIAL PRECAUTIONS OR OTHER COMMENTS 1.
Odor is not a reliable test for the presence of hydrogen sulfide.
2.
Since hydrogen sulfide is heavier than air, it settles when released into the atmosphere and becomes more concentrated near the ground and in low places.
3.
Hydrogen sulfide dissolves in liquid sulfur and is a hazard in storage tanks and pits.
Disclaimer The information contained herein is believed to be accurate, but is not warranted to be, whether originating within the company or not. Health and safety precautions in this data sheet may not be adequate for all individuals and/or situations. Recipients are advised to confirm in advance of need that the information is current, applicable, and suitable to their circumstances. It is the end user’s responsibility to evaluate and use this product safely, and to comply with all applicable laws and regulations. No statement made in this data sheet shall be construed as a permission or recommendation for use of any product in a manner that might infringe existing patents. No warranty is made, either expressed or implied.
ISSUE DATE: 06/12/95
SUPERSEDES: 02/19/93
PAGE 6 OF 6
MATERIAL SAFETY DATA SHEET SULFUR DIOXIDE SECTION I - PRODUCT IDENTIFICATION Substance
SULFUR DIOXIDE
Trade Names / Synonyms:
Sulfurous Acid Sulfur Oxide
Molecular Formula:
SO2
General or Generic ID:
Inorganic Gas
CAS Number: 7446-09-5
Anhydride;
Sulfurous
Anhydride;
Sulfurous
Oxide;
Molecular Weight: 64.06
SECTION II - COMPONENTS Component:
Sulfur Dioxide
Percent: > 99.0
Other Contaminants:
Hydrogen Sulfide
Exposure Limits:
Sulfur Dioxide 5 PPM OSHA TWA per 8-hour working day 2 PPM ACGIH TWA 0.5 PPM NIOSH recommended TWA SECTION III - PHYSICAL DATA
Description:
Colorless gas at atmospheric temperature and pressure, with an irritating, suffocating odor.
Melting Point:
-104°F (-76°C)
Boiling Point:
14°F (-10°C)
Liquid Specific Gravity: (water = 1.0)
1.43
Vapor Specific Gravity: (air = 1.0)
2.21
Vapor Pressure:
49 PSIA (3.3 atm) @ 70°F (21°C)
Odor Threshold:
0.47 PPM
Solubility in Water:
129 g/l @ 60°F (15°C), 102 g/l @ 68°F (20°C)
Other Solvents:
Sulfur
Other Physical Data:
ISSUE DATE: 02/19/93
SUPERSEDES:
PAGE 1 OF 5
MATERIAL SAFETY DATA SHEET SULFUR DIOXIDE SECTION IV- FIRE AND EXPLOSION INFORMATION Fire and Explosion Hazard:
None
Auto-Ignition Temperature:
N/A
Flash Point Temperature: N/A
Explosive Limits in Air:
Lower: N/A
Upper: N/A
Extinguishing Media:
Material is nonflammable. Use what is appropriate to the surrounding fire. SO2 will form a corrosive acidic mist with water fog or steam.
Fire-Fighting Procedures:
Fire fighters must use full protective clothing, eye protection, and selfcontained breathing equipment when this material is involved in a fire situation.
Fire-Fighting Phases:
N/A
SECTION V - HEALTH HAZARD DATA Permissible Exposure Level:
5 PPM
Threshold Limit Value:
2 PPM
Health Effects from Exposure Swallowing:
Ingestion of a gas is unlikely.
Inhalation:
Chiefly affects the upper respiratory tract and the bronchi, causing irritation, difficulty with breathing, pulmonary edema, and, at high levels, respiratory paralysis. Short exposures above 50-100 PPM can be dangerous, and, above 400-500 PPM, immediately life threatening. Systemic effects of acute or chronic exposure are not fully known. Statistical evidence has been reported to show increased pulmonary function impairment at chronic SO2 levels of 1-4 PPM. Mixture with smoke particulate or aerosols may increase the hazards of SO2 inhalation.
Eye Contact:
At 20 PPM and above, irritation and inflammation of the conjunctiva.
Skin Contact:
At 10,000 PPM, irritating to moist areas within a few minutes.
ISSUE DATE: 02/19/93
SUPERSEDES:
PAGE 2 OF 5
MATERIAL SAFETY DATA SHEET SULFUR DIOXIDE SECTION V- HEALTH HAZARD DATA (continued) First Aid Measures Swallowing:
Treat symptomatically and supportively. Get medical attention immediately. If vomiting occurs, keep head lower than hips to prevent aspiration.
Inhalation:
The victim must be carried at once to an uncontaminated atmosphere and effective artificial respiration started immediately if breathing has ceased. Oxygen (100%) should be administered (by trained personnel only) as soon as possible after a severe exposure, preferably against a positive exhalation pressure of 1.25 inches of water. Oxygen inhalation must be continued as long as necessary to maintain the normal color of the skin and mucous membranes. In cases of severe exposure, the patient should breathe 100% oxygen under positive exhalation pressures for 30 minute periods every hour for at least 3 hours. If there are no signs of lung congestion at the end of this period, and if the breathing is easy and the color is good, oxygen inhalation may be discontinued. Throughout this time, the patient should be kept comfortably warm, but not hot.
Eye Contact:
If sulfur dioxide has contacted the eyes, they should be washed promptly with large quantities of water for at least 15 minutes. Chemical neutralizers are not advisable. It is advisable to irrigate the eyes gently with water at room temperature in order to minimize additional pain and discomfort. Refer the victim at once to a physician, preferably an eye specialist.
Skin Contact:
On skin contact with sulfur dioxide, use an emergency safety shower at once. Clothing and shoes contaminated with sulfur dioxide should be removed under the shower. Sulfur dioxide should be washed off with very large quantities of water. Wash skin areas with large quantities of soap and water. Do not apply salves or ointments to chemical burns for 24 hours.
ISSUE DATE: 02/19/93
SUPERSEDES:
PAGE 3 OF 5
MATERIAL SAFETY DATA SHEET SULFUR DIOXIDE SECTION VI- REACTIVITY DATA Reactivity:
Stable under normal temperatures and pressures.
Incompatibilities:
Acrolein Aluminum Cesium Hydrogencarbide Cesium Oxide Chlorates Chlorine Trifluoride Chromium Ferrous Oxide Fluorine Halogens or Interhalogens Lithium Acetylene Carbide Diammino Lithium Nitrate
Polymerization:
Hazardous polymerization has not been reported to occur under normal temperatures and pressures.
Manganese Metal Acetylides Metal Oxides Metals Polymeric Tubing Potassium Carbide Potassium Chlorate Rubidium Carbide Sodium Sodium Carbide Sodium Hydride Tin Monoxide
SECTION VII- SPILL OR LEAK PROCEDURES Steps to Be Taken in Case Material is Released or Spilled Notify safety personnel of significant leaks. Exclude all from area except those assigned to leak and spill control who are using full protective gear (see Section VIII). Provide ventilation. Locate and control leakage. Waste Disposal Method If water is used to knock-down vapors, it will be corrosive and toxic, and should be diked for containment. Add suitable agent to neutralize to 7 pH prior to disposal.
ISSUE DATE: 02/19/93
SUPERSEDES:
PAGE 4 OF 5
MATERIAL SAFETY DATA SHEET SULFUR DIOXIDE SECTION VIII - PROTECTIVE EQUIPMENT TO BE USED Ventilation:
Provide local exhaust or process enclosure ventilation to meet the published exposure limits. (Treatment of exhausted air to remove SO2 may be necessary before discharge to the outside environment.)
Respirator:
For fire fighting and other immediately dangerous to life or health conditions: Self-contained breathing apparatus with full pressure-demand or other positive pressure mode.
facepiece
operated
in
Supplied-air respirator with full facepiece and operated in pressure-demand or other positive pressure mode in combination with an auxiliary self-contained breathing apparatus operated in pressure-demand or other positive pressure mode. (An approved cartridge respirator can be used when contamination is known to be below 20 PPM.) Clothing:
Wear protective clothing. contact with skin.
Prevent any possibility of repeated or prolonged vapor
Gloves:
Wear full protective gloves.
Eye Protection:
Employee must wear splash-proof or dust-resistant safety goggles and a faceshield to prevent contact with this substance. Where there is any possibility that an employee's eyes may be exposed to this substance, the employer shall provide an eye-wash fountain within the immediate work area for emergency use.
SECTION IX - SPECIAL PRECAUTIONS OR OTHER COMMENTS
Disclaimer The information contained herein is believed to be accurate, but is not warranted to be, whether originating within the company or not. Health and safety precautions in this data sheet may not be adequate for all individuals and/or situations. Recipients are advised to confirm in advance of need that the information is current, applicable, and suitable to their circumstances. It is the end user’s responsibility to evaluate and use this product safely, and to comply with all applicable laws and regulations. No statement made in this data sheet shall be construed as a permission or recommendation for use of any product in a manner that might infringe existing patents. No warranty is made, either expressed or implied.
ISSUE DATE: 02/19/93
SUPERSEDES:
PAGE 5 OF 5
MATERIAL SAFETY DATA SHEET SULFUR SECTION I - PRODUCT IDENTIFICATION Substance:
SULFUR
CAS Number: 7704-34-9
Trade Names / Synonyms:
Asulfa-Supra; Bensulfoid; Brimstone; Colloidal Sulfur; Cosan; Devisulphur; Flowers of Sulfur; Ground Vocle Sulphur; Hexasul; Kumulus; Microwetsulf; Precipitated Sulfur; Precipitated Sulphur; S-590; S-594; S-595; Solid Sulfur; Solid Sulphur; Sublimed Sulfur; Sublimed Sulphur; Sulfex; Sulfran; Sulphur; Uni350
Molecular Formula:
S
General or Generic ID:
Non-metallic Element
Molecular Weight: 32.06
SECTION II - COMPONENTS Component:
Sulfur
Percent: > 99.0
Other Contaminants:
Hydrogen Sulfide, Sulfur Dioxide, Hydrocarbons, Carbon
Exposure Limits:
The Nuisance Dust TLV should govern exposure to solid sulfur in the absence of other standards: 10 mg/m3 (8 PPMW) ACGIH TWA for total dust 5 mg/m3 (4 PPMW) ACGIH TWA for respirable dust Liquid sulfur may release hydrogen sulfide and/or sulfur dioxide as gases. Refer to the specific Material Safety Data Sheets for these substances giving the applicable exposure limits. SECTION III - PHYSICAL DATA
Description:
Solid sulfur is odorless, tasteless, yellow rhombic or monoclinic crystals, lumps, granules, or powder. Sulfur contaminated with hydrocarbon or carbon may be orange, green, tan, brown, or black in color. Liquid sulfur is viscous and odorless, with a color ranging from bright yellow to dark orange (almost red) depending on temperature. Contaminants (particularly hydrogen sulfide) sometimes give sulfur the odor of rotten eggs.
Melting Point:
246°F (119°C)
Boiling Point:
832°F (444°C)
Liquid Specific Gravity: (water = 1.0)
1.80
Solid Specific Gravity: (water = 1.0)
2.07
Vapor Pressure:
0.05 PSIA (2.50 mm Hg) @ 400°F (204°C)
Odor Threshold:
N/A
Solubility in Water:
Negligible
ISSUE DATE: 06/13/95
SUPERSEDES: 02/19/93
PAGE 1 OF 10
MATERIAL SAFETY DATA SHEET SULFUR SECTION III- PHYSICAL DATA (continued) Other Solvents:
Other Solvents: Slightly soluble in Ethyl Alcohol; Ethyl Ether; Benzene; Toluene; Olive Oil.
Other Physical Data:
At temperatures up to about 317°F (158°C), the viscosity of pure liquid sulfur decreases as the temperature increases. As the temperature increases from 317°F to 370°F (158°C to 188°C), the viscosity of pure liquid sulfur rises rapidly to a tremendously high maximum, causing the liquid to become a dark, sticky, plastic material impossible to pump. SECTION IV - FIRE AND EXPLOSION INFORMATION
Fire and Explosion Hazard:
Solid - The primary hazard in handling solid sulfur results from the fact that sulfur dust suspended in the air ignites easily. Even though the explosion hazard is considered moderate, an explosion occurring in a confined area could cause considerable damage. Sulfur, being a very poor conductor of electricity, tends to develop static electric charges when it is in motion. Ignition of sulfur dust by static-caused sparks is not uncommon. Frictional heat in equipment has also been responsible for starting sulfur fires. Liquid - The fire hazards of liquid sulfur result primarily from the low ignition point of sulfur and from the presence of hydrogen sulfide.
Auto-Ignition Temperature:
450°F (232°C) for liquid sulfur 374°F (190°C) for sulfur dust suspended in air
Flash Point Temperature:
405°F (207°C)
Explosive Limits in Air:
Lower: 35 g/m3 (2.9% by wt)
Extinguishing Media:
Small Fires:
Water, dry chemical, soda ash, or sand. (1987 Emergency Response Guidebook, DOT P 5800.4)
Larger fires:
Use water spray, fog, or standard foam. (1987 Emergency Response Guidebook, DOT P 5800.4)
Upper: 1400 g/m3 (53% by wt)
Steam smothering can be used in storage pits and other relatively small enclosures. Carbon dioxide is also a satisfactory fire extinguishing agent. Fire-Fighting Procedures:
Straight streams of water from a nozzle can scatter molten sulfur and disperse sulfur dust into the air. Sulfur dust is a moderate explosion hazard when dispersed in air. As sulfur burns, it generates sulfur dioxide, a toxic gas. Wear self-contained breathing apparatus.
Unusual Hazards:
Small dust explosions may disperse larger quantities of dust into the air, resulting in a serious explosion, particularly in confined areas.
ISSUE DATE: 06/13/95
SUPERSEDES: 02/19/93
PAGE 2 OF 10
MATERIAL SAFETY DATA SHEET SULFUR SECTION V- HEALTH HAZARD DATA Permissible Exposure Level:
None indicated.
Threshold Limit Value:
None indicated.
Health Effects from Exposure Swallowing:
Acute Exposure - A man has survived ingestion of 60 grams of sulfur over a period of 24 hours. Large doses (15 grams) by mouth may lead to hydrogen sulfide production in vivo, chiefly due to bacterial action within the colon. Small particles are generally more toxic than large ones. If high levels of impurities are present, sore throat, nausea, headache, dullness, and possible unconsciousness may occur. Chronic Exposure - In medicine, it is used as a laxative. No adverse effects have been reported.
Inhalation:
Irritant. Acute Exposure - Inhalation of large amounts of dust may cause catarrhal inflammation of the nasal mucosa which may lead to hyperplasia with abundant nasal secretions. Tracheobronchitis is a frequent occurrence, with dyspnea, persistent cough, and expectoration, which may sometimes be streaked with blood. Chronic Exposure - Prolonged inhalation of dust may cause bronchopulmonary disease which, after several years, may be complicated by emphysema and bronchiectasis. Early symptoms in sulfur miners often include upper respiratory tract catarrh, with cough and expectoration which is mucoid and may even contain granules of sulfur. Asthma is a frequent complication. The maxillary and frontal sinuses may be affected; involvement is usually bilateral and pansinusitis may occur. Pulmonary function may be reduced. Radiological examinations have revealed irregular opacities in the lungs and occasionally nodulation has been reported.
Eye Contact:
Irritant. Acute Exposure - 8 PPM has caused irritation of human eyes. Dust may cause irritation, redness and pain with lacrimation, photophobia, conjunctivitis, and blepharoconjunctivitis; cases of damage to the crystalline lens have been reported with the formation of opacities and even cataract and focal chorioretinitis. Chronic Exposure - Low levels may cause conjunctivitis. Higher levels may cause symptoms similar to acute exposure.
ISSUE DATE: 06/13/95
SUPERSEDES: 02/19/93
PAGE 3 OF 10
MATERIAL SAFETY DATA SHEET SULFUR SECTION V - HEALTH HAZARD DATA (continued) Skin Contact:
Irritant. Acute Exposure - In highly purified form, the dust is low in irritation effects, but frequently impurities of hydrogen sulfide are present and may produce irritation or possibly burns. Chronic Exposure - Soaps, ointments, gels, and drugs containing sulfur are used as fungicides and parasiticides in the treatment of cutaneous disorders such as psoriasis, seborrhea, eczema-dermatitis, and scalp disorders. Sulfur possesses a keratolytic property which may be the basis of its therapeutic reaction. Prolonged local use of sulfur may result in characteristic dermatitis venenata, possibly with erythematous and eczematous lesions and signs of ulceration. Molten sulfur - Capable of inflicting severe burns.
First Aid Measures Swallowing:
Give water or fluids. Emesis is not necessary. Treat supportively and symptomatically. If irritation or digestive upset occurs, get medical attention.
Inhalation:
Remove from exposure area to fresh air immediately. If breathing has stopped, perform artificial respiration. Keep person warm and at rest. Get medical attention immediately.
Eye Contact:
Wash eyes immediately with large amounts of water, occasionally lifting upper and lower lids, until no evidence of chemical remains (approximately 15-20 minutes). Get medical attention immediately.
Skin Contact:
Remove contaminated clothing and shoes immediately. Wash affected area with soap or mild detergent and large amounts of water until no evidence of chemical remains (approximately 15-20 minutes). Get medical attention immediately.
ISSUE DATE: 06/13/95
SUPERSEDES: 02/19/93
PAGE 4 OF 10
MATERIAL SAFETY DATA SHEET SULFUR SECTION VI- REACTIVITY DATA Reactivity:
Stable under normal temperatures and pressures.
Incompatibilities:
Alkali Metal Nitrides:
Aluminum Powder: Aluminum Powder: Aluminum and Copper: Aluminum and Niobium Oxide: Ammonia: Ammonia Nitrate: Ammonia Perchlorate: Barium Bromate: Barium Carbide: Barium Chlorate:
Barium Iodate: Boron: Bromine Pentafluoride: Bromine Trifluoride: Cadmium: Calcium: Calcium Bromate: Calcium Carbide: Calcium Chlorate: Calcium Hypochlorite Powder: Calcium Hypochlorite: Calcium Iodate: Calcium Phosphide: Calcium, Vanadium Oxide, and Water: Cesium Nitride: Charcoal, Freshly Calcined: Chlorate and Copper: Chlorine Dioxide: Chlorine Monoxide: ISSUE DATE: 06/13/95
Highly flammable mixture which evolves ammonia and hydrogen sulfide in contact with water. Possible explosion if ignited with a magnesium fuse. Violent reaction. Possible explosion when heated in a closed container. Ignition. Possible formation of an explosive product. Possible explosion on impact. Possible explosion on impact. When both are finely divided, explosion with heat, percussion, or friction. Ignites in sulfur vapor at 150°C and incandesces. Possible spontaneous ignition at 108°C. When both are finely divided, explosion with heat, percussion, or friction. When both are finely divided, explosion with heat, percussion, or friction. Incandesces at 600°C. Violent reaction with possible ignition. Incandescence on contact. Vigorous reaction. Burns in the vapor at 400°C. Explodes on ignition. When both are finely divided, explosion with heat, percussion, or friction. Ignites in the vapor at 400°C. When both are finely divided, explosion with heat, percussion, or friction. Explosion if heated in closed vessel. With damp sulfur, produces a crimson flash with scattering of molten sulfur. When both are finely divided, explosion with heat, percussion, or friction. Incandesces at 300°C. Ignition. Intense reaction. Ignites spontaneously. Probable explosion. Ignition and possible explosion. Violent explosion.
SUPERSEDES: 02/19/93
PAGE 5 OF 10
MATERIAL SAFETY DATA SHEET SULFUR SECTION VI - REACTIVITY DATA (continued) Incompatibilities: (continued)
Chlorine Trifluoride: Chlorine Trioxide: Chromic Anhydride: Chromium Trioxide: Chromyl Chloride: Copper: Copper Alloy: Diarsenic Trisulfide: Dichlorine Monoxide: Diethyl Ether: Fiberglass and Iron Filings: Fluorine: Halogen Oxides: Heptasilver Nitrate Octaoxide: Hydrocarbons: Indium: Interhalogens: Iodine Pentafluoride: Iodine Pentoxide: Lampblack: Lead Chlorate: Lead Chloride: Lead Chlorite: Lead Chromate: Lead Dioxide: Lead (IV) Oxide: Lithium: Lithium dissolved in Ammonia: Lithium Carbide: Magnesium: Magnesium Bromate: Magnesium Chlorate: Magnesium Iodate: Mercuric Nitrate: Mercuric Oxide: Mercurous Oxide: Mercury (I) Oxide: Mercury (II) Oxide: Metal Acetylides of Carbides: Metal Chlorates:
ISSUE DATE: 06/13/95
Violent reaction with possible ignition. Possible violent reaction. Ignition on heating, possible explosion. Ignition on warming. Ignition. Attacked corrosively. Attacked corrosively. Formation of explosion mixture. Probable explosion. Possible explosion on evaporation. Exothermic reaction above 125°C. Ignition at ambient temperatures. Possible explosion. Explosion on impact. Explosive products produced on contact with molten sulfur. Ignition and incandescence on heating. Possible ignition or incandescent reaction. Incandescence on contact. Explosive reaction on warming. Spontaneous ignition. Possible spontaneous ignition at 63°C. Explosion. Explosion. Pyrophoric mixture. Explosion. Ignition on grinding or addition of sulfuric acid. When either is molten, explosively violent reaction. Vigorous reaction, even at -33°C. Burns in sulfur vapor. Vigorous reaction with molten sulfur or its vapor. When both are finely divided, explosion with heat, percussion, or friction. When both are finely divided, explosion with heat, percussion, or friction. When both are finely divided, explosion with heat, percussion, or friction. Possible explosion. Explosion when heated. Ignition on light impact. Ignition on frictional initiation. Explosion on heating. Possible ignition. Powerfully explosive, sensitive to friction or shock.
SUPERSEDES: 02/19/93
PAGE 6 OF 10
MATERIAL SAFETY DATA SHEET SULFUR SECTION VI - REACTIVITY DATA (continued) Incompatibilities: (continued)
Metal Halogenates: Metal Oxides: Metals: Monorubidium Acetylide: Nickel Powder: Nitrogen Dioxide: Osmium: Oxidants: Palladium: Perchlorates (Inorganic): Permanganates: Phosphorus: Phosphorus, Red: Phosphorus, Yellow: Phosphorus Trioxide: Potassium: Potassium: Potassium Bromate:
Potassium Chlorate:
Potassium Chlorite: Potassium Iodate: Potassium Nitrate and Arsenic Trisulfide: Potassium Nitride: Potassium Perchlorate: Potassium Permanganate: Rhodium: Rubidium (Molten): Rubidium Acetylene Carbide: Selenium: Selenium Carbide: Silver Bromate: Silver Chlorate: Silver Chlorite: Silver Nitrate: ISSUE DATE: 06/13/95
Possible violent or explosive reaction. Possible ignition or explosion on initiation. Possible ignition or explosion. Ignites in molten sulfur. Ignition and incandescence in boiling sulfur or its vapor at 600°C. Sulfur burns vigorously. Ignition and incandescence in boiling sulfur or its vapor at 600°C. Possible ignition or explosion. Ignition and incandescence on heating. Explosive on impact. Formation of an explosive mixture. Ignition or explosion. Violent exothermic reaction or explosion. Ignition or explosion on heating. Violent reaction or explosion. Violent reaction on warming. Vapors of both react with chemiluminescence at 300°C and low pressure. Unstable mixture which may ignite after several hours. When both are finely divided, explosion may occur with heat, percussion, or friction. Ignition at 160-162°C. When both are finely divided, explosion with heat, percussion, or friction. Violent reaction. When both are finely divided, explosion with heat, percussion, or friction. Pyrotechnic formulation. Highly flammable mixture which evolves ammonia and hydrogen sulfide. Explosion on moderately strong impact. Possible explosion on heating. Ignition and incandescence on heating. Ignition in the vapor at 200-300°C. Ignition. Ignition. When heated, incandesces with the vapor. Ignition at 73-75°C. Explosive reaction in presence of water. Possible spontaneous ignition. Ignition at 74°C. Explosion on rubbing. Explosion on percussion.
SUPERSEDES: 02/19/93
PAGE 7 OF 10
MATERIAL SAFETY DATA SHEET SULFUR SECTION VI - REACTIVITY DATA (continued) Incompatibilities: (Continued)
Silver Oxide: Sodium: Sodium Bromate: Sodium Chlorate: Sodium Chlorite: Sodium Hydride: Sodium Iodate: Sodium Nitrate and Charcoal: Sodium Peroxide: Stannic Iodide and Potassium: Stannic Iodide and Sodium: Static Discharges: Steel: Strontium Carbide: Strontium Carbide and Selenium: Sulfur Dichloride: Tetraphenyllead: Thallic Oxide: Thorium: Thorium Carbide: Tin: Uranium: Uranium Carbide: Zinc Bromate: Zinc Chlorate: Zinc Iodate: Zinc Powder:
Ignition on grinding. Violent or explosive reaction with heat or friction. When both are finely divided, explosion with heat, percussion, or friction. When both are finely divided, explosion with heat, percussion, or friction. Ignition in presence of water. Vigorous reaction with vapors. When both are finely divided, explosion with heat, percussion, or friction. Explosion. Explosive mixture. Explosion on impact. Explosion on impact. Easily ignited due to very low minimum ignition energy. Attacked corrosively in presence of moisture. Incandescence or ignition in vapors about 500°C. Incandescence at 500°C. Very violent explosion on impact. Possible explosion. Explosion on grinding. Ignition and incandescence with heating. Incandesces when heated. Ignites in the vapors about 500°C. Vigorous reaction with incandescence. Ignition on heating. Incandescence and ignition with boiling sulfur or its vapor. Ignition in the vapors about 500°C. When both are finely divided, explosion with heat, percussion, or friction. When both are finely divided, explosion with heat, percussion, or friction. When both are finely divided, explosion with heat, percussion, or friction. Explosive reaction on warming.
Decomposition:
Combustion may release toxic oxides of sulfur, some of which may react with air and moisture to produce corrosive sulfurous and sulfuric acids. Toxic and corrosive hydrogen sulfide may be generated by molten sulfur.
Polymerization:
Hazardous polymerization has not been reported to occur under normal temperatures and pressures.
ISSUE DATE: 06/13/95
SUPERSEDES: 02/19/93
PAGE 8 OF 10
MATERIAL SAFETY DATA SHEET SULFUR SECTION VII- SPILL OR LEAK PROCEDURES Steps to Be Taken in Case Material is Released or Spilled Small Spill:
Shut off ignition sources. Do not touch spilled material. With clean shovel, place material into clean, dry container and cover; move containers from spill area.
Large Spill:
Shut off ignition sources. Do not touch spilled material. Wet down with water and dike for later disposal. No smoking, flames, or flares in hazard area! Keep unnecessary people away. Isolate hazard area and deny entry.
Waste Disposal Method Waste should be mixed with four times its weight of crushed limestone, marble, or shell, and then buried at a permitted disposal site. SECTION VIII- PROTECTIVE EQUIPMENT TO BE USED Ventilation:
Provide local exhaust or process enclosure ventilation to meet the published exposure limits. Ventilation equipment must be explosion-proof.
Respirator:
In routine handling of molten sulfur in adequately ventilated premises, respiratory protective equipment is not required, but should be available nearby. For areas containing sulfur dust, the specific respirator selected must be based on the contamination levels found in the work place, must not exceed the working limits of the respirator, and be jointly approved by the National Institute for Occupational Safety and Health and the Mine Safety and Health Administration. The following respirators are recommended based on the data found in the Physical Data and Health Hazard Data sections. They are ranked in order from minimum to maximum respiratory protection: Chemical cartridge respirator with an organic vapor cartridge(s) with a highefficiency particulate filter and full facepiece. High-efficiency particulate respirator with a full facepiece. Powered air-purifying respirator with a high-efficiency filter with a full facepiece. Type "C" supplied-air respirator with a full facepiece operated in pressure-demand or other positive pressure mode, or with a full facepiece, helmet, or hood operated in continuous-flow mode. Self-contained breathing apparatus with a full pressure-demand or other positive pressure mode.
ISSUE DATE: 06/13/95
SUPERSEDES: 02/19/93
facepiece
operated
in
PAGE 9 OF 10
MATERIAL SAFETY DATA SHEET SULFUR SECTION VIII- PROTECTIVE EQUIPMENT TO BE USED Respirator: (continued)
For firefighting and other immediately dangerous to life or health conditions: Self-contained breathing apparatus with a full pressure-demand or other positive pressure mode.
facepiece
operated
in
Supplied-air respirator with a full facepiece operated in pressure-demand or other positive pressure mode in combination with an auxiliary self-contained breathing apparatus operated in pressure-demand or other positive pressure mode. Clothing:
Employees operating equipment containing molten sulfur should wear clothing capable of protecting the chest and arms, trousers without cuffs, and high-top shoes. When making connections or other changes in molten sulfur piping, leather protective clothing may be needed.
Gloves:
Employee must wear heat-resistant gloves when working with molten sulfur.
Eye Protection:
Employee must wear splash-proof or dust-resistant safety goggles to prevent eye contact with this substance. When making connections or other changes in molten sulfur piping, full face shields (in addition to safety glasses or goggles) should be worn.
SECTION IX - SPECIAL PRECAUTIONS OR OTHER COMMENTS
Disclaimer The information contained herein is believed to be accurate, but is not warranted to be, whether originating within the company or not. Health and safety precautions in this data sheet may not be adequate for all individuals and/or situations. Recipients are advised to confirm in advance of need that the information is current, applicable, and suitable to their circumstances. It is the end user’s responsibility to evaluate and use this product safely, and to comply with all applicable laws and regulations. No statement made in this data sheet shall be construed as a permission or recommendation for use of any product in a manner that might infringe existing patents. No warranty is made, either expressed or implied.
ISSUE DATE: 06/13/95
SUPERSEDES: 02/19/93
PAGE 10 OF 10
MATERIAL SAFETY DATA SHEET
AMMONIA SECTION I - PRODUCT IDENTIFICATION Substance:
AMMONIA
CAS Number: 7664-41-7
Trade Names / Synonyms:
Ammonia Anhydrous; Ammonia Gas; Spirit of Hartshorn
Molecular Formula:
NH3
General or Generic ID:
Inorganic Gas
Molecular Weight:
17.03
SECTION II - COMPONENTS Component:
Ammonia
Percent: > 99.0
Other Contaminants: Exposure Limits:
Ammonia 50 PPM OSHA TWA per 8-hour working day 35 PPM ACGIH STEL 50 PPM NIOSH recommended 5 minute ceiling SECTION III - PHYSICAL DATA
Description
Colorless gas at atmospheric temperature and pressure, with a pungent odor.
Melting Point:
-108°F (-78°C)
Boiling Point:
Liquid Specific Gravity: (water = 1.0)
0.77
Vapor Specific Gravity: 0.59 (air = 1.0)
Vapor Pressure:
147 PSIA (10 atm) @ 78°F (25°C)
Odor Threshold:
20 PPM
Solubility in Water:
579 g/l @ 60°F (15°C), 444 g/l @ 68°F (20°C)
-28°F (-33°C)
Other Solvents: Other Physical Data:
ISSUE DATE: 06/29/06
SUPERSEDES: 02/19/93
PAGE 1 OF 5
MATERIAL SAFETY DATA SHEET
AMMONIA SECTION IV - FIRE AND EXPLOSION INFORMATION Fire and Explosion Hazard:
Ammonia is a low fire hazard when exposed to heat or flame because it is difficult to ignite. It is a moderate explosion hazard when exposed to flame or fire. Air-ammonia mixtures can detonate in a fire.
Auto-Ignition Temperature:
1204°F (651°C)
Flash Point Temperature:
N/A
Explosive Limits in Air:
Lower: 15%
Upper:
28%
Extinguishing Media:
Water Fog.
Hazardous Decomposition Products:
Toxic fumes of NH3 and NOX.
Fire-Fighting Procedures:
Stop flow of gas. Wear self-contained breathing apparatus with a full facepiece operated in pressure-demand mode and full body protection when fighting fires.
SECTION V- HEALTH HAZARD DATA Permissible Exposure Level:
50 PPM
Threshold Limit Value:
25 PPM
Health Effects from Exposure
Swallowing:
Ingestion of a gas is unlikely.
Inhalation:
The life hazard from ammonia is due to its damage to the lungs when inhaled. When inhaled, ammonia is both an irritant and an asphyxiant, and can cause respiratory distress. Ammonia can usually be detected at levels of 20-50 PPM. There will be noticeable irritation of the eyes and nasal passages when exposed to 100 PPM, and severe irritation of the throat, nasal passages, and upper respiratory tract at 400 PPM. At 1700 PPM, there will be severe coughing and bronchial spasms, and an exposure of 30 minutes or less may be fatal. Concentrations of 5000 PPM and above are fatal almost immediately, causing serious edema of the lungs, strangulation, and asphyxiation.
Eye Contact:
This gas is dangerous to the eyes, as it causes irritation at 40-100 PPM. Prolonged exposure to 700 PPM or more can cause extensive injuries to the eyes - irritation, hemorrhages, swollen lids, corneal ulcers, even partial or total loss of sight.
Skin Contact:
Ammonia will irritate the skin, particularly if the skin is moist, to the point of causing chemical burns from prolonged exposure.
ISSUE DATE: 06/29/06
SUPERSEDES: 02/19/93
PAGE 2 OF 5
MATERIAL SAFETY DATA SHEET
AMMONIA SECTION V - HEALTH HAZARD DATA (continued) First Aid Measures Swallowing:
Treat symptomatically and supportively. Get medical attention immediately. If vomiting occurs, keep head lower than hips to prevent aspiration.
Inhalation:
Where breathing is weak, administer oxygen or mixtures of carbon dioxide and oxygen, containing not more than 5% carbon dioxide. It should be administered intermittently for periods of two minutes over a total time not to exceed fifteen minutes. If breathing has ceased, start artificial respiration immediately, by trained personnel only. Artificial respiration, when administered by an inexperienced person, is definitely hazardous following exposure to ammonia, and should be avoided where possible. The use of a pulmotor is definitely not recommended as its more violent action will irritate and may severely injure the lungs. A resuscitator used with oxygen and operated by a trained person is recommended. Keep the patient warm and still, and get medical attention immediately.
Eye Contact:
Hold the lids open and pour clean water over the eyeball and lids (or use an eye irrigation fountain). Wash thoroughly in this way for 15 minutes. A doctor, preferably an eye specialist, should be summoned immediately
Skin Contact:
Speed is essential. Strip the ammonia-saturated clothing from the body immediately. Flood affected areas continuously with clean water for at least 15 minutes. Do not cover burns with clothing or dressings. Allow them to remain open to the air.
ISSUE DATE: 06/29/06
SUPERSEDES: 02/19/93
PAGE 3 OF 5
MATERIAL SAFETY DATA SHEET
AMMONIA SECTION VI- REACTIVITY DATA Reactivity:
Stable under normal temperatures and pressures.
Incompatibilities:
Acetaldehyde Acrolein Ammonium Peroxo Disulfate Antimony Antimony Hydride Boron Boron Halides Boron Triiodide Bromine Pentafluoride Chloric Acid Chlorine Azide Chlorine Monoxide Chlorine Trifluoride Chlorites Chlorosilane Chromium Trioxide Chromyl Chloride Dichlorine Oxide Ethylene Dichloride + Liquid Ammonia Ethylene Oxide Gold Gold (III) Chloride Halogens Hexachloromelamine Hydrazine + Alkali Metals Hydrogen Bromide Hydrogen Peroxide Hypochlorous Acid Magnesium Perchlorate Mercury Nitric Acid
Polymerization:
Nitrogen Dioxide Nitrogen Tetraoxide Nitrogen Trichloride Nitrogen Trifluoride Nitryl Chloride Oxygen + Platinum Oxygen Difluoride Phosphorus Pentoxide Phosphorus Trioxide Picric Acid Potassium + Arsine Potassium + Phosphine Potassium + Sodium Nitrite Potassium Chlorate Potassium Ferricyanide Potassium Mercuric Cyanide Silver Silver Chloride Silver Nitrate Silver Oxide Sodium + Carbon Monoxide Sulfur Sulfur Dichloride Tellurium Tellurium Chloride Tellurium Hydropentachloride Tetramethyl Ammonium Amide Thionyl Chloride Thiotrithiazyl Chloride Trichloromelamine Trioxygen Difluoride
Cannot occur. SECTION VII - SPILL OR LEAK PROCEDURES
Steps to Be Taken in Case Material is Released or Spilled Notify safety personnel of significant leaks. Exclude all from area except those assigned to leak and spill control who are using full protective gear (see Section VIII). Provide ventilation. Locate and control leakage. Waste Disposal Method If water is used to knock-down vapors, it will be corrosive and toxic, and should be diked for containment. Add suitable agent to neutralize to 7 pH prior to disposal. ISSUE DATE: 06/29/06
SUPERSEDES: 02/19/93
PAGE 4 OF 5
MATERIAL SAFETY DATA SHEET
AMMONIA SECTION VIII - PROTECTIVE EQUIPMENT TO BE USED Ventilation:
Provide local exhaust or process enclosure ventilation to meet the published exposure limits. Ventilation equipment must be explosion-proof.
Respirator:
If work place exposure limit(s) of product or any component is exceeded (see Section II), a NIOSH/MSHA approved air supplied respirator is advised in absence of proper environmental control. OSHA regulations also permit other NIOSH/MSHA respirators (negative pressure type) under specified conditions (see your safety equipment supplier). Engineering or administrative controls should be implemented to reduce exposure.
Clothing:
To prevent repeated or prolonged skin contact, wear impervious clothing and boots.
Gloves:
Wear resistant gloves such as neoprene, nitrile rubber, butyl rubber.
Eye Protection:
Employee must wear splash-proof or dust resistant safety goggles and a faceshield to prevent contact with this substance. Where there is any possibility that an employee's eyes may be exposed to this substance, the employer shall provide an eye-wash fountain within the immediate work area for emergency use.
SECTION IX - SPECIAL PRECAUTIONS OR OTHER COMMENTS
DISCLAIMER The information contained herein is believed to be accurate, but is not warranted to be, whether originating within the company or not. Health and safety precautions in this data sheet may not be adequate for all individuals and/or situations. Recipients are advised to confirm in advance of need that the information is current, applicable, and suitable to their circumstances. It is the end user's responsibility to evaluate and use this product safely, and to comply with all applicable laws and regulations. No statement made in this data sheet shall be construed as a permission or recommendation for use of any product in a manner that might infringe existing patents. No warranty is made, either expressed or implied.
ISSUE DATE: 06/29/06
SUPERSEDES: 02/19/93
PAGE 5 OF 5
MATERIAL SAFETY DATA SHEET METHYLDIETHANOLAMINE SECTION I - PRODUCT IDENTIFICATION Substance:
METHYLDIETHANOLAMINE
CAS Number: 105-59-9
Trade Names / Synonyms:
MDEA; n-Methyldiethanolamine; n-Methyliminodiethanol; n-Methyl-2,2'-iminodiethanol; N,N-di(2-hydroxyethyl)-N-methylamine; 2,2'(Methylimino) bis-ethanol
Molecular Formula:
CH3-N-(CH2CH2OH)2
General or Generic ID:
Organic Base
Molecular Weight:
119.17
SECTION II - COMPONENTS Component:
Methyldiethanolamine
Percent: > 99.0
Other Contaminants:
Often stored and transported as an aqueous solution containing about 10% water by weight.
Exposure Limits:
Methyldiethanolamine There are no standards or regulations concerning MDEA. SECTION III - PHYSICAL DATA
Description:
Clear, colorless, viscous liquid.
Melting Point:
-6F (-21C)
Boiling Point:
477F (247C)
Liquid Specific Gravity: (water = 1.0)
1.042
Vapor Specific Gravity (air = 1.0)
4.11
Vapor Pressure:
< 0.0002 PSIA (0.01 mm Hg) @ 68F (20C)
Odor Threshold:
MDEA has a slight ammoniacal odor.
Solubility in Water:
MDEA is completely soluble in water.
Other Solvents: Other Physical Data:
ISSUE DATE: 01/25/95
SUPERSEDES:
PAGE 1 OF 3
MATERIAL SAFETY DATA SHEET METHYLDIETHANOLAMINE SECTION IV- FIRE AND EXPLOSION INFORMATION Fire and Explosion Hazard: MDEA is considered a slight fire hazard when exposed to heat or flame. Auto-Ignition Temperature:
N/A
Explosive Limits in Air:
not determined
Extinguishing Media:
Small Fire - dry chemical or CO2. Large Fire - water fog, alcohol foam, polymer foam, ordinary foam.
Fire-Fighting Procedures:
Wear positive pressure, self-contained breathing apparatus. SECTION V - HEALTH HAZARD DATA None established.
Permissible Exposure Level: Threshold Limit Value:
Flash Point Temperature:
260F (127°C)
None established.
Health Effects from Exposure Swallowing:
Single dose oral toxicity is low. The oral LD50 for rats is 4780 mg/kg for MDEA. Amounts ingested incidental to industrial handling are not likely to cause injury; however, ingestion of larger amounts may cause injury. Ingestion of MDEA can cause nausea, vomiting, and abdominal discomfort.
Inhalation::
At room temperature, exposure to vapors is unlikely due to physical properties. Higher temperatures may generate vapor levels sufficient to cause irritation.
Eye Contact:
May cause moderately severe irritation with corneal injury.
Skin Contact:
Prolonged or repeated exposure may cause skin irritation, even a burn. A single prolonged exposure is not likely to result in the material being absorbed through skin in harmful amounts. The dermal LD50 has not been determined.
Systemic Effects:
Repeated excessive exposures may cause kidney effects.
First Aid Measures Swallowing:
Induce vomiting if large amounts are ingested. Consult medical personnel.
Inhalation:
Remove to fresh air if effects occur. Consult a physician.
Eye Contact:
Flush eyes with large amounts of water for at least 15 minutes. Take the patient to a physician, preferably an eye specialist, at once.
Skin Contact:
Flush the affected area with plenty of water. If exposure has produced a burn, it should be treated like a thermal burn, with treatment based on the physician's judgement. Contaminated clothing should be removed and washed before reuse. Contaminated leather articles (shoes, belts, etc.) should be removed and destroyed. SUPERSEDES: PAGE 2 OF 3
ISSUE DATE: 01/25/95
MATERIAL SAFETY DATA SHEET METHYLDIETHANOLAMINE SECTION VI- REACTIVITY DATA Reactivity:
Stable under normal storage conditions.
Incompatibilities:
Incompatible with strong oxidizers and strong acids. Do not allow MDEA to contact sodium nitrite (NaNO2) or other nitrosating agents, as nitrosamines (suspected cancer-causing agents) could be formed.
Hazardous Decomposition Products:
Nitrous oxides, carbon monoxide, and/or carbon dioxide.
Polymerization
Hazardous polymerization will not occur. SECTION VII - SPILL OR LEAK PROCEDURES
Steps to Be Taken in Case Material is Released or Spilled Wear suitable protective equipment, especially eye protection. Collect for disposal. Toxic to fish; avoid discharge to natural waters. Waste Disposal Method Burn in approved incinerator. Follow all local, state, and federal requirements for disposal. SECTION VIII - PROTECTIVE EQUIPMENT TO BE USED Ventilation:
General (mechanical) room ventilation is expected to be satisfactory.
Respirator:
None required in normal use. If irritation of the nose and/or respiratory system is experienced, use an approved air-purifying respirator.
Clothing:
Use protective clothing impervious to this material. Selection of specific items such as boots, apron, or full-body suit will depend on operation.
Gloves:
Use gloves impervious to this material, such as rubber.
Eye Protection:
Use chemical goggles. SECTION IX - SPECIAL PRECAUTIONS OR OTHER COMMENTS
Avoid contact with eyes, skin, and clothing when handling and storing MDEA. handling.
Wash thoroughly after
Disclaimer The information contained herein is believed to be accurate, but is not warranted to be, whether originating within the company or not. Health and safety precautions in this data sheet may not be adequate for all individuals and/or situations. Recipients are advised to confirm in advance of need that the information is current, applicable, and suitable to their circumstances. It is the end user’s responsibility to evaluate and use this product safely, and to comply with all applicable laws and regulations. No statement made in this data sheet shall be construed as a permission or recommendation for use of any product in a manner that might infringe existing patents. No warranty is made, either expressed or implied.
ISSUE DATE: 01/25/95
SUPERSEDES:
PAGE 3 OF 3
MATERIAL SAFETY DATA SHEET SODIUM HYDROXIDE SECTION I - PRODUCT IDENTIFICATION SODIUM HYDROXIDE
Substance:
CAS Number: 1310-73-2
Trade Names / Synonyms:
Caustic; Caustic Soda; Caustic Soda Liquid; Liquid Caustic; Lye; Lye Solution; Soda Lye; Sodium Hydrate; Quaker Caustic Blend; White Caustic
Molecular Formula:
NaOH
General or Generic ID:
Alkali
Component:
Molecular Weight:
SECTION II - COMPONENTS Sodium Hydroxide
40.00
Percent: > 99.0
Other Contaminants:
Often stored and transported as an aqueous solution. Common strengths are 25, 50, and 73 weight percent NaOH.
Exposure Limits:
Sodium Hydroxide 2 mg/m3 (2 PPM) OSHA TWA for an 8-hour working day 2 mg/m3 (2 PPM) ACGIH ceiling 2 mg/m3 (2 PPM) NIOSH recommended ceiling
Description:
SECTION III - PHYSICAL DATA Pure sodium hydroxide is a white solid. When dissolved in water, NaOH forms a clear, colorless or water-white, strongly alkaline liquid. Neither form has an odor.
Melting Point:
Solid: 25 wt% solution: 50 wt% solution:
608°F (320°C) -2°F (-19°C) 50°F (10°C)
Boiling Point:
Solid: 25 wt% solution: 50 wt% solution:
2534°F (1390°C) 232°F (111°C) 288°F (142°C)
Specific Gravity: (water = 1.0)
Solid: 25 wt% solution: 50 wt% solution:
2.13 1.27 1.53
Vapor Pressure:
Solid:
0.02 PSIA (1 mm Hg) @ 1362°F (739°C)
Odor Threshold:
N/A
Solubility in Water:
At 60°F (15°C), more than 50 wt% will dissolve in water.
Other Solvents: Other Physical Data:
ISSUE DATE: 02/19/93
SUPERSEDES:
PAGE 1 OF 5
MATERIAL SAFETY DATA SHEET SODIUM HYDROXIDE SECTION IV- FIRE AND EXPLOSION INFORMATION Fire and Explosion Hazard:
Sodium hydroxide and its water solutions are not flammable. However, adding water to NaOH or solutions of NaOH can cause localized overheating due to its heat of dilution. Sodium hydroxide will generate gaseous hydrogen (which is flammable and/or explosive) when in contact with aluminum, copper, tin, zinc, and their alloys.
Auto-Ignition Temperature:
N/A
Flash Point Temperature:
N/A
Explosive Limits in Air:
Lower: N/A
Upper: N/A
Extinguishing Media:
Not combustible. Use extinguishing agents as may be suitable for material in surrounding fire.
Fire-Fighting Procedures:
Not combustible. Use clothing and safety equipment as may be suitable for sodium hydroxide and materials in the surrounding fire.
SECTION V - HEALTH HAZARD DATA Permissible Exposure Level:
2 mg/m3 (approximately 2 PPMW)
Threshold Limit Value:
2 mg/m3 (approximately 2 PPMW) ceiling
Health Effects from Exposure Swallowing:
Acutely toxic if swallowed, causing severe burns and scarring to the mouth, throat, esophagus, and stomach, and may lead to death. Squamous cell carcinoma of the esophagus can occur years after the exposure.
Inhalation:
Inhalation of dust or mist can cause injury to the entire respiratory tract. The effects of inhalation depend on the severity of the exposure, ranging from mild irritation of the mucous membranes to severe pneumonitis.
Eye Contact:
Contact with the eyes may cause irritation and, with greater exposure, severe burns and possible blindness.
Skin Contact:
Skin contact may cause burns, frequently with deep ulceration and scarring. Prolonged contact, even with dilute solutions, can cause tissue damage.
ISSUE DATE: 02/19/93
SUPERSEDES:
PAGE 2 OF 5
MATERIAL SAFETY DATA SHEET SODIUM HYDROXIDE SECTION V - HEALTH HAZARD DATA (continued) First Aid Measures Swallowing:
Do not induce vomiting - this will cause further damage to the throat and esophagus. Dilute by giving water to the patient immediately. Vinegar, 1% acetic acid solution, citrus fruit juices, or 5% citric acid solution may also be administered to help neutralize the alkaline solution. Follow this with milk, egg white in water, or milk of magnesia. Keep the patient warm and still, and summon a physician immediately.
Inhalation:
Remove the patient to fresh air at once. If breathing has stopped, begin artificial respiration immediately. Keep the patient warm and still, and summon a physician immediately.
Eye Contact:
Immediately begin flushing the eyes with large amounts of water, preferably with an eye wash fountain. Continue flushing for at least 15 minutes, forcibly holding the eyelids apart and rotating the eyeball, to ensure complete irrigation of all eye and lid tissue. A physician, preferably an eye specialist, should be summoned immediately.
Skin Contact:
Immediately flush the affected areas with large amounts of water. If large areas of the body are contaminated, or if clothing has been penetrated to the skin, immediately use a safety shower, preferably removing clothing while under the shower. Continue flushing the areas for at least 15 minutes. If available, follow the water flush with a generous application of vinegar or 1% acetic acid solution to neutralize the residual NaOH. After the acid treatment, apply a good protective dressing as with any other burn and take the patient to a physician. Contaminated clothing should be washed before reuse. Contaminated leather articles (shoes, belts, etc.) should be discarded.
ISSUE DATE: 02/19/93
SUPERSEDES:
PAGE 3 OF 5
MATERIAL SAFETY DATA SHEET SODIUM HYDROXIDE SECTION VI- REACTIVITY DATA Reactivity:
Stable.
Incompatibilities:
Acetaldehyde Acetic Acid Acetic Anhydride Acrolein Acrylonitrile Allyl Alcohol Allyl Chloride Aluminum Chlorine Trifluoride Chloroform + Methanol Chlorohydrin (Chlorhydrin) 4-Chloro-2-methylphenol Chloronitrotoluene Chlorosulfonic Acid (Chlorosulfuric Acid) Cinnamaldehyde Copper Cyanogen Azide Diborane (Boron Hydride) 1,2-Dichloroethylene Difluoroethane Ethylene Cyanohydrin (Hydracrylonitrile) Glyoxal Hydrochloric Acid (Hydrogen Chloride) Hydrofluoric Acid (Hydrogen Fluoride)
Polymerization:
Hazardous polymerization cannot occur.
Other Hazards:
Adding water to sodium hydroxide or sodium hydroxide solutions may cause localized overheating and spattering.
ISSUE DATE: 02/19/93
SUPERSEDES:
Hydroquinone Magnesium Maleic Anhydride Methanol + Tetrachlorobenzene 4-Methyl-2-nitrophenol 3-Methyl-2-penten-4-yn-1-ol Nitric Acid Nitroethane (forms shock-sensitive salts) Nitromethane (forms shock-sensitive salts) Nitroparaffins (forms shock-sensitive salts) Nitropropane (forms shock-sensitive salts) Oleum (fuming Sulfuric Acid) Pentol Phosphorus Phosphorus Pentoxide ß-Propiolactone (2-Oxetanone) Strong Mineral or Organic Acids Sulfuric Acid 1,2,4,5-Tetrachlorobenzene Tetrahydrofuran Tin 1,1,1-Trichloroethanol Trichloroethylene Trichloronitromethane Trifluoride Water Zinc Zirconium
PAGE 4 OF 5
MATERIAL SAFETY DATA SHEET SODIUM HYDROXIDE SECTION VII - SPILL OR LEAK PROCEDURES Steps to Be Taken in Case Material is Released or Spilled Cleanup personnel must wear proper protective equipment (refer to Section VIII). Completely contain spilled material with dikes, sandbags, etc., and prevent run-off into ground or surface waters or sewers. Recover as much material as possible into containers for disposal. Remaining material may be diluted with water and neutralized with dilute hydrochloric acid. Neutralization products, both liquid and solid, must be recovered for disposal. Waste Disposal Method Recovered solids or liquids may be sent to a licensed reclaimer or disposed of in a permitted waste management facility. Consult federal, state, or local disposal authorities for approved procedures.
SECTION VIII - PROTECTIVE EQUIPMENT TO BE USED Ventilation:
Ventilation is not usually required for caustic solutions. Avoid creation of mist or spray. If present, wear appropriate safety clothing and provide local exhaust systems.
Respirator:
Provide mist protection where applicable. respirators.
Clothing:
Employees should wear impervious rubber, neoprene, or vinyl boots, overalls, and/or full-body suits.
Gloves:
Use impervious rubber, neoprene, or vinyl gloves.
Eye Protection:
Use chemical goggles and face shield.
Use NIOSH or MSHA approved
SECTION IX - SPECIAL PRECAUTIONS OR OTHER COMMENTS When diluting sodium hydroxide, use agitation (mixing) and add the concentrated sodium hydroxide to water at a controlled rate to control the heat of dilution and avoid spattering. Never add water to sodium hydroxide.
Disclaimer The information contained herein is believed to be accurate, but is not warranted to be, whether originating within the company or not. Health and safety precautions in this data sheet may not be adequate for all individuals and/or situations. Recipients are advised to confirm in advance of need that the information is current, applicable, and suitable to their circumstances. It is the end user’s responsibility to evaluate and use this product safely, and to comply with all applicable laws and regulations. No statement made in this data sheet shall be construed as a permission or recommendation for use of any product in a manner that might infringe existing patents. No warranty is made, either expressed or implied.
ISSUE DATE: 02/19/93
SUPERSEDES:
PAGE 5 OF 5
MATERIAL SAFETY DATA SHEET 1. CHEMICAL PRODUCT AND COMPANY INFORMATION Product Name:
Activated Alumina S-2001/ESM-221
Product Use:
Alumina
ASM Catalysts, LLC 8550 United Plaza Blvd., Suite 702 Baton Rouge, LA 70809-0200 USA Tel.: +1-225-752-4276 Fax: +1-225-922-4550
Euro Support B.V. Kortegracht 26 3811 KH Amersfoort The Netherlands Tel: +31-33-4650465 Fax: +31-33-4650721
2. HAZARDS IDENTIFICATION Emergency Overview: Repeated or prolonged exposure may irritate eyes, skin and respiratory system. The product gets hot as it first adsorbs water. Form: Spheres Color: White Potential Health Effects: Primary Routes of Exposure: Contact with skin and eyes. Exposure may also occur via inhalation or ingestion if product dust is generated. Eye Contact: Dust and/or product may cause eye discomfort and/or irritation seen as tearing and reddening. Skin Contact: Repeated or prolonged exposure may cause skin irritation. Ingestion: The product is considered to have a low order of oral toxicity. Inhalation: Exposure to dust particles generated from this material may cause irritation of the respiratory tract. Irritation may be accompanied by coughing and chest discomfort. Chronic Effects: Prolonged or repeated inhalation of dust generated from this material may cause lung injury.
Activated Alumina S-2001/ESM-221 Page 1 of 9
Revision Number: 1 June 2008
Carcinogenicity Classification: International Agency for Research on Cancer (IARC): Neither the product nor the components are classified. U.S. National Toxicology Program (NTP): Neither the product nor the components are classified. U.S. Occupational Safety and Health Administration (OSHA): Neither the product nor the components are classified or regulated. American Conference of Governmental Industrial Hygienists (ACGIH): Aluminum oxide – Not Classifiable as a Human Carcinogen (A4).
3. COMPOSITION/INFORMATION ON INGREDIENTS INGREDIENT & CAS NO. Aluminum oxide (non-fibrous) 1344-28-1 Water 7732-18-5
ACGIH TLV-TWA
OSHA PEL-TWA
<95
1(R)
<10
N.E.
15 (TD) 5(R) N.E.
% WEIGHT
Abbreviations: N.A. - Not Applicable N.E. - None Established STEL - Short Term Exposure Limit
RD R F
- Respirable Dust - Respirable Fraction - Respirable Fibers
Fu I TD
- Fume - Inhalable - Total Dust
UNITS mg/m3 N.A.
IS FuD SC
- Insoluble - Fume and Dust - Soluble Compounds
4. FIRST AID MEASURES Eye contact: Flush immediately with plenty of water for at least 15 minutes. If eye irritation persists, consult a physician. Skin contact: Wash off with soap and plenty of water. If skin irritation persists, call a physician. After inhalation: Remove the victim into fresh air. If symptoms persist, call a physician. After ingestion: Drink at least 2 glasses of water. Obtain medical attention. Never give anything by mouth to an unconscious person. Notes to physician: This product is a desiccant and generates heat as it adsorbs water. Symptomatic treatment is advised. The used product can retain material of a hazardous nature. Identify that material and treat symptomatically.
Activated Alumina S-2001/ESM-221 Page 2 of 9
Revision Number: 1 June 2008
5. FIRE FIGHTING MEASURES Suitable extinguishing media: Non-combustible. Use extinguishing media for surrounding fire. Unsuitable extinguishing media: N.A. Fire and explosion hazards: The product itself does not burn. The used product can retain material of a hazardous nature. Identify that material and inform the fire fighters. Special protective equipment: In the case of respirable dust and/or fumes, use self-contained breathing apparatus and dust impervious protective suit. Flash point: N.A.
6. ACCIDENTAL RELEASE MEASURES Personal protection: See Section 8. Environmental precautions: No special environmental precautions required. Clean-up: Sweep, shovel or vacuum spilled product into appropriate containers (do not use a vacuum if material has contacted a hydrocarbon material). Pick-up and arrange disposal without creating dust. Never use spilled product. Spilled product should be disposed of in accordance with all applicable government regulations.
7. HANDLING AND STORAGE Handling: Handle and open container with care. Avoid formation of dust particles. Avoid contact with skin and eyes. Provide an electrical ground connection during loading and transfer operations to avoid static discharge in an explosive atmosphere and to prevent persons handling the product from receiving static shocks. Storage: Store in original container. Keep in a dry place.
8. EXPOSURE CONTROLS/PERSONAL PROTECTION Engineering measures: Where natural ventilation is inadequate, especially in confined areas, use mechanical ventilation, other engineering controls or respiratory protection to prevent inhalation of product dust. Personal protection equipment: Handle in accordance with good industrial hygiene and safety practice. Eye protection: Safety glasses or goggles. Hand protection: Protective gloves. Skin and body protection: Work uniform and gloves to prevent prolonged contact. Respiratory protection: In case of insufficient ventilation, wear suitable respiratory equipment. Air-purifying respirator with NIOSH classification N-95 filter or P-95 (or equivalent) if oil/liquid aerosols are present (42 CFR 84).
Activated Alumina S-2001/ESM-221 Page 3 of 9
Revision Number: 1 June 2008
9. PHYSICAL AND CHEMICAL PROPERTIES These data do not represent technical or sales specifications.
Form: Spheres
Color: White
Odor: None
pH: 9 – 11 (AS)
Boiling point/range: None
Melting point/range: N.A.
Flash point: N.A.
Autoignition temperature: N.A.
Bulk density: 38-60 lbs/ft3
Explosion limits: N.A.
Vapor pressure: N.A.
Relative density/Specific gravity: 3.0
Vapor density: N.A.
Viscosity: N.A.
Water solubility: Insoluble
Solubility: N.D.
10. STABILITY Stability: Stable Hazardous Decomposition Products: No decomposition if used as directed. Hydrocarbons and other materials that contact the product during normal use can be retained on the product. It is reasonable to expect that decomposition products will come from these retained materials of use. If the product is subject to extreme temperatures or chemical conditions, decomposition may occur and he product will include the oxides shown in Section 3. Conditions/Materials to avoid: Reacts violently with chlorine trifluoride, producing flames. May cause ethylene oxide to polymerize violently, releasing heat.
Activated Alumina S-2001/ESM-221 Page 4 of 9
Revision Number: 1 June 2008
11. TOXICOLOGICAL INFORMATION Acute toxicity: LD50/oral/rat: No data available. LD50/dermal/rabbit: No data available. LD50/inhalation/rat: No data available. Chronic toxicity: Classification of Ingredients EC Carcinogenic: Not listed.
Carcinogenicity (ACGIH): A4 (Aluminum oxide)
EC Mutagenic: Not listed.
IARC classification: Not listed.
EC Toxic for Reproduction: Not listed. Routes of exposure: Exposure may occur via inhalation, contact with skin and eyes. Irritation: Skin (rabbit): No data available. Eye (rabbit): No data available. Additional product information: Avoid repeated exposure. Additional component information: No data available.
12. ECOLOGICAL INFORMATION Mobility: No data available.
Biodegradation: No data available.
Bioaccumulation: No data available.
Aquatic toxicity: No data available.
Further Information: No information available.
Activated Alumina S-2001/ESM-221 Page 5 of 9
Revision Number: 1 June 2008
13. DISPOSAL CONSIDERATIONS Provisions relating to waste: EPA – Resource Conservation and Recovery Act (RCRA) Hazardous and Solid Waste Management Regulations. Disposal information: This product (in its fresh unused state) is not listed by generic name or trademark name in the U.S. EPA’s RCRA regulations and does not possess ay of the four identifying characteristics of hazardous waste (ignitability, corrosivity, reactivity or toxicity). Materials of a hazardous nature that contact the product during normal use may be retained on this product. The user of the product must identify the hazards associated with the retained material in order to assess the waste disposal options.
14. TRANSPORT INFORMATION Proper shipping name: Not applicable.
UN-No.: N.A.
Packing group: N.A.
Transport mode
Class
U.S. DOT:
Not regulated.
Reportable N.A. Quantity: Marine Pollutant DOT: No
N.A.
ADR/RID:
Not regulated.
Danger Code:
N.A.
N.A.
IMDG:
Not regulated.
Marine pollutant: EmS:
No N.A.
N.A.
IATA:
Not regulated.
Instr. Passenger: Instr. Cargo:
N.A. N.A.
N.A.
Additional Information
Activated Alumina S-2001/ESM-221 Page 6 of 9
Remarks
Revision Number: 1 June 2008
15. REGULATORY INFORMATION United States Toxic Substances Control Act (TSCA): All the ingredients of this mixture are registered on the TSCA Chemical Substance Inventory. CERCLA (Comprehensive Environmental Response, Compensation, and Liability Act) Reportable Quantity: The following component(s) of this product is/are subject to release reporting under 40 CFR 302 when release exceeds the Reportable Quantity (RQ): --None— SARA Title III (Superfund Amendments and Reauthorization Act of 1986): Section 302 (Extremely Hazardous Substances): The following component(s) of this product is/are subject to the emergency planning provisions of 40 CFR 355 when there are amounts equal to or greater than the Threshold Planning Quantity (TPQ): --None— Section 313 (toxic Chemicals): The following component(s) have been specified as Toxic Chemicals under SARA Section 313 and may be subject to the Toxic Release Inventory (TRI) reporting requirements under 40 CFR 372: --None— The following components are listed in U.S. State Regulations: State Reg Reference: State Reg Reference: California – Proposition 65:
None.
Massachusetts Right-to-Know:
Aluminum oxide
New Jersey Right-To-Know:
Aluminum oxide
Pennsylvania Right-to-Know:
Aluminum oxide
Note: Other U.S. State Regulations may exist, check your local sources if available.
Activated Alumina S-2001/ESM-221 Page 7 of 9
Revision Number: 1 June 2008
Canada Canadian Hazardous Products Act: This product is not classified as a controlled product under regulations pursuant to the Federal Hazardous Product Act (e.g. WHMIS). Canadian Environmental Protection Act: All the ingredients of this mixture are notified to CEPA and on the DSL (Domestic Substances List).
European Union (EU) European Inventory of Existing Commercial Chemical Substances: All components of this product are included in EINECS/ELINCS. Council of European Communities Directive on Classification, Packaging and Labeling of Dangerous Substances/Preparation (67/548/EEC & 1999/45/EC, as amended): No Dangerous Goods Label Required. Additional Governmental Inventories Australia – Inventory of Chemical Substances (AICS): All the ingredients of this mixture appear on the AICS. China – All the ingredients of this mixture appear on the China Inventory. Japan – Existing and New Chemical Substances (ENCS): All the ingredients of this mixture appear on the ENCS. Korea – Existing and Evaluated Chemical Substances (ECL): All the ingredients of this mixture appear on the ECL. Philippines – Inventory of Chemicals and Chemical Substances (PICCS): All the ingredients of this mixture appear on the PICCS.
Activated Alumina S-2001/ESM-221 Page 8 of 9
Revision Number: 1 June 2008
16. OTHER INFORMATION HMIS™ - Hazardous Material Identification System: HMIS™ Ratings: 0-minimal hazard, 1-slight hazard, 2-moderate hazard, 3-serious hazard, 4-severe hazard
HEALTH: FLAMMABILITY: REACTIVITY:
1 0 1
For additional information concerning this product, contact the following: ASM Catalysts, LLC 8550 United Plaza Blvd., Suite 702 Baton Rouge, LA 70809-0200 USA Tel: +1-225-752-4276, Fax: +1-225-922-4550
Euro Support B.V. Kortegracht 26 3811 KH Amersfoort The Netherlands Tel: +31-33-465-0465, Fax: +31-33-465-0721
The data and recommendations presented in this data sheet concerning the use of our product and the materials contained therein are believed to be accurate and are based on information which is considered reliable as of the date hereof. However, the customer should determine the suitability of such materials for his purpose before adopting them on a commercial scale. Since the use of our products by others is beyond our control, no guarantee, express or implied, is made and no responsibility assumed for the use of this material or the results to be obtained therefrom. Information on this form is furnished for the purpose of compliance with Government Health and Safety Regulations and shall not be used for any other purposes. Moreover, the recommendations contained in this data sheet are not to be construed as a license to operate under or a recommendation to infringe, any existing patents, nor should they be confused with state, municipal or insurance requirements, or with national safety codes.
Activated Alumina S-2001/ESM-221 Page 9 of 9
Revision Number: 1 June 2008
Material Safety Data Sheet (MSDS) MSDS Number: 6179-12
01/26/2010
EMERGENCY ASSISTANCE
CHEMTREC (US): 1-800-424-9300
CANUTEC (Canada): 613-996-6666
CHEMTREC (International): +1-703-527-3887 (Call Collect)
SECTION I. PRODUCT:
MATERIAL IDENTIFICATION
CRITERION 234 CATALYST
COMMON NAME: PRODUCT USE:
Metal Oxide Hydrotreating Catalyst
SECTION 2. COMPOSITION/INFORMATION ON INGREDIENTS COMPONENTS OF THE MATERIAL Component Chemical CAS Formula Al2O3 1344-28-1 Aluminum oxide CoO 1307-96-6 Cobalt oxide MoO3 Molybdenum oxide 1313-27-5
SECTION 3.
Concentration 74 - 98 % 1-5% 10 - 19 %
HAZARDS IDENTIFICATION
EMERGENCY OVERVIEW Physical Appearance: Blue Extrudates or Spheres. Odorless Human Health Hazards: Irritating to eyes and respiratory system. May cause allergic reaction (rash) with skin contact and asthma-like allergic reaction by inhalation in sensitive individuals. Physical Hazards: No specific hazards. Environmental Hazards: Toxic to aquatic organisms, may cause long-term adverse effects in the aquatic environment.
Page 1 of 8
CRITERION 234 CATALYST
MSDS Number:
6179
Potential Health Effects Eye: Mildly irritating to eyes. Skin: Mildly irritating to the skin. May cause contact dermatitis (allergic skin rash) in cobalt sensitive individuals.
Inhalation: Dusts may be irritating to the nose, throat and respiratory tract. May cause sensitization by inhalation due to presence of a cobalt compound. Existing respiratory diseases may be aggravated by exposure to this material. Ingestion: Low-level cobalt ingestion is known to cause effects on the heart after a short-term exposure. The symptoms of heart damage may be a swelling of the feet (edema) and shortness of breath on exertion or when lying flat on the back (supine). Other Health Effects: Molybdenum compounds have a low order of toxicity, may be irritating and may cause anemia. SECTION 4. FIRST AID MEASURES Eye Contact: Flush eyes with water. If persistent irritation occurs, get medical attention. Skin Contact: Wash skin with water and, if available, soap. If persistent irritation occurs, get medical attention. Inhalation: Move to fresh air. If rapid recovery does not occur, get medical attention. Ingestion: Do not induce vomiting. Give nothing by mouth. Get medical attention immediately. Note to Physicians: Treat symptomatically. If skin sensitization has developed and a causal relationship has been confirmed, further exposure should not be allowed. SECTION 5. FIRE FIGHTING MEASURES Extinguishing Media: Material will not burn; use an extinguishing medium appropriate for the surrounding fire.
SECTION 6. ACCIDENTAL RELEASE MEASURES Precautionary Measures: Do not breathe dust. Avoid contact with skin and eyes. Avoid dust generation. Wear suitable protective clothing and gloves. Wear a NIOSH approved respirator if there is a possibility of exposures above the established occupational exposure limits. (See Section 8 for exposure limits.) Spill Management: Prevent contamination of soil and water. Do not wash spills into sewers or other public water systems. Prevent further leakage or spillage and prevent from entering drains.
Page 2 of 8
CRITERION 234 CATALYST
MSDS Number:
6179
Spill Disposal: Shovel up and place in a labeled, sealable container for subsequent safe disposal. Environmental Compliance: Refer to latest state or local regulations to determine if there are disposal or reporting requirements.
SECTION 7. HANDLING AND STORAGE Handling Recommendations: Avoid contact with skin and eyes. Avoid dust generation. Do not breathe dust. Do not eat, smoke or drink in areas where catalyst is present. Use only in well ventilated areas. Use local exhaust extraction. Take precautionary measures against static discharge. Ground all equipment. Storage Recommendations: Keep container tightly closed and dry. Reseal plastic liner.
SECTION 8. EXPOSURE CONTROLS/PERSONAL PROTECTION Engineering Controls: Use only in well ventilated areas. Use local exhaust extraction. Hygiene Measures: Avoid contact with material. Wash hands thoroughly after handling. Do not reuse clothing if contaminated until thoroughly decontaminated. Respiratory Protection: Use either an atmosphere-supplying respirator or an air-purifying respirator for particulates. Eye Protection: Wear safety goggles or glasses to prevent eye contact. Hand Protection: Wear neoprene, nitrile, PVC or latex gloves to prevent contact. Body Protection: When there is a possibility of exposure wear a one piece coated overall with integral hood, safety boots, chemical-resistant without lace holes. Chemical Name
Authority
Limits
Special Notations
Aluminum oxide Aluminum oxide Aluminum oxide Cobalt oxide
OSHA OSHA ACGIH OSHA
PEL 15 mg/m³ PEL 5 mg/m³ TWA 10 mg/m³ PEL 0.1 mg/m³
Cobalt oxide Cobalt oxide Cobalt oxide Molybdenum oxide
ACGIH ACGIH ACGIH OSHA
TWA 0.02 mg/m³ BEI 15 µg/m³ BEI 20 µg/m³ PEL 15 mg/m³
total dust respirable dust total dust metal dust & fumes; as Co; Cancer: 3 as Co as creatinine BEI as Mo; total dust
Page 3 of 8
CRITERION 234 CATALYST
Molybdenum oxide Molybdenum oxide
SECTION 9.
OSHA ACGIH
PEL 5 mg/m³ TWA 10 mg/m³
MSDS Number:
6179
as Mo; respirable dust as Mo; total dust
PHYSICAL AND CHEMICAL PROPERTIES Product
Physical & Chemical Properties Appearance and Odor: Solubility in water: Bulk density (solids): Melting point:
Characteristics Blue Extrudates or Spheres. Odorless <5% 0.48 g/cc ~3700
SECTION 10. STABILITY AND REACTIVITY Stability: Stable. Hygroscopic. Materials To Avoid: Strong acids, strong bases, strong oxidizing agents.
SECTION 11. TOXICOLOGICAL INFORMATION The hazard determination and the information presented below is based on available data derived from testing for the material, hazardous components of this material and/or a testing on a substantially similar material(s). The material tested is indicated in the data.
Route Dermal
Acute Lethality Material Tested Molybdenum oxide
Route Dermal Inhalation
Sensitization Material Tested Cobalt oxide Cobalt oxide
LD/LC50 >2000 mg/kg
Description Sensitizer Sensitizer
Species Rat
Species Human Human
Other Health Effects: Cobalt was used as a defoaming agent in beer at 1 ppm. After a few weeks of exposure beer drinkers were found to have myocardial effects. Deaths were reported. Medical evaluations found myocardial infarction. In a lifetime feeding study with cobalt in hamsters, no statistically significant increases in tumors were seen. Carcinogenicity: Cobalt oxide is classified by: IARC as a possible human carcinogen (Group 2B)
Page 4 of 8
CRITERION 234 CATALYST
MSDS Number:
6179
SECTION 12. ECOLOGICAL INFORMATION Ecotoxicological data have not been determined specifically for this material. The information given below is based on knowledge of the components and the ecotoxicology of similar products. Toxicity to Aquatic Organisms: Toxic to aquatic organisms, may cause long-term adverse effects in the aquatic environment. Persistence & Bioaccumulation: Not inherently biodegradable. Mobility: Sinks in water. If product enters soil, one or more constituents will be mobile and may contaminate groundwater. Sewage Treatment: Not toxic at the limit of water solubility.
SECTION 13. DISPOSAL CONSIDERATIONS Product disposal: Recover or recycle, if possible. Otherwise: Send to an approved contractor for regeneration or metal recovery or dispose with a licensed disposal contractor. Waste Disposal: If product is unused, see above. If used, evaluate the toxicity and physical properties of the material you have generated and dispose of the material in accordance with local, state and federal regulations. Container Disposal: Empty containers may contain residues. Ensure container is properly cleaned. Remove all packaging for recovery or waste disposal. DO NOT USE CONTAINER FOR OTHER PURPOSES. Regulatory Controls: Comply with all federal, state and local laws regulating the handling and disposal of wastes. SECTION 14. TRANSPORTATION INFORMATION Transport Statement: Not dangerous for conveyance under USA DOT, Canadian TDG, and IATA/ICAO codes. Consult local laws to determine transportation regulations. U. S. A. - DEPARTMENT OF TRANSPORTATION (DOT) Not regulated by DOT (USA). CANADA - TRANSPORTATION OF DANGEROUS GOODS (TDG) Not dangerous for conveyance under Canadian TDG. Maritime transport (IMO) UN No. Proper Shipping Name Class Packing Group Hazard symbol
UN 3077 ENVIRONMENTALLY HAZARDOUS SUBSTANCE, SOLID, N.O.S. ( Cobalt compounds ) 9 III , MARINE POLLUTANT MISCELLANEOUS DANGEROUS SUBSTANCES AND ARTICLES ENVIRONMENT
Page 5 of 8
CRITERION 234 CATALYST
MSDS Number:
Air transport ICAO/IATA Not dangerous for conveyance under IATA/ICAO codes. SECTION 15.
REGULATORY INFORMATION
National Authority EINECS/ELINCS TSCA MITI DSL/NDSL TCCL AICS PICCS IECS
National Inventories Country EC USA Japan Canada Korea Australia Philippines China
Status All ingredients listed. All ingredients listed. All ingredients listed. All ingredients listed. All ingredients listed. All ingredients listed. All ingredients listed. All ingredients listed.
PRODUCT SAFETY CLASSIFICATIONS Canada WHMIS Canadian - Workplace Hazardous Materials Information System (WHMIS) Class D - Toxic and Infectious Materials Division 2 - Materials Causing other Toxic Effects Subdivision A - Very Toxic Materials
California Proposition 65 Name on List Cobalt oxide
Classification Carcinogen
Massachusetts Aluminum oxide
Right-To-Know Substances List
Pennsylvania Aluminum oxide Molybdenum oxide
Right-To-Know Hazardous Substance PA Environmental Hazard E (1 % threshold)
Page 6 of 8
6179
CRITERION 234 CATALYST
MSDS Number:
6179
European Community CONTAINS COBALT OXIDE / MOLYBDENUM OXIDE Xn: Harmful N: Dangerous to the Environment Harmful Dangerous to the Environment R48/20/22: Harmful: danger of serious damage to health by prolonged exposure through inhalation and if swallowed. R42/43: May cause sensitization by inhalation and skin contact. R36/37: Irritating to eyes and respiratory system. R51/53: Toxic to aquatic organisms, may cause long-term adverse effects in the aquatic environment. S22: Do not breathe dust. S24: Avoid contact with skin. S37/39: Wear suitable gloves and eye/face protection. S61: Avoid release to the environment. Refer to special instructions/Safety data sheets.
Label Name Hazard Symbols Classification Risk Phrases
Safety Phrases
NATIONAL ENVIRONMENTAL AND SAFETY REGULATIONS
Superfund Amendments and Reauthorization Act (SARA) SARA 311/312 Classification: Immediate (acute) health hazard Delayed health hazard SARA 313 Chemicals: Cobalt compounds Molybdenum oxide SECTION 16.
OTHER INFORMATION
COMPANY NAME:
Criterion Catalysts & Technologies L.P. 16825 Northchase Drive, 2 Greenspoint Plaza Houston, Tx. 77060 (USA) +1 281 874 2600 +1 281 874 2641 (FAX)
MSDS Prepared By:
CRI/Criterion, Inc. 16825 Northchase Drive, Suite #1110
Houston, TX 77060 (USA) +1 281-874-2600 (USA CST) [email protected] Uses and restrictions: Use as a raw material/intermediate for catalyst manufacture, as a catalyst for refinery processing or for petrochemicals manufacture. MSDS Distribution: The information in this document should be made available to all who may handle the product.
Page 7 of 8
CRITERION 234 CATALYST
MSDS Number:
6179
Amendment Notation: Amendments from the previous version of the MSDS are indicated by two vertical bars in the left margin and the section is highlighted. Disclaimer: This information is based on our current knowledge and is intended to describe the product for the purposes of health, safety and environmental requirements only. It should not, therefore, be construed as guaranteeing any specific property of the product.
Issue Date: 01/25/2010 US/Canada - (English)
Page 8 of 8
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
Table of Contents 3. GENERAL .................................................................................................................... 3-1 3.1 ORGANIZATION ................................................................................................... 3-1 3.2 GENERAL PRECOMMISSIONING PROCEDURES ............................................. 3-2 3.2.1 Mechanical ..................................................................................................... 3-2 3.2.2 Electrical ......................................................................................................... 3-3 3.2.3 Instrumentation ............................................................................................... 3-5 3.3 DESIGN BASIS ..................................................................................................... 3-7 3.3.1 Plant Capacity ................................................................................................ 3-7 3.3.2 Sulfur Block Feed Streams ............................................................................. 3-7 3.3.3 Effluent Stream Conditions ........................................................................... 3-12 3.3.4 Other Design Requirements ......................................................................... 3-13 3.3.5 Utility Information .......................................................................................... 3-14 3.3.6 Plant Site Conditions .................................................................................... 3-16
Issued 30 August 2011
General
Page 3-i
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
3. GENERAL 3.1
Organization This manual discusses the startup and operation of the new Sulfur Block, consisting of an Amine Treating Unit, an Amine Regeneration Unit, a Sour Water Stripping Unit, two Sulfur Recovery Units, a common Tailgas Thermal Oxidation Unit, Tailgas Cleanup Unit, and Sulfur Degassing Unit, on a systems basis. The systems are discussed individually, but are also grouped together into two main categories. The categories and systems, in order of presentation, are: A.
B.
UTILITY SYSTEMS 1.
Power Distribution
2.
Plant Control Systems
3.
Utility Systems
PROCESS SYSTEMS 1.
Amine Treating / Amine Regeneration
2.
Sour Water Stripping
3.
Sulfur Recovery
4.
Tailgas Thermal Oxidation
5.
Tailgas Cleanup
6.
Sulfur Degassing and Transfer
7.
Solvent Storage and Drain
The systems are presented in the sequence required for a normal startup. That is, electric power is usually the first system commissioned and the Sulfur Degassing system is usually the last.
Issued 30 August 2011
General
Page 3-1
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
3.2
General Precommissioning Procedures Prior to placing each of the Amine Treating, Sour Water Stripping, Sulfur Recovery, Tailgas Thermal Oxidation, Tailgas Cleanup, Sulfur Degassing, and associated systems in operation, check-out of the various systems should be made in as much detail as practical. This will help eliminate problems during startup and familiarize personnel with the plant equipment.
3.2.1
Mechanical A complete check of all plant construction should be made to assure it is in accordance with the Piping & Instrument Diagrams and equipment manufacturer's recommendations. Any discrepancies or defects should be corrected before attempting to put the plant in operation. Each piece of equipment should be checked against the vendor's recommendations and guidelines. Some of the steps that should be taken to ensure the plant is mechanically ready for startup include:
Issued 30 August 2011
A.
Make an internal check of vessels for correct installation of mist pads, support grids, trays, vortex breakers, etc.
B.
Check to ensure suction strainers are installed in all pump suction lines before the pumps are operated for any reason.
C.
Perform all necessary pressure tests. After tests, remove the test blinds, giving special attention to those below relief valves.
D.
Check the nameplate on each relief valve to ensure it has been installed in the proper location.
E.
Clear the plant area involved in startup of construction equipment and debris that could cause fire or injuries.
F.
Check for proper rotation of all motors.
G.
Check all motors and rotating equipment to ensure proper lubrication and that belts are free and properly aligned.
H.
Check pumps for packing where required (follow manufacturer's instructions).
I.
Check filters to ensure they contain properly installed filter elements or charcoal media and that adequate spare elements are on hand.
General
Page 3-2
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK J.
Prior to commencement of startup, the following items should be on hand: (1)
Spare parts
(2)
Lubricants, greases, etc.
(3)
Chemicals, or provisions to provide chemicals
(4)
Spare filter elements
(5)
Any special tools required
(6)
Fire extinguishers
(7)
Safety equipment
(8)
Oxygen analyzer
(9)
Laboratory test equipment
(10) Pertinent test procedures
3.2.2
Electrical The purpose of commissioning electrical components and control systems prior to the startup of a plant is to ensure correct performance per specifications under simulated operating conditions.
WARNING
POWER SHOULD NOT BE APPLIED TO ANY ELECTRICAL DEVICE, CONTROL PANEL, CONTROL SYSTEM, OR MOTOR IN THE FACILITY UNTIL SUCH TIME THAT ALL POWER AND CONTROL WIRING FOR THE FACILITY HAS BEEN TERMINATED AND PROPERLY MADE-UP ON EACH CONDUCTOR END. Electrical power circuits must be energized in order to make an electrical check-out prior to startup. Some of the following procedures may be accomplished during construction; however, before the plant is put in operation the following should be completed:
Issued 30 August 2011
General
Page 3-3
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
Issued 30 August 2011
A.
Test each circuit phase-to-ground.
with
B.
Test the motor feeder with the motor out of the circuit. After motors are connected, make phase-to-ground tests on the motor circuit.
C.
Test the control circuit with the push-buttons and over-current devices connected.
D.
Test the feeders to the panel-boards with the branch circuits open.
E.
Test the power feeder with switches and circuit breakers in place.
F.
Megger the power and control circuits of the switchgear and motor control centers.
G.
Check the control switches, alarm and shutdown devices, indicating lights, and meters for proper operation.
H.
Install thermal overload heaters where required after checking them against the manufacturer's heat tables and motor nameplate data to ensure the heaters are of the proper size and rating. Check operation of time-delay under-voltage devices for proper timing, proper restart, and dropout action.
I.
Megger motor windings and transformer windings for ground. Examine them for moisture accumulation. If evidence of moisture accumulation is found, the equipment must be dried before being placed in operation.
J.
Check circuit breakers, motor starters, switches, relays, and other equipment for loose connections (both mechanical and electrical) and to see that contacts and working parts are correctly aligned and free from dust and foreign material.
K.
Check motors for proper rotation, lubrication, and alignment.
L.
For circuit breakers with adjustable trips, check the thermal rating against the value shown on the drawings and adjust the magnetic setting to the "LO" position. On magnetic-only (instantaneous trip) breakers in combination starters, the instantaneous setting should be adjusted so that the setting is just above the motor in-rush current. Lower the setting to the point where the contacts open when the motor is started, then raise the setting in small increments to the point where the breaker allows the motor to start.
General
a
megger,
phase-to-phase
and
Page 3-4
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
3.2.3
M.
Ensure that all individual motor starter and feeder breakers are in the "OFF" position.
N.
Provide power to the MCC by engaging the main feeder breaker.
O.
Turn the MCC feeder breakers to the "ON" positions, applying power to all individual circuit breakers, contactors, and motor switches.
P.
In order to initially energize any motor, pump, or fan, the shutdown control system should first be energized and the emergency shutdown system reset.
Instrumentation The purpose of commissioning instruments prior to the startup of the facility is to ensure correct performance per specifications under simulated operating conditions. Handling of instruments after calibration should be kept to a minimum. The instruments have been ordered pre-calibrated and set. It should be necessary only to verify the factory calibration and zero of the instruments. In the event that an instrument requires re-calibration or major mechanical adjustments, the manufacturer's recommendations and guidelines should be adhered to, and will be considered the applicable standard. All instruments, components, and accessory devices (including charts, scales, dials, gauges, switches, etc.) should be checked against their specification sheets for agreement. Specific steps that should be taken to ensure the plant pneumatic instrumentation system is ready for startup include:
Issued 30 August 2011
A.
The instrument air system must be put into operation in order to check-out the instrument loops. The individual block valves for each air user should be closed as the air system is pressurized. Once operating pressure is reached, dirt and pipe scale should be blown from the headers. The individual instrument lines should then be disconnected at the instruments and any debris blown from the entire tubing run.
B.
All air supply regulators should be adjusted to the recommended settings.
C.
Once the instrument air system is pressurized, the piping and tubing should be checked for leaks.
General
Page 3-5
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
Issued 30 August 2011
D.
All instrument loops should be checked to ensure the instruments and control devices are properly interconnected. The controllers should be set to the proper control action with the proper control modes and tuning characteristics.
E.
"Stroke" the control valves to ensure the valves move in the proper direction.
F.
Check orifice plates for proper bore and direction of installation.
G.
Level switches and transmitters should be put in service and checked for proper actuation. Calibration of level devices may be completed after liquid levels are established.
H.
Check the tag numbers on the steam traps to confirm that each trap has been installed in the proper location.
I.
In plants controlled by a distributed control system (DCS), confirm that the range stored in the DCS for each field instrument matches the actual range of the instrument. This is particularly important for flow meters used in ratio control loops, as an incorrect range may prevent the control loop from functioning properly. It is also important on flow loops to confirm that either the transmitter or the DCS (and not both) is extracting the square root of the signal.
General
Page 3-6
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
3.3
Design Basis The information used to design the Sulfur Block is given in this section. Unless stated otherwise, the design conditions presented below are assumed to be available at the battery limits for the new units.
3.3.1
Plant Capacity The feedstock basis for the Sulfur Block is a nominal sulfur production of 35 MT/D. In order to provide a design margin for the Sulfur Recovery Units, each unit is designed for 75% of the normal feed rates, which results in a nominal sulfur production of 52 MT/D.
3.3.2
Sulfur Block Feed Streams
3.3.2.1
Amine Treating Unit Feed Gas (Max Contaminate Case) Composition, mol fraction H2 H2S NH3 Methane Ethane Propane i-Butane n-Butane i-Pentane n-Pentane nC6 H2O
0.008757
Naphtha + Total, kgmol/hr Total, kg/hr
463.85 9902 38 6
Temp, °C Press, kg/cm2(g)
Issued 30 August 2011
Combined Sour Offgas 0.583538 0.133806 0.000146 0.023661 0.018913 0.016896 0.008563 0.115412 0.057487 0.030181 0.00264
General
Page 3-7
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 3.3.2.2
Rich Amine to Amine Regeneration Unit Composition, kmol/hr H2O MDEA H2S NH3 CO2 H2 Methane Ethane Propane i-Butane n-Butane Heptane C1/C2 RSH Total Total, kg/hr
Rich MDEA from DHT RGS 752.79 61.32 14.31 0.00088 0.51 0.01 0.004 0.002 0.0004 0.0004 0.0006 828.95 21358
0.04 1130.75 29231
63 4.5
41 4.5
Temp, °C Press, kg/cm2(g)
Issued 30 August 2011
Rich MDEA from LPG Absorber 1027.14
General
83.56 11.49 8.24 0.04 0.09 0.04 0.12
Page 3-8
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 3.3.2.1
Sour Water to SWS (Max Contaminant Case) Sour Water from NHT (1)
Sour Water from KHT
Sour Water from DHT
Sour Water from CFU
Sour Water from UOP Guard Bed
H2 NH3 H2S
--0.03 0.53
0.23 0.06 0.58
0.16 0.22 0.50
--0.02 0.02
--0.0005 0.0010
H2O
834.34
425.94
320.09
447.70
0.7986
Total Total - kg/hr
834.90 15050
426.81 7695
320.97 5788
447.75 8067
0.8000 14
52
55
54
60
38
3.0
3.0
3.0
3.0
3.0
Composition kgmol/hr
Temp, °C Press, kg/cm2(g) Note
Issued 30 August 2011
(1) The maximum NHT sour water rate is 19585 kg/h containing 35 wt ppm H2S and 18 wt ppm NH3 when running 100% NWS Narrow feed.
General
Page 3-9
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 3.3.2.2
Fuel Gas Streams Fuel gas for the Sulfur Block is supplied from the treated fuel gas header. The treated fuel gas is used only for the fuel to the Thermal Oxidizer Burner. Vaporized C4 LPG is supplied to the Acid Gas Burner, Acid Gas Burner Pilot, and the Thermal Oxidizer Burner Pilot. Composition, mole % Hydrogen
67.353
H2S
0.010
Water Vapor
1.067
Methane
2.729
Ethane
2.180
Propane
1.948
i-Butane
0.988
n-Butane
13.306
i-Pentane
6.633
n-Pentane
3.481
C6 +
0.305
Totals
100.000
Temperature, °C
38
Pressure, kg/cm2(g) (min)
3.5 10,425
LHV, kcal/kg
Issued 30 August 2011
Treated Fuel Gas
General
Page 3-10
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 3.3.2.3
Hydrogen Stream (Reducing Gas) Composition, mole % Hydrogen
99.9
Nitrogen
--20 ppm
CO & CO2 Methane
0.1
Ethane
---
Propane
---
i-Butane
---
n-Butane
---
Totals
Issued 30 August 2011
PSA Hydrogen
100.0
Temperature, °C
40
Pressure, kg/cm2(g) (min)
25
General
Page 3-11
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 3.3.3
Effluent Stream Conditions
3.3.3.1
Treated Fuel Gas from ATU Temperature °C
3.3.3.1
2
normal / max
38 / 40
kg/cm (g)
min / max
3.5 / 4.2
H2S
ppmv
max (dry)
100
Stream:
Treated water
max
60
Treated Water from SWS °C 2
Pressure
kg/cm (g)
min
5.0
H2S
ppmw
max
20
NH3
ppmw
max
20
Incinerated Effluent from TTO Min. 232
Temperature
°C
Pressure SO2
kg/cm2 (g)
H2S (1)
CO NOX
Note
Issued 30 August 2011
Treated Gas
Pressure
Temperature
3.3.3.1
Stream:
(1)
Norm. 288
Max. 400
atm.
ppmv (dry, 0% oxygen)
200
ppmv ppmv ppmw
10 50 65
For oxidation of H2S to SO2, the normal operating temperature for the Tailgas Thermal Oxidizer (TTO) is about 650°C. If CO emissions must be limited and, therefore, the CO must be oxidized to CO2, then the normal operating temperature for the TTO is about 816°C.
General
Page 3-12
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 3.3.3.1
Molten Sulfur Temperature
3.3.4
°C
Min.
Norm.
119
138
2
Pressure Purity H2S
kg/cm (g) % (dry basis) ppmw
Carbon Color
%
Max.
atm. 99.9 10 0.2 “Texas Bright”
Other Design Requirements
3.3.4.1
The Lean Amine from the Amine Regeneration Unit is a 35 wt% MDEA solution with a residual loading of 0.01 mole acid gas / mole MDEA.
3.3.4.2
The Rich Amine from the DHT, LPG Absorber and Amine Treating Unit will go to the Amine Regeneration Unit for regeneration. The maximum Rich Amine loading will be 0.40 mole acid gas / mole MDEA.
3.3.4.3
Liquid sulfur from the SRU is to be degassed to convert H2SX species to H2S and reduce the concentration of H2S to less than 10 PPMW for safe handling.
3.3.4.4
In general, the Sulfur Block is to be designed for a 3-4 year run length between turnarounds. Mechanical turnaround duration is usually 3-7 days for each unit.
3.3.4.5
All units are to be designed individually for a 98% or better on-stream factor.
3.3.4.6
Critical equipment is to be spared, to permit on-line maintenance.
Issued 30 August 2011
General
Page 3-13
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 3.3.5
Utility Information
3.3.5.1
Electricity
Service
Voltage
Phase
Cycles
Motors above 132 kW
6,600 V
3
60
Motors 0.2 kW up to and including 132 kW
440 V
3
60
Fractional kW motors up to 0.2 kW
440 V
3
60
3.3.5.2
Steam Operating Temp. °C
Operating Pressure: kg/cm²(g)
Mechanical Design
Min
Norm
Max
Min
Norm
Max
Press: kg/cm²(g)
HP Steam MP Steam
44 16
45 17
46 17.5
380 275
400 280
420 300
50 20
427 350
IP Steam
13.7
14.4
15.1
202
204
206
16.7
227
LP Steam
3
3.5
4
190
195
210
5.5
300
3.3.5.3
Condensate Condensate Destination or Designation
Grade Level Battery Limit Pressure: kg/cm²(g)
HP Steam MP Steam
HP Condensate MP Condensate
19 6
IP Steam
LP Condensate
1.5
LP Steam
LP Condensate
1.5
3.3.5.4
Boiler Feed Water Min.
Normal
Max.
Design
BFW Temperature, °C
132
132
132
160
BFW Pressure, kg/cm2(g)
57
57
58
63
Dissolved Solids, PPMW (avg)
<5
Conductivity, µS/cm (avg)
<20
Issued 30 August 2011
Temp: °C
General
Page 3-14
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 3.3.5.5
Cooling Water Normal 2
Min.
Design
2
2
kg/cm (g)
°C
kg/cm (g)
°C
kg/cm (g)
°C
Supply
5(1)
--
--
32
8
60
Return
2(1)
--
--
42
8
60
TSS ppmw
20 max
Chlorides ppmw
1200
Ammonia ppmw
nil
Note
3.3.5.6
(1) These conditions are not necessarily the conditions at the inlet or outlet connections of the equipment. Instrument Air and Plant Air
Plant Air, kg/cm2(g) 2
Instrument Air, kg/cm (g)
Min.
Normal
Max.
Design
5.5
5.5
6
10
4
7
8
10
Plant Air Dewpoint °C
---
Instrument Air Dewpoint °C
-40
Issued 30 August 2011
General
Page 3-15
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 3.3.5.7
Gaseous Nitrogen
Pressure, kg/cm2(g)
Min.
Normal
Max.
Design
4
6
8
10
Composition, mole % Nitrogen
99.5
Oxygen
20 ppmv (max)
CO
20 ppmv (max)
CO2
20 ppmv (max)
Other C Compounds
5 ppmv (max)
Chlorine
1 ppmv (max)
H2O
5 ppmv (max)
Hydrogen
20 ppmv (max)
Noble Gases
Remainder
Total
3.3.6
100.0
Plant Site Conditions
3.3.6.1
Barometric Pressure:
760 mm Hg (average)
3.3.6.2
Air Temperature:
37°C (dry bulb) maximum summer design 30°C (dry bulb) for air blower design -10°C (dry bulb) minimum winter design -14.3°C (dry bulb) winterizing
3.3.6.3
Issued 30 August 2011
5.6 m above mean sea level
Site Elevation:
General
Page 3-16
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
Table of Contents 4. POWER DISTRIBUTION .............................................................................................. 4-1 4.1 PURPOSE OF SYSTEM ....................................................................................... 4-1 4.2 SAFETY ................................................................................................................. 4-1 4.2.1 General ........................................................................................................... 4-1 4.2.2 Hazardous (Classified) Areas ......................................................................... 4-1 4.3 EQUIPMENT DESCRIPTION ................................................................................ 4-2 4.3.1 Motors and Motor Controls ............................................................................. 4-2
Issued 30 August 2011
Power Distribution
Page 4-i
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
4. POWER DISTRIBUTION 4.1
Purpose of System This utility system supplies electrical power to all users in the Amine Treating, Amine Regeneration, Sour Water Stripping, Sulfur Recovery, Tailgas Cleanup, Tailgas Thermal Oxidation, and Sulfur Degassing units including motors, instruments, controls, lights, receptacles, and heat tracing.
4.2
Safety
4.2.1
General Only authorized and qualified personnel should maintain and repair electrical equipment. All operator controls and adjustments are accessible without opening electrical equipment enclosures. Maintain extreme care when operating electrical equipment and machinery driven by electrical motors. Equipment may start without warning. Observe company safety rules and permit-to-work system. If you suspect a person has been electrocuted, DO NOT approach the victim until the source of power has been turned off or it is obvious the victim is no longer in contact with the source. If possible, drag victim clear of any metal or potential electrical sources using victim's clothing or by wearing insulating gloves. If the victim is still in contact with the electrical source and skin contact is made, you may also be electrocuted.
4.2.2
Hazardous (Classified) Areas Most of the process areas in the Amine Treating, Amine Regeneration, Sour Water Stripping, Sulfur Recovery, Tailgas Cleanup, Tailgas Thermal Oxidation, and Sulfur Degassing units have been classified as Zone 2, Gas Group IIA/IIB for electrical installation. The only exceptions to this are any below-grade vaults which have been classified as Zone 1, Gas Group IIA/IIB. Locations are classified depending on the properties of the flammable vapors, liquids, or gases which may be present and the likelihood that a flammable or combustible concentration or quantity is present. The electrical equipment and installation in classified areas conforms to the
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SULFUR BLOCK International Electrotechnical Commission (IEC) Standards. Special precautions are required when operating electrical equipment in classified areas. The equipment should be approved for the area classification or a "hot-work" permit system should be followed during the period a non-approved piece of equipment is used in the classified area.
4.3
Equipment Description
4.3.1
Motors and Motor Controls A.
In general, the electric motors are TEFC, 444 VAC, 3 Ø, 60 Hz with the exception of: (1)
B.
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The motors on the Process Air Blower, A2-GB1530A/B, are TEFC, 6600 VAC, 3 Ø, 60 Hz.
The motor control circuits for the Process Air Blower (A2-GB1530A/B), Thermal Oxidizer Air Blower (A2-GB1570A/B), and TGCU Start-Up Blower (A2-GB1560) include provisions that allow the blowers to "ride-through" brief power interruptions.
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Table of Contents 5. PLANT CONTROL SYSTEMS ..................................................................................... 5-1 5.1 5.2 5.3 5.4
DISTRIBUTED CONTROL SYSTEM .................................................................... 5-1 PROGRAMMABLE LOGIC CONTROL SYSTEM ................................................. 5-2 EMERGENCY SHUTDOWN SYSTEMS ............................................................... 5-3 LOCAL CONTROL PANELS ................................................................................. 5-3
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5. PLANT CONTROL SYSTEMS This section of the manual describes the various control systems associated with the new Amine Treating, Amine Regeneration, Sour Water Stripping, Sulfur Recovery, Tailgas Cleanup, Tailgas Thermal Oxidation, and Sulfur Degassing units. Most of the process control functions are performed by a Distributed Control System (DCS). The DCS, with its operator interface screens and keyboards, allows the control room operator to monitor and control nearly all of the systems within the new units. The safety system interlocks and sequential control functions are performed by a programmable logic controller (PLC). A PLC is a solid-state microprocessor that performs the functions of a traditional relay logic system. The PLC for the new units will communicate with the DCS to allow the operator to monitor the PLC using the operator interface screens of the DCS.
5.1
Distributed Control System The Distributed Control System (DCS) provides control, monitoring, recording, alarming, and all other functions required for dependable and effective process control of the facility. It is a microprocessor based, fully engineered system of hardware and software products integrated into an industrially-proven DCS design capable of both functional and geographic distribution. A communication system links these locations to a centralized operating center with video displays configured as operator workstations. The system has been designed so that control and monitoring functions are distributed on a modular basis to minimize control and data information loss in the event of a failure anywhere within the system. Control functionality does not depend on a single centrally-based device or communication system to assure that on a single failure the system will remain operative to allow continued control and monitoring of the remainder of the process. To achieve this, redundancy has been included for controllers, power supplies, communication modules and cables, and operator workstations.
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5.2
Programmable Logic Control System A Programmable Logic Control (PLC) system is used for the new Amine Treating, Amine Regeneration, Sour Water Stripping, Sulfur Recovery, Tailgas Cleanup, Tailgas Thermal Oxidation, and Sulfur Degassing units to perform the functions of traditional relay logic systems. The logic control systems for each unit are all contained in one or more PLCs. Each logic control system will be discussed in more detail in later sections of the manual: a.
Amine Treating Unit Emergency Shutdown System (see Section 7.4.2).
b.
Sour Water Stripper Unit Interlocks (see Section 8.4).
c.
Sulfur Recovery Unit Emergency Shutdown System (SRU ESD) and Burner Management System (see Sections 9.5.2 and 9.5.8).
d.
Sulfur Degassing Unit Startup Interlock and Emergency Shutdown System (SDU ESD) (see Sections 10.5.3 and 10.5.7).
e.
Sulfur Loading Emergency Shutdown System (see Section 10.5.8).
f.
Tailgas Cleanup Unit Emergency Shutdown System (TGCU ESD) (see Section 11.5.5).
g.
Tailgas Thermal Oxidation Emergency Shutdown System (TTO ESD) and Burner Management System (see Sections 12.5.1 and 12.5.5).
The PLC hardware and programs are fail-safe by design. Loss of power to the PLC will de-energize all its outputs and send devices (control valves, etc.) to their "fail" position. The restoration of power to the PLC will restart the PLC, but program interlocks will "lock-out" control actions until the respective ESD systems are reset. Similarly, the PLC logic has been designed such that open circuits in field wiring or open field contacts will de-energize their respective outputs and render equipment and process to a "safe" status. The PLC system is connected by both "hard-wired" cables and software "links" that allow it to communicate with the DCS. This enables the DCS operator interface to be used by the operators to monitor the status of the PLC and its safety and sequential control systems.
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5.3
Emergency Shutdown Systems The purpose of the Amine Treating Unit Emergency Shutdown (ATU ESD), Sulfur Recovery Unit Emergency Shutdown (SRU ESD), Tailgas Cleanup Unit Emergency Shutdown (TGCU ESD), Tailgas Thermal Oxidation Unit Emergency Shutdown (TTO ESD), and Sulfur Degassing Unit Emergency Shutdown (SDU ESD) systems is to shut down the appropriate equipment and divert the appropriate streams to the flare when serious problems occur. Each of these ESD systems can be initiated either by a system response or by an operator. Refer to the Instrumentation and Control Systems sections of these guidelines for complete discussions of these emergency shutdown systems. These ESD systems are mostly independent of each other, with the exception of the TGCU ESD system, which is activated when both of the SRU ESD systems are activated. Except for this situation, activation of the ESD system in a particular unit will not cause any other ESD systems to be directly activated. Of course, depending on the particular circumstances, the effects that result when a particular ESD system is activated may indirectly cause another ESD system to be activated due to the process upset that occurs.
5.4
Local Control Panels There are three local control panels that are used for startup of each Sulfur Recovery Unit and the Tailgas Thermal Oxidation Unit. The functions of these local panels are described in the Instrumentation and Control Systems sections of these guidelines for the Sulfur Recovery system and the Tailgas Thermal Oxidation system.
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Table of Contents 6. UTILITY SYSTEMS ...................................................................................................... 6-1 6.1 PURPOSE OF SYSTEM ....................................................................................... 6-1 6.2 SYSTEM DESCRIPTION ...................................................................................... 6-1 6.2.1 Nitrogen Supply .............................................................................................. 6-1 6.2.2 C4 LPG and Treated Fuel Gas Supply .......................................................... 6-2 6.2.3 Hydrogen Supply ............................................................................................ 6-2 6.2.4 Plant Air .......................................................................................................... 6-3 6.2.5 Instrument Air ................................................................................................. 6-3 6.2.6 Sour Water Disposal....................................................................................... 6-3 6.2.7 Steam, Condensate, Boiler Feed Water, and Blowdown ............................... 6-4 6.2.7.1 Purpose of Systems ................................................................................ 6-4 6.2.7.2 Safety ...................................................................................................... 6-4 6.2.7.3 Process Description ................................................................................ 6-5 6.2.7.4 Boiler Feed Water ................................................................................... 6-5 6.2.7.5 HP Steam ................................................................................................ 6-6 6.2.7.6 LP Steam................................................................................................. 6-7 6.2.7.7 Condensate Return ................................................................................. 6-7 6.3 PRECOMMISSIONING, STARTUP, AND SHUTDOWN PROCEDURES............. 6-8
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6. UTILITY SYSTEMS 6.1
Purpose of System The utility headers supply the fluids necessary for plant operation and maintenance.
6.2
System Description The Piping and Instrument Diagrams show the utility system tie-ins for this project. Some of the more important or complex systems are discussed in more detail in the sections below.
6.2.1
Nitrogen Supply The SRUs and TGCU have two sections of equipment or piping that are stagnant during certain modes of operation. One of these, the SRU warmup bypass line(s), would cause undesirable effects on sulfur recovery and/or severe corrosion if leakage occurred in the line. The other one, the TGCU Start-Up Blower, could suffer corrosion if exposed to wet process gases when it is not running. The most positive means of preventing these problems is to isolate the section in question and purge it with inert gas (such as nitrogen). If the pressure of the purge gas is higher than the process operating pressure, then any leakage through the isolation valves will be the inert purge gas leaking out rather than process gas leaking in. Nitrogen is used in this manner at each of these locations within the new unit. Nitrogen is also used for several other purposes within the new units: 1) to purge instruments (flame scanners, pyrometers, flow meters, etc.) exposed to process gas containing sulfur vapor or ammonia; 2) to empty out and purge vessels before opening them for maintenance; 3) to prevent a vacuum from forming in several overhead lines; 4) as the motive fluid for the aspirator in the air demand analyzer; and 5) as a cool-down medium for the SRUs and the front-end of the TGCU. A dedicated low pressure header is used for purges permanently connected to low pressure sulfur plant equipment; a high pressure header operating at about 7.0 kg/cm2(g) provides nitrogen for the other users.
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SULFUR BLOCK 6.2.2
C4 LPG and Treated Fuel Gas Supply When the refractory in the Reactor Furnace, A2-BA1530 (A2-BA1540), must be heated in a controlled fashion according to its cure-out schedule, fuel is fired in the Acid Gas Burner, A2-BA1531 (A2-BA1541), on manual control. Variable fuel gas quality could lead to temperature "run-aways" if there is not close operator attention throughout the heating cycle. For this reason, vaporized C4 LPG is used as the fuel gas for the Acid Gas Burner. The heating value of vaporized LPG normally varies much less than the heating value of a typical treated fuel gas stream, so vaporized LPG should be much less likely to cause temperature control problems during this manual operation. The fuel gas to the Thermal Oxidizer Burner, A2-BA1571, is automatically adjusted to maintain the desired temperature in the Thermal Oxidizer, A2-BA1570. In addition, this burner normally operates with considerable excess air, since the oxygen to oxidize the sulfur compounds entering the Thermal Oxidizer comes from the burner combustion products. As a result, the variable nature of treated fuel gas can be tolerated by this burner much more easily than the Acid Gas Burner, so this burner is designed to burn treated fuel gas. The pilot burners for the Acid Gas Burner and the Thermal Oxidizer Burner are not as reliable if variable quality fuel gas is used. For this reason, vaporized LPG is used for both pilots to ensure reliable light-off and good service life. During normal operation, loss of the treated fuel gas supply will cause the Thermal Oxidizer to shut down. However, the SRU should continue to operate. The Thermal Oxidizer shutdown will be due to "flame failure" of the Thermal Oxidizer Burner. Loss of LPG will normally not affect either unit, but it will not be possible to restart either unit should a shutdown occur until the LPG supply is restored.
6.2.3
Hydrogen Supply The TGCU Unit is designed to use an external supply of reducing gas to hydrogenate the sulfur compounds in the SRU tailgas back into H2S, rather than generate its own reducing gas. High-purity hydrogen is imported into the Sulfur Block, let-down to low pressure, and combined with the SRU tailgas upstream of the TGCU Reactor Feed Mixer, A2-ME1560. If the hydrogen supply is interrupted, it is likely that the TGCU Unit will have to be bypassed until the hydrogen supply is restored.
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SULFUR BLOCK 6.2.4
Plant Air The Plant Air system provides compressed air for the utility air stations throughout the plant. It can be used for operating pneumatic tools and other pneumatic equipment such as air movers, spray guns, and sand blasting apparatus. Plant air is also used in the Tailgas Cleanup Unit for catalyst passivation.
6.2.5
Instrument Air Dry instrument air is used to provide the motive force to operate the control valves and shutdown valves in the Sulfur Block. Loss of the air supply for brief periods will probably not cause any operational problems. However, if the instrument air pressure falls below about 4.2 kg/cm2(g), some of the large process gas valves may begin to move. If one of the process gas valves that is in the open flowpath through the SRUs, the TGCU, and the TTO should begin to close, the ESD system for that SRU and/or the TGCU will be activated, resulting in an SRU and/or TGCU shutdown.
6.2.6
Sour Water Disposal Sour water is produced at several points in the SRU and TGCU, such as in the Acid Gas Knock-Out Drums, A2-FA1530 (A2-FA1540), the SWS Gas Knock-Out Drum, A2-FA1531 (A2-FA1541), and the excess water condensed in the TGCU Quench Column, A2-DA1560. Some of this sour water is intermittent in nature, like the knock-out drum liquids, whereas the excess quench water will be a continuous flow. The sour water from the Acid Gas Knock-Out Drum is pumped to the Rich Amine Flash Drum, A2-FA1513, while the remaining sources are sent to the Sour Water Flash Drum, A2-FA1520. Sour water must also be drained from equipment items periodically (pump cases, level instruments, etc.). The Closed Drain Tank, A2-FA1582, has an underground header system to collect these liquids and hold them. As the tank fills, the Closed Drain Pump, A2-GA1581A/B, can be used to send the collected sour water to Sour Water Stripping Unit.
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WARNING
THE LIQUID DRAINED INTO THE CLOSED DRAIN TANK AND ITS UNDERGROUND HEADER SYSTEM CONTAINS DISSOLVED H2S. ALWAYS OBSERVE PROPER PROCEDURES AND PRECAUTIONS WHEN DRAINING LIQUID FROM THESE ITEMS OR PERFORMING MAINTENANCE ON THEM. THE "GENERAL SAFETY" SECTION OF THIS MANUAL SHOULD BE CONSULTED IF THERE IS ANY DOUBT ABOUT HOW TO WORK SAFELY WHEN H2S MAY BE PRESENT.
6.2.7 6.2.7.1
Steam, Condensate, Boiler Feed Water, and Blowdown Purpose of Systems The Steam system provides heating media for plant systems and equipment and motive driving power for each vent ejector. The Condensate system is designed to collect and return the steam which has been condensed by the users to the Steam system. The Boiler Feed Water system provides suitably conditioned water to the steam generators located within the Sulfur Block. The Blowdown system collects the blowdown water from the boilers in the Sulfur Block for safe disposal.
6.2.7.2
Safety Use appropriate safety precautions when handling the boiler feed water chemicals (sulfite, amine, phosphate, etc.). The normal operating temperatures in the Steam, Condensate, and Boiler Feed Water systems are high enough to cause burns: Steam Pressure
Steam Temperature
48.5 kg/cm2(g) 45.0 kg/cm2(g) 4.2 kg/cm2(g)
262°C 400°C superheated 153°C
Personnel should take the appropriate precautions to avoid burns when working around open vents, open drains, steam traps, or any
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SULFUR BLOCK un-insulated piping in the Steam, Condensate, and Boiler Feed Water systems. It is common for hot water to drip from steam tracing connections, steam traps, etc. Steam leaks and steam vent streams can cause severe burns and lacerations. Also, refer to the discussion concerning boilers in the General Safety section of this manual, Section 2.13. 6.2.7.3
Process Description There are three Steam headers (saturated 48.5 kg/cm2(g), superheated 45 kg/cm2(g) and saturated 3.5 kg/cm2(g)), a low pressure Condensate Return header, a high pressure Condensate Return Header, a Cold Condensate Header, a Boiler Feed Water header, and an atmospheric pressure Blowdown header. There are six steam generators in the Sulfur Block: A2-BF1530
Waste Heat Boiler (sat. 48.5 kg/cm2(g) steam)
A2-BF1540
Waste Heat Boiler (sat. 48.5 kg/cm2(g) steam)
A2-EA1531
Sulfur Condenser (sat. 4.2 kg/cm2(g) steam)
A2-EA1541
Sulfur Condenser (sat. 4.2 kg/cm2(g) steam)
A2-EA1561
TGCU Waste Heat Reclaimer (sat. 4.2 kg/cm2(g) steam)
A2-BF1570
Thermal Oxidizer Waste Heat Boiler (superheated 45.0 kg/cm2(g) steam)
The different subsystems are described below. 6.2.7.4
Boiler Feed Water In accordance with the ASME Section I Code for Power Boilers, boiler feed water must be provided to the Waste Heat Boiler, A2-BF1530 (A2-BF1540), and the Thermal Oxidizer Waste Heat Boiler, A2-BF1570, at 58.3 kg/cm2(g) or higher (i.e., 6% above the relief valve settings). The BFW supply header must be maintained at or above this pressure to safely satisfy this requirement.
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SULFUR BLOCK In accordance with the ASME Section VIII Code for Unfired Steam Boilers, boiler feed water must be provided to the Sulfur Condenser, A2-EA1531 (A2-EA1541), and the TGCU Waste Heat Reclaimer, A2-EA1561, at 5.8 kg/cm2(g)or higher (i.e., 6% above the relief valve settings). 6.2.7.5
HP Steam The Waste Heat Boiler, A2-BF1530 (A2-BF1540), generates HP steam at a normal operating pressure of about 48.5 kg/cm2(g). A small portion of this steam is consumed in the reactor feed heaters to reheat the feed streams to the catalytic reactors in the SRUs. The rest of the HP steam is combined with the steam from the Thermal Oxidizer Waste Heat Boiler, A2-BF1570, enters the Steam Knock-Out Drum, A2-FA1570, to remove any entrained water droplets, and is then routed to the superheat passes in the Thermal Oxidizer Waste Heat Boiler. The Thermal Oxidizer Waste Heat Boiler includes a water-tube boiler that uses part of the waste heat from the Thermal Oxidizer to generate 48.5 kg/cm2(g) saturated steam. The remainder of the waste heat is used to superheat the steam from this boiler after it combines with the HP steam produced by the Waste Heat Boiler. The Thermal Oxidizer Waste Heat Boiler allows a major portion of the heat required to incinerate the sulfur compounds to SO2 to be recovered as useful steam. The superheated steam is exported to the refinery HP steam header at about 400°C and 45.0 kg/cm2(g). Note that the Thermal Oxidizer Waste Heat Boiler is the only source of superheat for the HP steam produced in the Sulfur Block. If the Thermal Oxidizer shuts down and begins to cool, the steam will no longer be sufficiently superheated to satisfy the requirements of the users located outside of battery limits. Under this circumstance, the steam from the superheat passes of the TTO Waste Heat Boiler will instead be vented to atmosphere automatically until the Thermal Oxidizer is restarted and the steam is once again superheated to the proper temperature. HP steam is used as motive fluid for the Sulfur Surge Tank Vent Ejector, A2-EE1530 (A2-EE1540). The steam for this service is normally supplied from the steam produced within the process train. When the HP steam is being vented to atmosphere as described
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SULFUR BLOCK above, however, steam must be imported into the Sulfur Block for this equipment item. 6.2.7.6
LP Steam The Sulfur Condenser, A2-EA1531 (A2-EA1541), in the sulfur plant and the TGCU Waste Heat Reclaimer, A2-EA1561, in the tailgas cleanup unit generate LP steam at a normal operating pressure of about 4.2 kg/cm2(g). This LP Steam is used for heating amine acid gas in the Acid Gas Preheater, A2-EA1530 (A2-EA1540), reboiling the solvent in the ARU Stripper Reboiler, A2-EA1512A/B, the water in the Sour Water Stripper Reboiler, A2-EA1521, and the TGCU solvent in the TGCU Stripper Reboiler, A2-EA1565, miscellaneous steam tracing and steam jacketing of process gas lines, sulfur rundown lines, sulfur vapor valves, etc., and for the heating coils in the Sulfur Surge Tank, A2-EA1531 (A2-EA1531), and Sulfur Storage Tank, A2-FB1550. The remaining LP Steam is exported to the refinery.
6.2.7.7
Condensate Return The HP condensate produced from the HP Steam used in the Sulfur Block is collected and routed to the HP Condensate return system. The LP condensate produced from the LP Steam used in the Sulfur Block is collected and routed to the LP Condensate return system.
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6.3
Precommissioning, Startup, and Shutdown Procedures The utility equipment and piping may be put into service as required by the process systems they serve. Normal procedures should be followed after completion of construction to ensure that the lines have been adequately blown or flushed clean before being commissioned. Other than checking for cleanliness and possible leaks, and following good practice in venting lines while they are being filled, no other special procedures should be required to commission the utility systems.
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Table of Contents 7. AMINE TREATING & AMINE REGENERATION ......................................................... 7-1 7.1 PURPOSE OF SYSTEM ....................................................................................... 7-1 7.2 SAFETY ................................................................................................................. 7-1 7.3 PROCESS DESCRIPTION.................................................................................... 7-2 7.3.1 General ........................................................................................................... 7-2 7.3.2 Water Washing ............................................................................................... 7-2 7.3.3 Sour Gas Contacting ...................................................................................... 7-3 7.3.4 Solvent Regeneration ..................................................................................... 7-3 7.4 EQUIPMENT DESCRIPTION ................................................................................ 7-6 7.4.1 Wash Water Column, A2-DA1510 .................................................................. 7-6 7.4.2 Amine Absorber, A2-DA1511 ......................................................................... 7-6 7.4.3 Flash Gas Contactor, A2-DA1512 .................................................................. 7-6 7.4.4 Stripper, A2-DA1513 ...................................................................................... 7-6 7.4.5 Wash Water Column Packing, A2-DB1510 .................................................... 7-7 7.4.6 Amine Absorber Trays, A2-DB1511 ............................................................... 7-7 7.4.7 Stripper Trays, A2-DB1513 ............................................................................ 7-7 7.4.8 Amine Absorber Overhead Cooler, A2-EA1510 ............................................. 7-8 7.4.9 Lean/Rich Exchanger, A2-EA1511A/B ........................................................... 7-8 7.4.10 Stripper Reboiler, A2-EA1512A/B .................................................................. 7-8 7.4.11 Stripper Reflux Condenser, A2-EC1511......................................................... 7-8 7.4.12 Lean Amine Cooler, A2-EC1510 .................................................................... 7-8 7.4.13 Wash Water Feed Knock-Out Drum, A2-FA1510 ........................................... 7-8 7.4.14 Amine Absorber Feed Knock-Out Drum, A2-FA1511 ..................................... 7-9 7.4.15 Amine Absorber Overhead Knock-Out Drum, A2-FA1512 ............................. 7-9 7.4.16 Rich Amine Flash Drum, A2-FA1513 ............................................................. 7-9 7.4.17 Stripper Reflux Accumulator, A2-FA1514..................................................... 7-10 7.4.18 Stripper Reboiler Condensate Pot, A2-FA1515A/B ...................................... 7-10 7.4.19 ATU Skim Oil Sump, A2-FA1516 ................................................................. 7-10 7.4.20 ATU Skim Oil Pump Sump, A2-FA1517A/B ................................................. 7-10 7.4.21 ATU Amine Drips Tank, A2-FA1580............................................................. 7-11 7.4.22 MDEA Storage Tank, A2-FB1580 ................................................................ 7-11 7.4.23 Wash Water Filter, A2-FD1510A/B ............................................................... 7-11 7.4.24 Rich Amine Filter, A2-FD1511A/B ................................................................ 7-11 7.4.25 Lean Amine Filter, A2-FD1512 ..................................................................... 7-11 7.4.26 Lean Amine Carbon Filter, A2-FD1513 ........................................................ 7-12 7.4.27 Lean Amine After-Filter, A2-FD1514 ............................................................ 7-12 7.4.28 ATU Amine Drips Filter, A2-FD1580 ............................................................ 7-12
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SULFUR BLOCK 7.4.29 Wash Water Pump, A2-GA1510A/B ............................................................. 7-13 7.4.30 Lean Amine Pump, A2-GA1511A/B ............................................................. 7-13 7.4.31 ATU Skim Oil Pump, A2-GA1512A/B ........................................................... 7-13 7.4.32 Rich Amine Pump, A2-GA1513A/B .............................................................. 7-13 7.4.33 Lean Amine Booster Pump, A2-GA1514A/B ................................................ 7-13 7.4.34 Stripper Reflux Pump, A2-GA1515A/B ......................................................... 7-13 7.4.35 MDEA Transfer Pump, A2-GA1580.............................................................. 7-14 7.5 INSTRUMENTATION AND CONTROL SYSTEMS ............................................. 7-15 7.5.1 Treated Fuel Gas H2S Analyzer ................................................................... 7-15 7.5.2 ATU Emergency Shutdown Systems ........................................................... 7-15 7.5.2.1 Causes of ATU ESD.............................................................................. 7-15 7.5.2.2 Effects of ATU ESD ............................................................................... 7-17 7.5.2.3 Non-ESD Shutdowns and Alarms ......................................................... 7-17 7.6 PROCESS PRINCIPLES AND OPERATING TECHNIQUES ............................. 7-19 7.6.1 Amine Absorber Operation ........................................................................... 7-19 7.6.1.1 Low Temperature .................................................................................. 7-19 7.6.1.2 Acid Gas Loading .................................................................................. 7-20 7.6.1.3 High Amine Concentration .................................................................... 7-20 7.6.2 Stripper Operation ........................................................................................ 7-22 7.6.3 Amine Water Balance ................................................................................... 7-24 7.6.4 Amine Loss ................................................................................................... 7-27 7.6.5 Operation at Low Flow Rates ....................................................................... 7-29 7.7 PRECOMMISSIONING PROCEDURES ............................................................. 7-30 7.7.1 Preliminary Check-out .................................................................................. 7-30 7.7.2 Shutdown System Check-out ....................................................................... 7-31 7.7.3 Leak Testing the Process Piping and Equipment ......................................... 7-31 7.7.4 Washing the Wash Water System ................................................................ 7-33 7.7.4.1 Water Flush ........................................................................................... 7-33 7.7.4.2 Acid Wash ............................................................................................. 7-35 7.7.4.3 Alkaline Wash........................................................................................ 7-36 7.7.4.4 Initial Water Fill ...................................................................................... 7-37 7.7.5 Washing the Amine System ......................................................................... 7-38 7.7.5.1 Water Flush ........................................................................................... 7-38 Acid Wash ............................................................................................. 7-43 7.7.5.2 7.7.5.3 Weak Amine Wash ................................................................................ 7-45 7.7.5.4 Initial Solvent Fill ................................................................................... 7-46 7.7.6 Purging the Low Pressure Columns ............................................................. 7-50 7.7.6.1 Purging the Columns ............................................................................. 7-50 7.8 STARTUP PROCEDURES.................................................................................. 7-52 7.8.1 Wash Water and Amine Systems ................................................................. 7-52
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 7.8.2 Sour Fuel Gas Flow to the Columns............................................................. 7-53 7.9 SHUTDOWN PROCEDURES ............................................................................. 7-56 7.9.1 Planned Shutdown - ATU ............................................................................ 7-57 7.9.2 Planned Shutdown - ATU and ARU ............................................................. 7-60 7.9.3 Emergency Shutdown .................................................................................. 7-62 7.9.4 Effects of Shutdowns and Outages in Other Systems.................................. 7-63 7.9.4.1 Steam System Outage .......................................................................... 7-63 7.10 ANALYTICAL PROCEDURES ............................................................................ 7-64 7.10.1 General Procedures for Analyzing ATU/ARU Solvent, ................................. 7-64 7.10.2 Determination of Amine Concentration in ATU/ARU Solvent ....................... 7-68 7.10.3 Determination of Total Acid Gas Loading in ATU/ARU Solvent ................... 7-70 7.10.4 Determination of H2S and CO2 Loading in ATU/ARU Solvent ...................... 7-72 7.10.5 Determination of Foaming Tendency of ATU/ARU Solvent .......................... 7-76 7.10.6 H2S Conc. in Amine Absorber Ovhd by the Tutweiler Method ..................... 7-78 7.10.7 H2S Conc. in Amine Absorber Ovhd Using Gas Detector Tubes ................. 7-79 7.10.7.1 Operating Principles .............................................................................. 7-79 7.10.7.2 Sampling the Amine Absorber Overhead Gas ...................................... 7-80 7.10.7.3 Calculations ........................................................................................... 7-81
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
7. AMINE TREATING & AMINE REGENERATION 7.1
Purpose of System The purpose of the Amine Treating system is to remove essentially all the H2S from the sour fuel gas stream using an aqueous amine solvent, MDEA (methyldiethanolamine). The H2S is absorbed in the amine solvent and the treated fuel gas stream, containing with less than 100 ppmv of H2S, is returned to the complex for consumption as fuel. The purpose of the Amine Regeneration system is to strip the H2S from the rich amine solvent produced in the Amine Treating, LPG Treating and DHT units. The H2S-laden acid gas is sent to the Sulfur Recovery Unit (SRU) for disposal and the lean amine is recycled back to the upstream process units.
7.2
Safety
WARNING
ALL PIPING AND VESSELS INCLUDED IN THIS UNIT EITHER CONTAIN OR HAVE THE POTENTIAL FOR CONTAINING HAZARDOUS GAS THAT MAY CAUSE SERIOUS INJURY OR DEATH. THE GAS THAT IS MOST COMMON AND HAZARDOUS IN A TOXIC WAY IS HYDROGEN SULFIDE. CLOSE ATTENTION SHOULD BE PAID TO THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES AS TO THE NATURE AND ABILITY OF THIS GAS TO CONTAMINATE OTHER ELEMENTS IN THIS UNIT. AN EMPLOYEE'S KNOWLEDGE OF THE HAZARDOUS CHEMICALS AND COMPOUNDS WITH WHICH HE WILL BE WORKING IS ONE OF THE MOST BASIC PREREQUISITES FOR HIS OWN SAFETY, THE SAFETY OF OTHERS, AND THE PROTECTION OF EQUIPMENT. ALL EMPLOYEES SHOULD REVIEW THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES OCCASIONALLY TO REFRESH THEIR MEMORIES. NEW EMPLOYEES SHOULD STUDY IT UNTIL THE INFORMATION IS THOROUGHLY UNDERSTOOD. PEOPLE WHO HAVE NOT BEEN PROPERLY TRAINED SHOULD NOT BE ALLOWED TO OPERATE OR WORK IN AND AROUND THIS PLANT.
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
7.3
Process Description
7.3.1
General The Systems Diagram, Material Balance and Process Flow Diagrams, Dwg. Nos. 507000-7000-01, through -04, are contained in the "Process Flow Diagrams" Section of the Basic Engineering Package. Please refer to these drawings to follow this description of the process. The Amine Treating Unit (ATU) uses an aqueous amine solvent, MDEA (methyldiethanolamine), to remove essentially all the H2S from the sour fuel gas stream. The normal solvent concentration is 45 wt % MDEA in water. The ATU is designed to treat 10,397 Nm3/hr of sour fuel gas. The treated gas stream is returned to the refinery for consumption as fuel, and the acid gas (H2S, plus CO2) is routed to the Sulfur Recovery Units (SRUs). Less than 100 PPMV of H2S remains in the treated fuel gas.
7.3.2
Water Washing Sour fuel gas streams in chemical complexes are often contaminated with various gaseous, liquid, and even solid substances. In order to prevent these contaminants from causing operating problems (foaming, poor treating, corrosion, etc.) in the amine solvent system, the sour fuel gas streams are washed with water to remove the contaminants upstream of the amine contactors. Some of the more common contaminants are ammonia (NH3), hydrogen cyanide (HCN), and hydrocarbon liquids. The sour fuel gas enters Wash Water Feed Knock-out Drum, A2-FA1510, at 38°C [100°F] and 6.0 kg/cm2(g) [85 PSIG]. Any entrained liquids are removed automatically on level control and routed to the sour liquids system. The scrubbed gas enters the bottom of the Wash Water Column, A2-DA1510, and passes upward through a packed bed where it is countercurrently contacted with a stream of circulating water. The washed sour gas stream leaves the top of the column and flows to Amine Absorber Feed Knock-out Drum, A2-FA1511, to remove any wash water that may be carried over with the gas. The scrubbed gas proceeds to the Amine Absorber, A2-DA1511, while any wash water carry-over is routed to the Closed Drain system on level control. The wash water leaving the bottom of the column is pumped by the Wash Water Pump, A2-GA1510A/B, to the Wash Water Filter, A2-FD1510A/B, for removal of any particulates or other solid material removed from the sour gas feed. Most of the filtered water is returned to the top of Wash
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SULFUR BLOCK Water Column on flow control, after being mixed with fresh makeup water. The remainder of the filtered water is directed to the Sour Water Stripping Unit (SWS) to purge the gaseous and liquid contaminants removed by the wash water from the system. The makeup water rate can be adjusted as necessary to control the contaminants (primarily ammonia in most cases) at an acceptable concentration, and the level control on the column bottoms will automatically adjust the purge rate to balance the water added to the system with the makeup water flow control.
7.3.3
Sour Gas Contacting The washed sour refinery fuel gas enters the bottom of the Amine Absorber at 37°C [98°F] and 5.8 kg/cm2(g) [82 PSIG] and passes upward through 30 trays to be contacted countercurrently with lean MDEA solvent. As the sour gas is contacted by the amine, the acidic H2S (and CO2, if present) in the gas reacts with the basic amine solution: (1)
H2S + CH3(CH2OHCH2)2N
CH3(CH2OHCH2)2NH+ + HS–
(2)
CO2 + CH3(CH2OHCH2)2N + H2O
CH3(CH2OHCH2)2NH+ + HCO3–
This is an acid-base reaction, forming an amine "salt" that remains dissolved in the aqueous solution. The rich amine leaves the bottom of the column at 58°C [136°F] on level control and is routed to the Rich Amine Flash Drum, A2-FA1513. The treated gas leaves the top of the column and flows to the Amine Absorber Overhead Cooler, A2-EA1510, where it is cooled to 37°C [98°F] before flowing to the Amine Absorber Overhead Knock-out Drum, A2-FA1512, where any solvent carry-over is recovered and returned to the rich solvent stream on level control. The scrubbed treated gas at 37°C [98°F] and 4.5 kg/cm2(g) [64 PSIG] is then routed to the treated fuel gas header for consumption elsewhere in the complex.
7.3.4
Solvent Regeneration The combined rich solvent stream from the Amine Treating Unit, the LPG Treating Unit, and the DHT Unit enters the Rich Amine Flash Drum at 54°C [130°F]. This vessel is operated at low pressure (0.64 kg/cm2(g) [9 PSIG]) to maximize the vaporization and removal of any light hydrocarbons that may be entrained or dissolved in the amine solvent. A small amount of H2S will be liberated from the rich amine by the pressure reduction, so the resulting flash gases enter the bottom of the Flash Gas Contactor, A2-DA1512, and flow upward through its packed bed to be
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SULFUR BLOCK countercurrently contacted with a small stream of lean amine. The amine will remove most of the H2S from the flash gas, so that the treated gas flowing to the flare will contain 200 PPMV or less of H2S. The rich amine from the bottom of the packed bed falls into the flash drum to join the other rich solvent. The flash drum is large enough to provide 30-40 minutes or more of residence time for the rich solvent. This allows time for any heavy hydrocarbons entrained in the solvent to separate as a second liquid phase that spills over the internal weir at the inlet end of the drum, collecting in the ATU Skim Oil Sump, A2-FA1516. The ATU Skim Oil Pump, A2-GA1512A/B, sends the collected hydrocarbon to the Condensate Feed Tank on start/stop level control. After removal of any liquid hydrocarbon, the heavier amine phase passes under the internal weir at the outlet end of the drum to be pumped through the Rich Amine Filter, A2-FD1511A/B, by the Rich Amine Pump, A2-GA1513A/B, on level/flow cascade control. The filter removes particulates from the solvent before it enters the tube side of the Lean/Rich Amine Exchanger, A2-EA1511A/B. The Rich Amine is preheated to 105°C [221°F] by cooling the lean solvent before flowing to the Stripper, A2-DA1513, entering between trays #4 and #5. The Stripper contains 30 valve trays (4 wash water trays, 26 stripping trays) and one chimney draw tray. As the solvent flows down the column, the absorbed H2S and CO2 are stripped from the MDEA by countercurrent contact with stripping steam rising upward. This stripping steam is generated in the Stripper Reboiler, A2-EA1512A/B, using LP (3.5 kg/cm2(g) [50 PSIG]) steam as the heat input. The heat input to the reboilers is adjusted by flow control of the steam. The steam flow controllers can be reset by the Stripper overhead temperature, which will maintain the desired overhead temperature of 114°C [238°F] by varying the heat input in proportion to the amount of acid gas contained in the Rich Amine. The stripping steam supplies the heat of reaction required to reverse reactions (1) and (2), and carries the H2S and CO2 stripped from the solvent overhead to the Stripper Reflux Condenser, A2-EC1511, where the steam is condensed as the stream is cooled to 49°C [120°F]. The condensed water is removed by the Stripper Reflux Accumulator, A2-FA1514, and returned as reflux to the wash water trays in the tower by the Stripper Reflux Pump, A2-GA1515A/B. The acid gas (H2S and CO2,
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SULFUR BLOCK along with the uncondensed water) stripped from the solvent exits the reflux drum at 0.85 kg/cm2(g) [12 PSIG] and flows to the SRUs. The Lean Amine Booster Pump, A2-GA1514A/B, pumps the regenerated lean MDEA solvent from the bottom of the Stripper through the shell side of the Lean/Rich Amine Exchanger, cooling the lean solvent from 259°F to 78°C [172°F] by countercurrent heat exchange with the cool rich amine. A slipstream of the lean amine then flows through the Lean Amine Filter, A2-FD1512, to remove accumulated solids from the solvent and through the Lean Amine Carbon Filter, A2-FD1513, where the activated carbon adsorbs contaminants such as hydrocarbons and degradation products from solvent. The Lean Amine After-Filter, A2-FD1514, catches any carbon "fines" before the filtered slipstream rejoins the main solvent stream. A portion of the lean amine flows to the DHT unit on temperature control while the remainder flows to the Lean Amine Cooler, A2-EC1510, where it is cooled to 50°C [122°F]. A small stream of cool lean amine is directed on flow control to the top of the Flash Gas Contactor as described previously. A portion of the cool lean amine flows to the LPG Treating Unit and a portion flows to the DHT unit on temperature control. The remaining lean amine is pumped to higher pressure by the Lean Amine Pump, A2-GA1511A/B before being directed on flow control to the top of the Amine Absorber.
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
7.4
Equipment Description
7.4.1
Wash Water Column, A2-DA1510 The Wash Water Column contains a single bed of random packing to provide good contact between the sour fuel gas and the circulating wash water. The tower has a 304 S.S. woven wire mist eliminator above the packed bed to remove entrained water droplets from the gas before it leaves the tower.
7.4.2
Amine Absorber, A2-DA1511 The Amine Absorber contains a 30 valve trays to provide good contact between the sour fuel gas and the amine solvent to remove H2S from the fuel gas. The tower has a 304 S.S. woven wire mist eliminator above the top bed to remove entrained solvent droplets from the gas before it leaves the tower.
7.4.3
Flash Gas Contactor, A2-DA1512 As lighter hydrocarbons are allowed to disengage from the amine in the Rich Amine Flash Tank, a small amine flow scrubs these lighter hydrocarbons of acid gas as the amine and hydrocarbon flow counter currently. The Flash Gas Contactor contains a single bed of random packing which provides good contact between the light hydrocarbon gas entering below it and the amine fed above it.
7.4.4
Stripper, A2-DA1513 The Stripper contains 28 valve trays to provide good contact between the rich amine solvent and the reboiler vapors to strip H2S and CO2 from the solvent. The rich amine enters on the fifth tray from the top; the four trays above that are "water wash" trays that allow the reflux water (entering on the top tray) to remove traces of MDEA from the overhead vapor and minimize solvent losses. A chimney tray is located below the bottom valve tray to gather all of the column liquids to feed the Stripper Reboiler. The column section located below this chimney tray serves to separate the outlet steam and lean amine from the reboiler and to provide surge for the solvent circulating system.
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 7.4.5
Wash Water Column Packing, A2-DB1510 This bed of random packing provides good contact between the sour fuel gas entering below it and the wash water fed above it inside the Wash Water Column. The packing has a bed limiter above it and rests on a bed support. The quench water is distributed over the packing by a distributor tray. The packing is 304 S.S.; the other internals are 304 S.S. Gaskets are installed where the bed support and distributor tray bolt to the support ring and clips inside the Wash Water Column to prevent direct contact between the stainless steel internals and the carbon steel vessel. This electrically isolates the dissimilar metals from each other to prevent direct contact that could lead to galvanic corrosion.
7.4.6
Amine Absorber Trays, A2-DB1511 These 1-pass valve trays provide good contact between the fuel gas entering below it and lean amine fed above it inside the Amine Absorber. The tray decks and tray downcomers are 304L S.S., and the valves are fabricated from 304 S.S. to resist corrosion and to prevent "sticking" to the tray decks.
7.4.7
Stripper Trays, A2-DB1513 These 1-pass valve trays provide good contact between the rich amine solvent fed above them and the reboiler vapors fed below them inside the Stripper. The tray decks are 304L S.S., and the valves are fabricated from 304 S.S. to resist corrosion and to prevent "sticking" to the tray decks. The chimney tray deck is 304L S.S. The bottom valve tray has a seal pan for its downcomer to maintain a liquid seal and prevent gas from blowing up the downcomer. The chimney tray gathers the tower liquids to feed the reboiler. The outlet from the reboiler reenters the column below the chimney tray, with the vapor produced by the reboiler flowing upward through the chimneys in order to reach the valve trays above. The top four trays in the column are located above the rich amine feed point and serve as water-wash trays to minimize the amount of amine carried-over in the tower overhead. Since these trays have only the reflux water flowing over them, the liquid rates for these trays are much lower than for the trays lower in the column. For this reason, these four trays are designed for minimum leakage (i.e., picket fence weirs, minimum downcomer clearance, etc.).
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 7.4.8
Amine Absorber Overhead Cooler, A2-EA1510 This shell and tube exchanger is used to provide the final cooling of the treated fuel gas, with cooling water from the complex as the cooling medium.
7.4.9
Lean/Rich Exchanger, A2-EA1511A/B These shell and tube exchangers conserve energy by providing heat exchange between the rich amine and the lean amine, so that the hot lean amine leaving the Stripper can preheat the rich amine before it feeds the Stripper. This cross exchange saves reboiler duty by preheating the rich amine, and reduces the load on the Lean Amine Cooler by partially cooling the hot lean amine.
7.4.10
Stripper Reboiler, A2-EA1512A/B The Stripper Reboilers are a fixed tubesheet shell and tube heat exchangers. The exchangers are arranged as once-through vertical thermosiphon reboilers, mounted on the side of the Stripper. The static head of the solvent above the inlet nozzle on the lower channel provides the driving force to circulate the solvent through the tubes. LP steam on the shell of the exchangers heats the solvent inside the tubes, partially vaporizing it to create stripping steam to remove the H2S and the CO2 from the solvent flowing down the Stripper.
7.4.11
Stripper Reflux Condenser, A2-EC1511 This forced-draft aerial exchanger provides cooling to condense the majority of the water from the acid gas stream leaving the overhead of the Stripper. Fans are used to circulate air across the finned tubes to remove heat from the overhead stream and condense the water to be used as reflux for the tower.
7.4.12
Lean Amine Cooler, A2-EC1510 This forced-draft aerial exchanger provides the final cooling of the lean amine stream returning from the regeneration section of the process. Fans are used to circulate air across the finned tubes to remove heat from the solvent.
7.4.13
Wash Water Feed Knock-Out Drum, A2-FA1510 This vertical vessel is installed in the inlet sour fuel gas line to remove liquids from the gas stream before it is routed to the Wash Water Column.
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK The liquid produced in this vessel is routed to the closed drain on automatic start/stop control. The vessel is equipped with high level alarms to warn of a rising level in the drum, and a high-high level shutdown to activate the ATU ESD system before liquids can reach the column. The shutdown requires that 2 out of 3 transmitters have a high-high level indicated.
7.4.14
Amine Absorber Feed Knock-Out Drum, A2-FA1511 This vertical vessel is installed in the overhead line from the Wash Water Column to remove liquids from the gas stream before it is routed to the Amine Absorber. The liquid produced in this vessel is routed to the closed drain on automatic start/stop control. The vessel is equipped with high level alarms to warn of a rising level in the drum, and a high-high level shutdown to activate the ATU ESD system before liquids can reach the absorber. The shutdown requires that 2 out of 3 transmitters have a high-high level indicated.
7.4.15
Amine Absorber Overhead Knock-Out Drum, A2-FA1512 This vertical vessel is installed in the overhead line from the Amine Absorber to remove liquids from the treated fuel gas stream before it is routed to the complex fuel gas system. The liquid produced in this vessel is combined with the rich amine stream leaving the Amine Absorber on automatic start/stop control.
7.4.16
Rich Amine Flash Drum, A2-FA1513 This horizontal vessel allows for the removal of hydrocarbons that may be carried out of the various upstream processes with the amine. The rich amine enters the vessel through a slotted, vertical distributor. Any hydrocarbon that may be carried with the amine from the upstream processes will accumulate in the center section of this vessel. When a sufficient amount of hydrocarbon has accumulated, the hydrocarbon will overflow the partition and flow into the hydrocarbon section. Lighter hydrocarbons are disengaged from the amine and exit through the Flash Gas Contactor where they are washed free of any acid gases. Hydrocarbon-free amine then passes under another partition, at the opposite end of the vessel, and into the amine outlet section, where the amine is pumped to the Stripper.
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 7.4.17
Stripper Reflux Accumulator, A2-FA1514 This vertical pressure vessel removes condensed water from the stream leaving the Stripper Reflux Condenser so that the water can be used as reflux for the Stripper. The vessel has a 304 S.S. woven wire mist eliminator in the top to remove entrained liquid droplets from the gas before it leaves the vessel.
7.4.18
Stripper Reboiler Condensate Pot, A2-FA1515A/B These two vertical pressure vessels collect the condensate from the Stripper Reboiler and return it to the condensate system on level control. This method of removing condensate from the exchanger provides much smoother control of the heat input to the reboiler than a conventional steam trap could. As stated above, this vessel is simply a very good steam trap. During normal operation, the steam pressure required to provide the necessary reboil heat to the Stripper may be much less than the 3.5-4.2 kg/cm2(g) steam pressure available in the LP steam system. The normal steam pressure in the shell of the reboiler may be such that the water level in the condensate pot will rise upwards from the pot, perhaps even within the shell of the reboiler. During these periods, the level valve will remain fully open and the sight glass will indicate a full water level. This is a normal operating condition for this vessel. The vessel will usually operate with a visible level only when the Stripper Reboiler is operating near its maximum capacity with full steam pressure on the shell of the exchanger. Under these conditions, the level control and level valve will function normally and maintain a water level in the vessel.
7.4.19
ATU Skim Oil Sump, A2-FA1516 This horizontal vessel is located in a below-ground concrete vault. It collects the heavy hydrocarbons from the Rich Amine Flash Tank. The collected hydrocarbon liquid is pumped back to the Condensate Feed Tank on stop/start level control.
7.4.20
ATU Skim Oil Pump Sump, A2-FA1517A/B These vertical vessels house the ATU Skim Oil pumps. Hydrocarbon liquids from the ATU Skim Oil Sump flow into this vessel and are pumped out by the ATU Skim Oil Pump.
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 7.4.21
ATU Amine Drips Tank, A2-FA1580 This horizontal pressure vessel is located in a below-ground concrete vault. It collects solvent from the ATU via headers when equipment is drained for maintenance, etc. The vessel will normally operate with little or no pressure so that gravity-flow is sufficient to cause solvent to drain into the vessel. The collected solvent is pumped back to the solvent system in the ATU for reuse when the vessel gets full.
7.4.22
MDEA Storage Tank, A2-FB1580 This vertical, cylindrical, cone roof storage tank holds fresh MDEA solvent unloaded from transport trucks until it is needed for make-up to the ATU solvent system.
7.4.23
Wash Water Filter, A2-FD1510A/B These filters are designed to remove solid particles 5 microns and larger from the circulating wash water.
7.4.24
Rich Amine Filter, A2-FD1511A/B These full-flow filters are designed to remove solid particles 5 microns and larger from the circulating rich solvent, which will help prevent fouling of the downstream heat exchangers.
WARNING THESE FILTERS HANDLE LIQUID CONTAINING H2S AND OTHER HARMFUL SUBSTANCES. ALWAYS OBSERVE PROPER PROCEDURES AND PRECAUTIONS WHEN PERFORMING MAINTENANCE ON THIS FILTER. THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES SHOULD BE CONSULTED IF THERE IS ANY DOUBT ABOUT HOW TO WORK SAFELY WHEN H2S MAY BE PRESENT.
7.4.25
Lean Amine Filter, A2-FD1512 This full-flow filter is designed to remove solid particles 5 microns and larger from the circulating lean solvent.
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 7.4.26
Lean Amine Carbon Filter, A2-FD1513 This full-flow filter is designed to remove organic contaminants (trace hydrocarbons, degradation products, etc.) from a slipstream of the circulating lean solvent using a bed of activated carbon.
7.4.27
Lean Amine After-Filter, A2-FD1514 This filter is designed to remove solid particles, particularly carbon fines, 5 microns and larger from the lean solvent leaving the Lean Amine Carbon Filter.
7.4.28
ATU Amine Drips Filter, A2-FD1580 This filter is designed to remove solid particles 5 microns and larger from the recovered solvent drained from equipment, etc. in the ATU. The recovered solvent is filtered as it is routed back to the ATU.
CAUTION SINCE THE PUMPS DESCRIBED IN THE FOLLOWING SECTIONS ARE CONSTRUCTED OF STAINLESS STEEL, DO NOT HYDROTEST THE ASSOCIATED VESSELS OR PIPING WITH WATER CONTAINING HIGH LEVELS OF CHLORIDES. AVOID ALLOWING WATER CONTAINING MORE THAN 50 PPM CHLORIDES TO COME IN CONTACT WITH THESE PUMPS TO PREVENT STRESS CORROSION CRACKING OF THE STAINLESS STEEL.
WARNING THE LIQUID IN THESE PUMPS CONTAINS DISSOLVED H2S. THIS H2S CAN BE RELEASED TO THE SURROUNDINGS WHEN LIQUID IS DRAINED FROM THESE PUMPS OR FROM THE PIPING CONNECTED TO THE PUMPS. ALWAYS OBSERVE PROPER PROCEDURES AND PRECAUTIONS WHEN DRAINING LIQUID FROM THESE PUMPS OR PERFORMING MAINTENANCE ON THEM. THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES SHOULD BE CONSULTED IF THERE IS ANY DOUBT ABOUT HOW TO WORK SAFELY WHEN H2S MAY BE PRESENT.
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SULFUR BLOCK 7.4.29
Wash Water Pump, A2-GA1510A/B These centrifugal pumps are used to circulate wash water to which is used to remove contaminates from the sour gas feed stream. Each pump is designed for the total duty; the other pump is a 100% spare. These pumps are equipped with tandem seals to reduce the likelihood of releasing H2S to the surroundings.
7.4.30
Lean Amine Pump, A2-GA1511A/B These centrifugal pumps are used to send the lean amine from the Amine Regeneration Unit to the Amine Absorber. Each pump is designed for the total duty; the other pump is a 100% spare. These pumps are equipped with tandem seals to reduce the likelihood of releasing H2S to the surroundings.
7.4.31
ATU Skim Oil Pump, A2-GA1512A/B These vertical sump-type pump is mounted in the ATU Skim Oil Pump Sump to transfer the recovered hydrocarbons back to the Condensate Feed Tank.
7.4.32
Rich Amine Pump, A2-GA1513A/B These centrifugal pumps are used to send the rich amine from the Rich Amine Flash Drum to the Stripper. Each pump is designed for the total duty; the other pump is a 100% spare. These pumps are equipped with tandem seals to reduce the likelihood of releasing H2S to the surroundings.
7.4.33
Lean Amine Booster Pump, A2-GA1514A/B These centrifugal pumps are used to send the lean amine from the Amine Regeneration Unit to the DHT Unit, the LPG Treating Unit, and to the suction of the Lean Amine Pumps in the Amine Treating Unit. Each pump is designed for the total duty; the other pump is a 100% spare. These pumps are equipped with tandem seals to reduce the likelihood of releasing H2S to the surroundings.
7.4.34
Stripper Reflux Pump, A2-GA1515A/B These centrifugal pumps are used to send the reflux from the Stripper Reflux Accumulator to the Stripper. Each pump is designed for the total duty; the other pump is a 100% spare. These pumps are equipped with
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SULFUR BLOCK tandem seals to reduce the likelihood of releasing H2S to the surroundings.
7.4.35
MDEA Transfer Pump, A2-GA1580 This single-stage centrifugal pump is used to transfer amine from the MDEA Storage Tank to the ATU solvent system. This pump does not run continuously so no spare is provided.
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SULFUR BLOCK
7.5
Instrumentation and Control Systems
7.5.1
Treated Fuel Gas H2S Analyzer Analyzer A2-AE15057 measures the H2S concentration in the treated fuel gas leaving Amine Absorber Overhead Knock-out Drum, A2-FA1512. If the H2S concentration exceeds the specification for fuel gas (200 PPMV), DCS relay A2-AY15057 should start ramping down the signal that pressure controller A2-PC15057 is supplying to control valve A2-PV15057. As this valve closes, the pressure will start to rise, until it reaches the setpoint (6.0 kg/cm2(g)) of the over-ride pressure controller, A2-PC15059, which will then open control valve A2-PV15059 to divert the fuel gas to the flare header. The duration of the ramping should be about 60 seconds or so, so that the pressure in the system does not change too rapidly. Once the H2S concentration is back on-specification, A2-AY15057 should start ramping up the signal from A2-PC15057 to A2-PV15057. As this control valve opens and the pressure starts to drop back to its normal value (5.0 kg/cm2(g)), the over-ride pressure controller will then close A2-PV15059, so that the fuel gas is flowing to the fuel gas header once again. The duration of this ramping should again be about 60 seconds or so, so that the pressure in the system does not change too rapidly. A2-HS15057 in the DCS is a bypass to disable relay A2-AY15057 and prevent it from changing the control signal to A2-PV15057. This switch can be used to prevent upset of process operations when calibrating or performing maintenance on the analyzer.
7.5.2
ATU Emergency Shutdown Systems The purpose of the ATU ESD system is to shut off the flow of sour fuel gas to the treating system when serious problems occur. The Cause and Effect Diagrams are contained in the Instrumentation and Controls Drawings section of the Basic Engineering Package. These diagrams describe the ATU ESD system in block format. For reference, the causes and effects of the ESD system shown on these diagrams is explained below.
7.5.2.1
Causes of ATU ESD Any one of the devices listed below will activate the ATU ESD system:
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SULFUR BLOCK a.
Manual Shutdown Switch, A2-HS15022 An operator can activate the ATU ESD system using these guidelines shutdown switch in the DCS, a "timed pulse" switch.
b.
Wash Water Feed Knock-out Drum High-High Liquid Level, A2-LT15008A/B/C. This device prevents liquids in this vessel from entering the wash water system for the sour refinery fuel gas and contaminating it, since this could then lead to contamination of the solvent system. It is set to actuate if the liquid level reaches 1,050 mm above the bottom seam of the vessel. Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD (i.e., at least two transmitters must show high-high level) to avoid spurious "trips" due to the malfunction of a single transmitter.
c.
Amine Absorber Feed Knock-out Drum High-High Liquid Level, A2-LT15030A/B/C. This device prevents liquids in this vessel from entering the Amine Absorber and contaminating the solvent system. It is set to actuate if the liquid level reaches 1,200 mm above the bottom seam of the vessel. Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD.
d.
Amine Absorber Low-Low Liquid Level, A2-LT15040A/B/C. If the solvent level drops too low in the Amine Absorber, large amounts of high pressure gas could blow through control valve A2-LV15040 into the Rich Solvent Flash Drum, A2-FA1513, and other equipment and piping in the ATU/ARU with a lower design pressure than this column. Loss of solvent in this column could also result in the treated fuel gas going sour. This device is set to actuate if the liquid level drops to 450 mm above the bottom seam of the vessel. To reduce the chances of blow-through, this device will also de-energize solenoid valve A2-NY15040 to close the control valve. Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD.
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SULFUR BLOCK 7.5.2.2
Effects of ATU ESD A shutdown of the Amine Absorber, activated either manually or automatically, has the following effects on the ATU/ARU: a.
Closes A2-NV15002, blocking the flow of high pressure sour fuel gas into the ATU.
b.
If the ESD system is activated by low-low level in the Amine Absorber, closes A2-LV15040 to prevent possible blow-through of high pressure gas into the low pressure sections of the ATU/ARU.
When S/D valve A2-NV15002 closes to stop the gas flow into the ATU, the pressure of the incoming sour fuel gas will begin to rise. When it reaches the setpoint (6.3 kg/cm2(g)) of over-ride pressure controller A2-PC15001, the controller will open control valve A2-PV15001 to divert the sour gas to the flare header. 7.5.2.3
Non-ESD Shutdowns and Alarms In addition to the devices listed in Section 7.5.2.1 that activate the ATU ESD system, there are several interlocks of significance that either generate an alarm or shut down an individual piece of equipment. These devices/interlocks and their effects are described in this section. a.
Wash Water Column Low-Low Level, A2-LT15014A/B/C The Wash Water Pump (A2-GA1510A/B) could be damaged if the pump loses suction because the level in the Wash Water Column drops too low. This device will protect the pump by stopping it before this can occur. The setpoint is 450 mm above the bottom seam of the column. Note that there are three independent transmitters and 2oo3 voting logic is used for the shutdown.
b.
Treated Fuel Gas High-High H2S, A2-AE15057 This device closes pressure control valve A2-PV15057 to the treated fuel gas header and opens pressure control valve A2-PV15059 to the flare header when the H2S concentration for the treated fuel gas exceeds 200 ppmv.
a.
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SULFUR BLOCK The Rich Amine Pump (A2-GA1513A/B) could be damaged if the pump loses suction because the level in the Rich Amine Flash Drum drops too low. This device will protect the pump by stopping it and closing the downstream flow control valve before this can occur. The setpoint is 685 mm above the bottom of the vessel. Note that there are three independent transmitters and 2oo3 voting logic is used for the shutdown. c.
Lean Amine Cooler Fan High Vibration, A2-WSH15080 Each fan on the Lean Amine Cooler (A2-EC1510) is provided with its own vibration switch. If the vibration sensed by the switch exceeds the preset level, the switch will trip to stop the associated fan and activate an alarm in the DCS.
d.
Stripper Low-Low Level, A2-LT15108A/B/C The Lean Amine Booster Pump (A2-GA1514A/B) could be damaged if the pump loses suction because the level in the Stripper drops too low. Likewise, the Lean Amine Pump (A2-GA1511A/B) could be damaged if the pump loses suction because the Lean Amine Booster Pump has stopped. This device will protect these pumps by stopping both pumps before this scenario can occur. The setpoint is 450 mm above the bottom seam line of the column. Note that there are three independent transmitters and 2oo3 voting logic is used for the shutdown.
e.
Stripper Reflux Condenser Fan High Vibration, A2-WSH15118 Each fan on the Stripper Reflux Condenser (A2-EC1511) is provided with its own vibration switch. If the vibration sensed by the switch exceeds the preset level, the switch will trip to stop the associated fan and activate an alarm in the DCS.
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SULFUR BLOCK
7.6
Process Principles and Operating Techniques The more important considerations involved in startup, operation, shutdown, maintenance, and emergency procedures for the ATU and ARU are discussed in the remaining sections of this portion of the operating guidelines. The operator should also be thoroughly acquainted with the equipment and the "Process Description" section of these guidelines before attempting to operate the plant in accordance with the operating techniques that follow. If the function of each portion of the plant equipment is understood, the sequence of steps outlined in the "procedures" sections will be more easily understood. In addition, the following general discussion of principles and techniques will clarify the reasons for some of the procedures.
7.6.1
Amine Absorber Operation The main requirement for the Amine Absorber is to consistently produce treated fuel gas which contains a low level of residual H2S. The absorption of H2S in the amine solution is favored by: 1. Low temperature 2. Acid gas loading 3. High amine concentration 4. High H2S partial pressure in the feed stream 5. Intimate contacting In general practice, items 4 and 5 are not operating variables, having been fixed by the design criteria for the unit and choice of equipment in the absorber design.
7.6.1.1
Low Temperature The lower the temperature of the lean amine solution, the better the H2S removal. When treating a hydrocarbon gas, however, the lean amine temperature is limited by the temperature of the gas being treated. The lean amine temperature must be maintained 3-6°C higher than that of the gas feed stream to avoid any possible condensation of these vapors. The circulating lean amine temperature before it enters the absorber is commonly between 27°C and 49°C.
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SULFUR BLOCK 7.6.1.2
Acid Gas Loading Good acid gas removal efficiency depends on good amine solution regeneration, as will be discussed in the following sections. However, it also depends on restricting the H2S loading in the rich amine to favor the forward direction of reaction (1) given in section 7.3.3. The loading of the amine solution is controlled by adjustment of the amine circulation rate. In most cases, unless special design considerations have been employed, the rich amine acid gas loading (H2S plus CO2) should not exceed 0.3 to 0.4 mols total acid gas per mol of amine present.
7.6.1.3
High Amine Concentration The concentration of uncombined amine ion is favored by high amine concentration in the amine solution, good regeneration, and freedom from strong acids. Practical and economic considerations confirmed by field experience have generally shown that the optimum amine concentration is between 15 and 50 wt-% amine depending upon the type of amine used. This is based on the lowest heat requirement for the desired H2S removal, the lowest chemical losses, and the fewest operational problems. The free amine ion concentration in the lean amine is mainly affected by the efficiency and control of amine regeneration. The fewer the sulfide ions in the lean amine, the greater the free amine ion concentration available for removal of H2S. In most cases, lean amine should not contain more than 0.03 mol H2S per mol amine nor more than 0.1 mol CO2 per mol amine. The amine strength should be monitored and the amine content of the circulating amine should be maintained close to the 45% (by weight) design value. Should the amine concentration decrease (normally due to blowdown and other amine losses), it will be necessary to add fresh amine to compensate. Laboratory procedures for analyzing amine are given in a later section of these guidelines. The amine should also be checked periodically for heat-stable salt content. Heat-stable salts form when the amine in the amine solution (a base) reacts with strong acids to form salts that do not decompose at the normal amine regeneration temperature. The most common heat-stable salts encountered in amine systems are SO2 salts, although oxygen contamination of the amine is another common culprit for heat-stable salts in these systems. Heat-stable salts
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SULFUR BLOCK increase the corrosivity of the amine (particularly at higher temperatures, like in the Stripper Reboiler) and increase the foaming tendencies of the amine. (Interestingly, heat-stable salts sometimes improve the H2S-removal capability of the amine, but the higher corrosion rate caused by the salt far outweighs this advantage.) A heat-stable salt content of 2 wt % or lower is desirable. Salt contents in the 5-20 wt % range can be corrosive and should be avoided if possible. The only way to reduce the heat-stable salt content of the amine is by dilution, blowing down some of the circulating amine and making up with fresh amine. There is no means for regenerating heat-stable salt from the amine while it is in the ATU/ARU, as vacuum distillation is required. (In recent years, however, several companies have successfully reclaimed amine on-line using ion exchange on a slipstream of the amine.) There are firms that specialize in reclaiming amine (usually off-site), and it may be economical to use such a firm if a large amount of amine has been contaminated with heat-stable salts. The best practice, however, is to avoid forming heat-stable salt in the first place by proper operation of the ATU, and gas-blanketing the fresh amine to avoid oxygen contamination.
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SULFUR BLOCK 7.6.2
Stripper Operation The lean amine must remain comparatively free of H2S and CO2 to assure attainment of the fuel gas specification. These acid gases are removed from the rich amine in the Stripper by stripping them out with steam. The stripping steam supplies heat to reverse the acid-base reaction between the H2S/CO2 and the amine, and also reduces the H2S/CO2 partial pressure in the vapor phase inside the column to promote mass transfer from the liquid. The stripping steam is produced by vaporizing some of the water in the amine in the Stripper Reboiler, using LP (3.5-4.2 kg/cm2(g)) steam for the heat input. The steam rate to the reboiler (and, hence, the amine stripping rate) is controlled by A2-FC15112A. Adjust this steam rate as needed to keep the H2S and CO2 loading in the lean amine low. See Section 7.10 in these guidelines for appropriate laboratory procedures. For a given column operating pressure, the overhead temperature is a direct indication of the stripping rate: the higher the temperature, the more stripping. Column bottoms temperature should not be used as a guideline for degree of stripping, as it is a function only of amine concentration and column pressure.
CAUTION THE DESIGN STRIPPING STEAM RATE SHOWN ON THE PROCESS FLOW DIAGRAM SHOULD BE CLOSE TO OPTIMUM. ALTHOUGH IT MAY BE POSSIBLE TO REDUCE THIS SOMEWHAT WITHOUT GOING OUT OF COMPLIANCE (I.E., WITH LITTLE CHANGE IN THE H2S LOADING OF THE LEAN SOLVENT), REDUCING THE STRIPPING STEAM RATE SIGNIFICANTLY CAN CAUSE ACCELERATED CORROSION DUE TO HIGH CO2 LOADINGS IN THE LEAN SOLVENT. SEVERAL PLANTS HAVE REPORTED UNEXPECTEDLY HIGH CORROSION RATES IN THE HOT, HIGH VELOCITY AREAS OF THE LEAN SOLVENT SYSTEM, SUCH AS THE OUTLET ENDS OF THE REBOILER TUBES AND THE LEAN SOLVENT PUMPS, AFTER REDUCING THE REBOILER STEAM.
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SULFUR BLOCK IF IT IS NECESSARY TO OPTIMIZE THE STEAM TO THE STRIPPER REBOILER, REDUCE THE STEAM BY SMALL INCREMENTS AND CHECK THE LEAN SOLVENT LOADINGS (BOTH H2S AND CO2) AFTER EACH CHANGE. DO NOT REDUCE THE STEAM FURTHER IF EITHER LOADING BEGINS TO RISE SIGNIFICANTLY, AND BE PREPARED TO PERFORM MORE EXTENSIVE CORROSION MONITORING WHEN OPERATING THE STRIPPER IN THIS MANNER. REFER TO SECTION 7.10 OF THESE GUIDELINES FOR THE PROCEDURES TO BE USED TO DETERMINE THE LEAN SOLVENT LOADINGS. The withdrawal of lean amine from the bottom of the Stripper is on flow control to the Amine Absorber. As a result, the level in the bottom of the Stripper, which serves as the "surge" for the system, will usually indicate if adjustments of water makeup to the amine system (or water "bleed" from the system) are required to maintain the proper water balance, as discussed later in Section 7.6.3 Even if water must be bled from the system by diverting some of the column reflux to Sour Water Stripping, the amine content of that waste stream should be low and only infrequent makeup of fresh amine should be required. It may also be necessary to "purge" ammonia from the reflux water periodically by routing some of the reflux water to the Sour Water Stripping Unit. Although ammonia is usually removed by the circulating water in the Wash Water Column, over a period of time, however, some of the ammonia may carry over into the Amine Absorber and dissolve in the amine. When this ammonia-containing amine reaches the Stripper, the ammonia becomes "trapped" because it is too light (volatile) to leave in the column bottoms and too heavy to leave in the overhead (the acid gas). As a result, the ammonia will become concentrated in the reflux water, to the point where it exceeds its solubility limits and begins to cause plugging problems. If this problem is suspected, simply "bleed" a small amount of the reflux water to the disposal header to purge the ammonia from the system, using the bleed water flow controller in the DCS to control the bleed water rate while monitoring the reflux flow rate to ensure that adequate reflux is maintained to the Stripper. Operating experience will show how often (and how much) the reflux must be purged in this manner to prevent excessive ammonia concentrations for a particular plant.
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SULFUR BLOCK There is full-flow of rich amine through the Rich Amine Filter, and full-flow of lean amine flow through the Lean Amine Filter, the Lean Amine Carbon Filter, and the Lean Amine After-Filter. These four filters will remove solids and organic contaminants from the circulating amine, such as degradation or corrosion products. The filter elements should be changed as soon as the "change" pressure drop is reached, to remove as many solids from the amine as possible. Finely divided solids can cause foaming and thereby limit column capacity. While it is possible to reduce foaming to some extent with anti-foam agents, the presence of such agents may also reduce H2S/CO2 selectivity in the Amine Absorber, so it is preferable that they not be used as an alternative to regular conscientious filter maintenance
7.6.3
Amine Water Balance The water content of the circulating amine is determined by the following factors: 1.
The water content of the feed gas to the Amine Absorber (the overhead from the Wash Water Column).
2.
The water content of the treated gas leaving the Amine Absorber.
3.
The water content of the acid gas leaving the Stripper Reflux Accumulator.
4.
The amount of water makeup to (or water "bleed" from) the amine system.
For given operating pressures, the water content of each gas stream will be determined by the temperature at the top of the respective vessel (Water Wash Column, Amine Absorber, and Stripper Reflux Accumulator, respectively), and will increase as the temperature increases. Since the Amine Absorber inlet gas is at a slightly higher pressure than the outlet treated gas, the inlet gas will normally contain less water than is contained in the outlet gas (if both gas streams are at the same temperature), thus requiring water makeup to maintain the proper water content of the amine. This situation will be reversed if the Amine Absorber overhead temperature is lower than the Wash Water Column overhead temperature, requiring a "bleed" of water to maintain water balance.
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SULFUR BLOCK Since the lean amine to the Amine Absorber is on flow control and withdrawal of the rich amine from the bottom of the Amine Absorber is on level control, a net gain or loss in the amine water balance will be reflected by an increase or decrease, respectively, of the liquid level in the bottom of the Stripper. Observation of this liquid level can thus guide adjustment of water makeup/bleed rate or operating conditions to maintain the desired water concentration of the circulating amine. Since the degree of H2S removal can depend on the amine concentration of the amine, the concentration should be maintained close to the design value (45 wt %) by appropriate maintenance of water concentration. It is usually possible to control the water balance without adding fresh water or "bleeding" water to the Sour Water Stripping Unit by adjusting the operating temperatures in the unit, as discussed in the following paragraphs. Following the steps outlined below will allow controlling the water balance with minimum usage of treated makeup water and minimum impact on the sour water system. A persistently increasing liquid level in the bottom of the Stripper at constant flow rates and conditions for Amine Absorber feed gas and amine indicates a gain in the amine water content. To reduce the water content of the amine, the preferred sequence of gradual adjustments is: A.
Reduce or terminate water makeup to the amine. Makeup water is cold condensate. (1)
Begin "bleeding" water (or increase the "bleed" water rate) from the amine system with the flow controller on the discharge line of the Stripper Reflux Pump. Be careful, however, not to starve the Stripper for reflux by withdrawing too much water. Use the DCS flow indicator for the reflux water to monitor the operation so that adequate reflux is maintained to the Stripper when bleeding water from the amine system.
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SULFUR BLOCK
CAUTION
UNDER NORMAL CONDITIONS, THE REFLUX WATER CONTAINS LITTLE OR NO AMINE BECAUSE OF THE "WASH WATER" TRAYS ABOVE THE SOLVENT FEED TRAY IN THE STRIPPER. HOWEVER, IF THE STRIPPER IS FLOODING OR FOAMING (AS INDICATED BY HIGH OR ERRATIC COLUMN DIFFERENTIAL PRESSURE), THE REFLUX CAN CONTAIN LARGE AMOUNTS OF AMINE. IF THE "BLEED" WATER LINE IS IN USE AT SUCH TIMES, A SIGNIFICANT QUANTITY OF SOLVENT CAN BE LOST TO THE SOUR WATER SYSTEM, AND WILL HAVE TO BE REPLACED WITH FRESH AMINE FROM THE STORAGE TANK. FOR THIS REASON, THE "BLEED" WATER SYSTEM SHOULD BE BLOCKED-IN DURING UPSETS IN THE STRIPPER. (2)
Increase the Amine Absorber overhead temperature by raising the setpoint of the lean solvent temperature controller to increase the lean solvent temperature. This will increase the amount of water leaving in the fuel gas, and it will also reduce the H2S-removal capability of the solvent. An increase in solvent flow rate will probably be needed to maintain the same H2S content in the vent gas, increasing the load on the Stripper and the other process equipment associated with the circulating solvent.
(3)
Increase the acid gas temperature by increasing the temperature setpoint of the reflux temperature controller to raise the outlet temperature from the Stripper Reflux Condenser. Although this will increase the water content of this stream and reduce the water in the solvent, the effect will be small because the quantity of acid gas is small relative to the fuel gas. This adjustment is the least effective and would not normally be considered during routine operations.
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SULFUR BLOCK (4)
B.
7.6.4
Should the solvent inventory be difficult to control due to continuing problems with an excessive amount of water in the solvent, the steam-heated Stripper Reboiler should be checked for tube leaks.
Conversely, a persistently decreasing liquid level in the bottom of the Stripper indicates a loss in the solvent water content. To increase the water content of the solvent, the preferred sequence of gradual adjustments is: 1.
Reduce or terminate the "bleed" water from the Stripper Reflux Accumulator.
2.
Decrease the Amine Absorber overhead temperature by lowering the lean solvent temperature with the lean solvent temperature controller to reduce the amount of water leaving in the fuel gas.
3.
Decrease the acid gas temperature with the aerial cooling from the Stripper Reflux Condenser to reduce the water loss in the stream as much as possible.
4.
Begin water makeup (or increase the makeup water rate) to the solvent system using the make-up flow controller to add condensate to the system..
Amine Loss The loss of MDEA by chemical degradation in the ATU/ARU is expected to be negligible because the upstream Wash Water Column should wash out any acids or other contaminates that enter with the sour fuel gas. Amine degradation can occur, however, under abnormal operating conditions. Amine degradation occurs via reactions with acids which can enter the Amine Absorber when the Wash Water Column is experiencing an upset. Any traces of acid entering the Amine Absorber will react with the MDEA to form a thermally non-regenerable complex (i.e., heat-stable salt). If present in sufficient quantity, this salt can alter the H2S-amine equilibrium and prevent removal of H2S to the desired level in the Amine Absorber overhead. Heat-stable salts also increase the corrosivity of the amine. Amine quality can be restored by treatment with an amount of caustic equivalent to the non-regenerable salt present but, if repeated caustic
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SULFUR BLOCK treatments are necessary due to repeated mal-operation, the potential for salt deposition in the system may rise. The equipment in the ATU/ARU, including the seals of pumps and blowers, should be operated at positive pressure to minimize the potential for oxygen (air) ingress into the amine. Oxygen will react with the amine to produce carboxylic acids that cause the solution to be corrosive. For this same reason, it is important to maintain an inert gas "blanket" on the MDEA storage tank to prevent oxygen contamination of the fresh amine. Amine losses due to entrainment in the treated fuel gas or the acid gas can be minimized by proper process operation (avoidance of column overloading, foaming, etc.) and routine inspection of the vessel internals. Amine losses in the water "bleed" from the Stripper reflux should be negligible if the rectifying trays (the "wash water" trays above the amine feed point) in the Stripper are operating properly (no flooding or foaming, no mechanical damage). The primary source of amine loss will likely be the mechanical losses from pump drips, cleaning of filters, etc. Good housekeeping practices, including prompt replacement or repair of leaking pumps, together with proper collection of amine drips for reuse (via the ATU Drips Tank, A2-FA1580), will minimize the mechanical loss of amine.
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SULFUR BLOCK 7.6.5
Operation at Low Flow Rates The ATU/ARU contains four columns: the Wash Water Column and the Flash Gas Contactor, which contain structured packing; and the Amine Absorber and Stripper, which contain valve trays. In general, the liquid feed rate to packed towers can decrease in proportion with the gas flow rate down to about 50% of design gas flow rate. Below this point, the liquid rate cannot be allowed to drop any further without risking poor column performance due to uneven liquid distribution and wetting of the packing. Trayed towers typically offer somewhat better turndown, allowing the liquid rate to drop to 30-40% of design before "weeping" of the trays begins to significantly affect performance. In the case of the Wash Water Column, decrease the wash water rate in proportion with the gas flow rate down to about 50% of design should maintain adequate performance. (It should be noted, however, that there is really no detrimental effect if the wash water circulation is simply left at the design value at all times. The only drawback is slightly higher power consumption by the pump and aerial cooler.) In the packed Amine Absorber, circulating more amine relative to the gas flow rate should maintain performance. The liquid flow rate should be maintained at a minimum of about 50%.
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SULFUR BLOCK
7.7
Precommissioning Procedures Prior to the initial startup, there are a number of precommissioning activities that are necessary to ensure that the newly constructed plant is ready to be placed in service. The activities outlined below should serve as a guide, but there may be others required as a part of your normal plant procedures.
7.7.1
Preliminary Check-out Check all equipment to ensure that it is properly installed. This will probably require consulting Manufacturer's literature as well as construction drawings.
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A.
Check and lubricate all equipment, in accordance with the Manufacturer's recommendations.
B.
Check the rotation of the following pumps by "bumping" them: (1) (2)
Wash Water Pump. Rich Amine Pump.
(3) (4) (5) (6) (7)
Stripper Reflux Pump. Lean Amine Pump.
Lean Amine Booster Pump ATU Skim Oil Pump MDEA Transfer Pump
C.
Check the rotation of the fans on the Lean Amine Cooler and the Stripper Reflux Condenser, by operating each fan for a short period.
D.
Check all piping and equipment to be sure that all blinds have been removed and that no valves are vented to atmosphere.
E.
Place the Instrument Air System in service to all instruments and check the action of controllers and control valves.
F.
Check all relief valves to ensure that they are installed in the proper locations, the inlet and outlet block valves (if provided) are open, the bypass valves (if provided) are closed, and the relief valves are set for the correct relieving pressure.
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SULFUR BLOCK 7.7.2
7.7.3
Shutdown System Check-out A.
Physically check all shutdown activating devices to ensure that they activate the ESD system.
B.
Physically check all devices activated by the ESD system to ensure that they operate properly.
C.
Check all relief valves to ensure that they are installed in the proper locations and set for the correct relieving pressures.
D.
The low-low level shutdowns for the pumps in the wash water and amine systems will be tested while washing these systems as described in the following sections.
Leak Testing the Process Piping and Equipment The process piping and equipment in the ATU can be checked for leaks by using a temporary nitrogen “jumper” to pressurize the process side of the equipment and piping to about 0.6-0.7 kg/cm2(g), then checking flanges, etc. for leaks (usually by applying masking tape or "Snoop" to the flanges, and by listening for other leaks). This same procedure can be used to leak test the ATU following maintenance, before restarting the unit. Whenever plant maintenance requires opening one or more of the flanged connections in the ATU it is good practice to leak test the unit before returning it to service. This allows detecting any leaking connections that may have resulted from the maintenance operations before sour fuel gas is reintroduced into the unit. To perform leak testing in the ATU, proceed as follows:
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A.
Reduce the output from the sour fuel gas hand control in the DCS to 0% to close the Sour Fuel Gas inlet valve.
B.
Confirm that the Wash Water Column is isolated from the wash water circulation loop by confirming that the following valves are all closed: (1)
The bypass valve and downstream block valve at the wash water flow control valve.
(2)
The suction valves at the Wash Water Pumps.
(3)
The drain valve on the suction line to the pumps.
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SULFUR BLOCK (4)
C.
The bypass valve and downstream block valve at the make-up water flow control valve.
Confirm that the Amine Absorber is isolated from the solvent circulation loop by confirming that the following valves are all closed: (1)
The bypass valve and downstream block valve at the lean solvent flow control valve.
(2)
The bypass valve and upstream block valve at the Absorber level control valve.
(3)
The drain valve upstream of the level control valve.
(4)
The block valves in the water makeup line.
(5)
The bypass valve and upstream block valve at the Absorber overhead pressure control valve to the SRUs.
(6)
The bypass valve and upstream block valve at the Absorber overhead pressure control valve to the flare.
D.
Use a temporary "jumper" to connect a nitrogen supply to one of the level bridles on the Wash Water Feed Knock-out Drum and establish a flow of nitrogen into the unit.
E.
Continue adding 0.6-0.7 kg/cm2(g).
nitrogen
until
the
pressure
reaches
Due to the volume inside the ATU, it will take several minutes for the pressure to build up in the unit.
Issued 30 August 2011
F.
Once the desired pressure has been achieved close the valve where the nitrogen "jumper" is connected to stop the flow of nitrogen. Check all of the equipment and piping connections for visible or audible signs of leakage.
G.
Disconnect the nitrogen jumper.
H.
Re-open valves as necessary to restore the wash water and solvent circulation loops that were isolated from the columns in the previous steps.
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SULFUR BLOCK 7.7.4
Washing the Wash Water System The following procedure is intended to remove grease, rust, scale, dirt, and trash from the equipment and piping in the Wash Water system before it is placed in operation. Washing of the system consists of three steps: an initial water flush to remove dirt and trash from the system; an acid wash to remove grease, rust, and scale; and a caustic wash to acclimate the equipment and piping to alkaline pH. Failure to clean the system properly prior to startup can lead to operating problems (heat exchanger fouling, rapid filter plugging, etc.).
WARNING
THIS PROCEDURE REQUIRES WORKING WITH ACIDIC AND ALKALINE CHEMICALS AND SOLUTIONS. EMPLOYEES MUST OBSERVE ALL APPLICABLE SAFETY PROCEDURES AND ENVIRONMENTAL REGULATIONS CONCERNING USAGE OF PERSONAL PROTECTIVE EQUIPMENT, HANDLING OF HAZARDOUS MATERIALS, DISPOSAL OF WASTE STREAMS, ETC.
7.7.4.1
Issued 30 August 2011
Water Flush A.
Place the Wash Water flow controller in the DCS in "manual" and set its output to 100% to fully open the Wash Water flow control valve.
B.
Place the Wash Water Column level controller in the DCS in "manual" and set its output to 0% to fully close the level control valve.
C.
Confirm that the Sour Fuel Gas inlet hand control in the DCS is set to 0% output so that the Sour Fuel Gas inlet valve is fully closed.
D.
Verify that the Wash Water flow control valve is fully open. Open both of its isolation block valves and its bypass valve.
E.
Verify that the Wash Water Column level control valve is fully closed. Close both of its isolation block valves and its bypass valve.
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SULFUR BLOCK F.
Verify that the Sour Fuel Gas inlet valve is fully closed. (This will prevent water from entering the upstream equipment if the Wash Water Column is accidentally over-filled.)
G.
The Wash Water Filters will not be used to filter solids during this time, but the filter vessels and their piping are to be flushed and cleaned. Remove the filter elements, then bolt-up the filters. Open the inlet and outlet block valves on the filters, and open the bypass valve around the filters.
H.
Add water to the top of the Wash Water Column by placing the Make-up Water flow control valve in manual and setting its output to 100% to fully open the make-up water flow control valve. If make-up water is not available from the Sour Water Stripping unit, use a temporary jumper to supply water (cold condensate) to the Wash Water Column.
Issued 30 August 2011
I.
Once there is an adequate level in the column, all the way to the top of its level gauge open the suction valve on a Wash Water Pump and use its drain valve to be sure the pump is flooded with water. Start the pump, then open its discharge valve.
J.
Watch the level in the Wash Water Column while placing the pump in service to be sure the pump does not lose suction while filling the downstream piping and equipment. If the level disappears in the column, shut the pump down until enough water (or condensate) is added to reestablish the level, then restart the pump.
K.
Once circulation is achieved and the level in the Wash Water Column is adequate (about halfway up in the level gauge), discontinue the addition of water (or condensate).
L.
Use the low point drain valves to flush out each section of the system. Leave the drain valves open until the water is clear.
M.
Briefly open the bypass valve on the Wash Water Column level control valve to flush this section of piping to The Sour Water Stripping Unit. Open the upstream block valve, open the Wash Water Column level control valve with the level controller in the
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SULFUR BLOCK DCS, and use the downstream drain valve to flush the control station. Once the flush water clears up, close the Wash Water Column level control valve and the upstream block valve. N.
Circulate the water and blow down the low point drains until all of the drain water is clear. Add more water ( or condensate) as necessary to maintain the level in the Wash Water Column. At some point during the washing procedure, the standby pump should be placed in service while the other pump is shut down. This will ensure cleaning out both pumps and their associated piping.
7.7.4.2
O.
Once the drain water is clear, completely drain the system. Drain the system as quickly as possible, so that the water velocity helps to flush the solids from all parts of the system.
P.
Allow the pump to continue running while the system drains, but watch the pump closely to verify that the low-low level shutdown shuts the pump down below the shutdown setpoint. If the level drops completely out of the gauge glass before the pump shuts down, stop the pump manually and correct the problem with the low-low level shutdown before proceeding further.
Acid Wash A weak (0.1 wt %) citric acid solution is used next to remove grease, rust, and scale from the equipment and piping. The citric acid will chelate with the iron in the rust and scale so that it dissolves in the solution.
Issued 30 August 2011
A.
Reestablish a level in the Wash Water Column.
B.
Once a level is established, start a Wash Water Pump to begin circulating the water.
C.
Add concentrated citric acid to the circulating water to make a 0.1 wt % citric acid solution.
D.
After circulating for about 3 hours, start the other Wash Water Pump and shut down the first one.
E.
Circulate the solution for a total of about 6 hours, blowing down the low point drains occasionally. Add more water (or
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SULFUR BLOCK condensate) if necessary to maintain the level in the Wash Water Column.
7.7.4.3
F.
Briefly open the bypass valve on the Wash Water Column level control valve to flush this section of piping to The Sour Water Stripping Unit. Then open both block valves and use the level controller in the DCS to open the Wash Water Column level control valve briefly and flush the control station. Close the Wash Water Column level control valve and the block valves.
G.
After 6 hours, shut down the pump and completely drain the system. Drain the system as quickly as possible, so that the liquid velocity will help flush any remaining solids from the system.
Alkaline Wash The washing operation is completed by circulating a weak alkaline solution through the system. This will neutralize any citric acid left in the system, and acclimate the system to high pH operation so that no further scale is removed from the equipment and piping when the normal Wash Water (8.0-9.5 pH) is circulated.
Issued 30 August 2011
A.
Reestablish a level in the Wash Water Column.
B.
Once a level is established, start a Wash Water Pump to begin circulating the water.
C.
Add caustic to the circulating water to make a 0.02 wt% solution. This should give a pH in the range of 11-22.
D.
Check the pH of the circulating water. If the pH is less than 11, add more caustic until the pH is 11 or higher.
E.
After circulating for about 1 hour, start the other Wash Water Pump and shut down the first one.
F.
Circulate the solution for a total of about 2 hours, blowing down the low point drains occasionally. Add more water (or condensate) if necessary to maintain the level in the Wash Water Column.
G.
Briefly open the bypass valve on the Wash Water Column level control valve to flush this section of piping to the sour water header. Then open both block valves and use the level
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SULFUR BLOCK controller in the DCS to open the Wash Water Column level control valve briefly and flush the control station. Close the Wash Water Column level control valve and the block valves. H.
7.7.4.4
After 2 hours, shut down the pump and completely drain the system. Drain the system as quickly as possible, so that the liquid velocity will help flush any remaining solids from the system.
Initial Water Fill The Wash Water system should now be clean and ready to place in service. All that remains is to refill the system with water and establish the proper operating conditions.
Issued 30 August 2011
A.
Close the inlet and outlet block valves on the Wash Water Filters (but leave the bypass valve open), then install the proper element(s) in the filters. Leave the block valves closed for now.
B.
Reestablish a level in the Wash Water Column.
C.
Once a level is established, start a Wash Water Pump to begin circulating the water.
D.
Place the Wash Water Filters in service as follows: (1)
Open the vent valves on the top of the filters.
(2)
"Crack" the filter inlet block valves open slightly and allow the filters to fill with water. When the filter is full, close the vent valve.
(3)
Open the filter inlet block valves fully and open the outlet block valves, then close the filter bypass valve.
E.
Place the Wash Water flow controller in the DCS in service and set its setpoint to its normal value. Close the bypass valve on the Wash Water flow control valve.
F.
Confirm that the Wash Water Column level control valve is closed, then open both of its block valves. Place the level controller in the DCS in service and set its setpoint to its normal value.
G.
Establish cooling water flow to the Amine Absorber Overhead Cooler.
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SULFUR BLOCK The Wash Water system is now ready for service. It can remain in this operating mode indefinitely while the rest of the ATU is prepared for startup. Check the system periodically for indications of plugging, etc. (low flow, erratic pump discharge pressure, high filter pressure drop), as solid materials may accumulate at various points in the system over time.
7.7.5
Washing the Amine System The following procedure is intended to remove grease, rust, scale, dirt, and trash from the equipment and piping in the solvent system before it is placed in operation. Washing of the system consists of three steps: an initial water flush to remove dirt and trash from the system; an acid wash and rinse to remove grease, rust, and scale; and a weak amine wash and rinse to acclimate the equipment and piping to alkaline pH. Failure to clean the system properly prior to startup can lead to operating problems (column foaming, poor treating, heat exchanger fouling, rapid filter plugging, etc.).
WARNING
THIS PROCEDURE REQUIRES WORKING WITH ACIDIC AND ALKALINE CHEMICALS AND SOLUTIONS. EMPLOYEES MUST OBSERVE ALL APPLICABLE SAFETY PROCEDURES AND ENVIRONMENTAL REGULATIONS CONCERNING USAGE OF PERSONAL PROTECTIVE EQUIPMENT, HANDLING OF HAZARDOUS MATERIALS, DISPOSAL OF WASTE STREAMS, ETC.
7.7.5.1
Water Flush A.
Issued 30 August 2011
Place the following controllers in the DCS in "manual" with their outputs set as indicated: (1)
Set the output from the lean solvent flow controller to 100% to fully open the lean solvent flow control valve.
(2)
Open the manual block valve upstream of the lean solvent filters.
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SULFUR BLOCK (3)
Set the output from the lean solvent filter bypass flow controller to 100% to fully open the filter bypass flow control valve.
(4)
Set the output from the Amine Absorber level controller to 100% to fully open the Amine Absorber level control valve.
(5)
Set the output from the Rich Amine flow controller to 100% to fully open the rich amine flow control valve.
(6)
Set the output from the amine flow controller to the Flash Gas Contactor to 100% to fully open the flow control valve.
(7)
Set the output from the Stripper Reboiler steam flow controller to 0% to fully close the steam flow control valve.
(8)
Set the output from the Stripper Reflux Accumulator level controller to 0% to fully close the Stripper Reflux Accumulator level control valve.
(9)
Set the output from the bleed water flow controller to 0% to fully close the bleed water flow control valve.
(10) Set the output from the flow controller on the spill-back line to the lean amine cooler to 0% to fully close the spill-back flow control valve. (11) Set the output from the makeup water flow controller to 0% to fully close the makeup water flow control valve. (12) Set the output from the Stripper pressure controller to 0% to fully close the overhead pressure control valve to the SRU. (13) Set the outputs from the two temperature controllers to 0% to fully close both temperature control valves to the DHT Unit. (14) Set the output from the lean solvent flow controller to the LPG Treating Unit to 0% to fully close the lean solvent flow control valve to the LPG Treating Unit. B.
Issued 30 August 2011
Place the other Stripper pressure controller in "automatic" with a setpoint of 0.85 kg/cm2(g). This will open the pressure control
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SULFUR BLOCK valve to the flare if pressure builds in the Stripper during this procedure. C.
D.
Issued 30 August 2011
Verify that the following control valves are fully open. Open both of the isolation block valves and the bypass valve (where applicable) at each control station. (1)
The lean amine flow control.
(2)
The lean amine filter bypass.
(3)
The Amine Absorber level control, (the rich solvent from the Amine Absorber).
(4)
The rich solvent flow control (the rich solvent from the Rich Amine Flash tank)
(5)
The lean solvent to the Flash Gas Contactor
Verify that the following control valves are fully closed. Close both of the isolation block valves and the bypass valve at each control station. (1)
The steam flow control valve to the Stripper Reboiler.
(2)
The Stripper Reflux Accumulator level control valve.
(3)
The bleed water flow control valve from the Stripper reflux.
(4)
The spill-back flow controller to the Lean Amine Cooler.
(5)
The makeup water flow control valve.
(6)
The acid gas pressure control to the SRU.
E.
Verify that the bypass valve on the pressure control valve to the flare is closed. Open both of the isolation block valves at this control station.
F.
The solvent filters will not be used to filter solids during this time, but the filter vessels and their piping are to be flushed and cleaned. Remove the filter elements, then bolt-up the individual filters. Open the inlet and outlet block valves on each filter, and open the bypass valves for the filters.
G.
Verify that the valves in the amine makeup line are closed.
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SULFUR BLOCK H.
Add water (cold condensate) to the Amine Absorber by opening the flow control valve in the make-up water line.
I.
Once there is an adequate level in the Rich Amine Flash Tank, all the way to the top of its level gauge open the suction valve on a Rich Amine Pump and use its drain valve to be sure the pump is flooded with water. Start the pump, then open its discharge valve. Watch the level in the Amine Absorber and the Rich Amine Flash Tank as the pump fills the downstream piping and begins to fill the Stripper. When the level drops to the low-low level shutdown it should shut down the pump. If it does not, stop the pump manually before it loses suction and correct the problem with the low level shutdown before proceeding.
Issued 30 August 2011
J.
Continue filling the Amine Absorber with condensate and pumping the water to the Stripper periodically, until the level in the Stripper is all the way to the top of its level gauge.
K.
Once there is an adequate level in the Stripper, open the suction valve on a Lean Amine Booster Pump and use its drain valve to be sure the pump is flooded with water. Start the pump, then open its discharge valve.
L.
Once the downstream piping and equipment has been filled with water, open the suction valve on a Lean Amine Pump and use its drain valve to be sure the pump is flooded with water. Start the pump, then open its discharge valve
M.
As the pump fills the downstream piping and begins to return water to the Amine Absorber, watch the level in the Stripper to be sure the Lean Amine Booster Pump does not lose suction. If the level disappears in the column, shut both pumps down, add more condensate to the Amine Absorber and pump it to the Stripper to reestablish the level, then restart the Lean Amine Booster Pump and the Lean Amine Pump.
N.
As the level begins to rise in the Amine Absorber, restart the Rich Amine Pump. Watch the levels in both columns, and shut a pump down if necessary to keep from emptying either column.
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SULFUR BLOCK O.
Once the levels in both columns are adequate, discontinue the addition of condensate.
P.
At this point, neither the flow into or the level of the Amine Absorber is being controlled. Both control stations are in "manual" with the valves fully open to flush the piping as much as possible. Depending on the hydraulics of the system, it may be necessary to place either or both of these controls in "automatic" to prevent losing the level in one of the columns. If so, leave the bypass valve on the control station "cracked" so that the bypass piping gets flushed.
Q.
Use the low point drain valves to flush out each section of the system. Leave the drain valves open until the water is clear.
R.
Circulate the water and blow down the low point drains until all of the drain water is clear. Add more condensate as necessary to maintain the levels in the columns. At some point during the washing procedure, the standby Rich Amine Pump, standby Lean Amine Pump, and standby Lean Amine Booster Pump should be placed in service while the other pumps are shut down. This will ensure cleaning out both pumps and their associated piping in each service. At some point in the washing procedure, open the flow control valve in the spill-back line to the Lean Amine Cooler to clean out this section of piping. Then close the control valve again.
Issued 30 August 2011
S.
Once the drain water is clear, shut down the Rich Amine Pump and completely drain the system. Drain the system as quickly as possible, so that the water velocity will help flush the solids from all parts of the system.
T.
Allow the Lean Amine Pump and the Lean Amine Booster Pump to continue running while the system drains, but watch the pumps closely to verify that the Stripper low-low level shutdown shuts the pumps down when the level falls to the shutdown setpoint. If the level drops completely out of the gauge glass before the pumps shut down, stop the pumps manually and correct the problem with the low level shutdown before proceeding further.
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SULFUR BLOCK U.
7.7.5.2
Confirm that the solvent transfer line (for MDEA makeup) has been flushed and is ready for service.
Acid Wash A weak (0.1 wt %) citric acid solution is used next to remove grease, rust, and scale from the equipment and piping. The citric acid will chelate with the iron in the rust and scale so that it dissolves in the solution.
Issued 30 August 2011
A.
Use the make-up water line to re-establish the levels in the Amine Absorber, Rich Amine Flash Tank, and the Stripper as before, and establish circulation of water in the system.
B.
Add concentrated citric acid to the circulating water to make a 0.1 wt % citric acid solution.
C.
Begin steam flow to the Stripper Reboiler and gradually raise the temperature of the circulating solution. For maximum effectiveness, the solution should be 65-95°C throughout the system, so adjust the steam flow accordingly. The fans on the Lean Amine Cooler should not be operating at this time.
D.
It is unlikely that any steam will leave the top of the Stripper during this operation, so the Stripper Reflux Accumulator should remain dry. If a level should develop in this vessel, drain the water from the vessel using a drain valve on one of the Stripper Reflux Pumps.
E.
After circulating for about 3 hours, start the other Rich Amine Pump and shut down the first one. Do the same with the Lean Amine Pumps and the Lean Amine Booster Pumps.
F.
Open the flow control valve in the spill-back line to the Lean Amine Cooler and circulate through this section of piping. Then close the control valve.
G.
Circulate the hot solution for a total of about 6 hours, blowing down the low point drains occasionally. Add more condensate if necessary to maintain the levels in the columns.
H.
After 6 hours, shut off the steam to the Stripper Reboiler, shut down the pumps, and completely drain the system. Drain the system as quickly as possible, so that the liquid velocity will help flush any remaining solids from the system. Amine Treating & Regeneration
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SULFUR BLOCK
Issued 30 August 2011
I.
Use the condensate makeup line to reestablish the levels in the Amine Absorber and the Stripper as before, and establish circulation of water to flush the system.
J.
Switch to the other pumps for a few minutes, then shut down the pumps and completely drain the system.
K.
Once again, use the condensate makeup line to reestablish the levels in the Amine Absorber and the Stripper as before, and establish circulation of water in the system.
L.
Reestablish steam flow to the Stripper Reboiler and gradually raise the temperature in the column.
M.
When the temperature begins to rise in the Stripper overhead line, start a fan on the Stripper Reflux Condenser and place the reflux temperature controller in service with a setpoint of 49°C.
N.
When a level builds in the Stripper Reflux Accumulator, drain it to the closed drain from the drain on one of the pump cases.
O.
Open the downstream block valve at the Stripper Reflux Accumulator level control valve, then use the drain valve to blow steam from the column backwards down the reflux line to remove any debris. Continue until the steam blows clear, then close the drain valve and the block valve.
P.
Continue to circulate water and apply heat in the Stripper Reboiler, until the water drained from the Stripper Reflux Accumulator is clear. During this time, blow down the low point drains occasionally and add more condensate if necessary to maintain the levels in the columns, and switch to the other Rich Amine Pump, Lean Amine Booster Pump, and Lean Amine Pump.
Q.
Once the reflux loop has cleared up (the drain water is clear), shut off the steam to the Stripper Reboiler, shut down the pumps, and completely drain the system. Drain the system as quickly as possible, so that the liquid velocity will help flush any remaining solids from the system.
R.
Check the pH of the water draining from the system. If necessary, repeat Steps K through Q until the pH of the drain water is about the same as the pH of the condensate makeup.
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SULFUR BLOCK 7.7.5.3
Weak Amine Wash The washing operation is completed by circulating a weak amine solution through the system. This will neutralize any citric acid left in the system, and acclimate the system to alkaline pH operation so that no further scale is removed from the equipment and piping when the normal solvent is circulated. A.
Use the condensate makeup line to reestablish the levels in the Amine Absorber and the Stripper as before, and establish circulation of water in the system.
B.
Add enough MDEA to the circulating water to reach a concentration of about 1 wt%.
C.
Begin steam flow to the Stripper Reboiler and gradually raise the temperature in the column.
D.
When the temperature begins to rise in the Stripper overhead line, check that at least one of the fans is running on the Stripper Reflux Condenser.
E.
When a level builds in the Stripper Reflux Accumulator, open the suction valve on one of the Stripper Reflux Pumps and use its drain valve to be sure the pump is flooded with water. Start the pump, open its discharge valve, then open the bypass valve on the Stripper Reflux Accumulator level control valve to pump the water back into the Stripper. Watch the level in the Stripper Reflux Accumulator while pumping it out. Shut the pump down when the vessel is empty, then close the suction and discharge valves on the pump and close the bypass valve on the Stripper Reflux Accumulator level control valve.
F.
Issued 30 August 2011
Continue to circulate the solution and apply heat to the Stripper Reboiler, pumping out the Stripper Reflux Accumulator as required by alternating which pump is used. During this time, blow down the low point drains occasionally and add more condensate if necessary to maintain the levels in the columns, and switch to the other Rich Amine Pump, Lean Amine Booster Pump and Lean Amine Pump.
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SULFUR BLOCK
7.7.5.4
G.
During one of the pumping cycles for the Stripper Reflux Accumulator, flush out the minimum flow spill-back line by opening the manual block valve to allow circulation through this line. Then close the manual block valve.
H.
During another pumping cycle, flush out the bleed water piping by setting the output of the bleed water flow controller to 100% to fully open the bleed water flow control valve, opening its upstream and downstream block valves, and opening its bypass valve. Then close the valves and set the output of the bleed water flow control valve back to 0%.
I.
Take a sample of the circulating solution and run a foam test on it using the procedure in Section 7.10.
J.
Once the solution drained from all the low point drain valves is clear, shut off the steam to the Stripper Reboiler, shut down the pumps, and completely drain the system. Drain the system as quickly as possible, so that the liquid velocity will help flush any remaining solids from the system.
K.
Use the condensate makeup line to reestablish the levels in the Amine Absorber and the Stripper as before, and establish circulation of water to flush the system.
L.
Open the control valve in the spill-back line to the Lean Amine Cooler for a few minutes, then close the control valve.
M.
Switch to the other pumps for a few minutes, then shut down the pumps and completely drain the system.
N.
If the solvent sample taken in Step I was foamy, repeat Steps A through M until the solvent is not foamy.
Initial Solvent Fill The solvent system should now be clean, ready to place in service. All that remains is to fill the system with the proper solvent charge and establish the proper operating conditions. NOTE:
Issued 30 August 2011
This procedure prepares the solvent system for operation in the shortest possible time. However, it does allow the MDEA to come in contact with oxygen that is in the Amine Absorber. If a slightly longer startup schedule can be tolerated, this deficiency can be minimized or eliminated
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SULFUR BLOCK by deferring the procedure in this section until nitrogen has been used to purge the Wash Water Column and Amine Absorber as described in the following section.
Issued 30 August 2011
A.
Close the inlet and outlet block valves (but leave the bypass valves open) on the solvent filters, then install the proper elements and/or carbon in the filters. Leave the block valves closed on each filter for now.
B.
Use the condensate makeup line to reestablish the levels in the Amine Absorber and the Stripper as before, and establish circulation of water in the system.
C.
Add enough MDEA to the circulating water to reach a concentration of about 45 wt%.
D.
Place in service and adjust the level controller on the Amine Absorber to maintain its normal setpoint. Stop the condensate and/or amine makeup when the Stripper level is about 50-60%.
E.
Begin steam flow to the Stripper Reboiler and gradually raise the temperature in the column. Place the steam flow controller in the DCS on "automatic" with its setpoint set to its normal value.
F.
Open the high point vent valve on the Stripper overhead line and allow the steam to purge any air from the vessel. As the pressure builds, the vent valve can be closed.
G.
Monitor the stripper pressure, and adjust the overhead pressure controller if necessary to maintain the stripper pressure at about 0.85 kg/cm2(g) as the system is heated to operating temperatures.
H.
Ensure that the fans are running on the Lean Amine Cooler and the Stripper Condenser.
I.
Place the lean solvent temperature controllers in "automatic" and set their setpoints to their normal values.
J.
When a level builds in the Stripper Reflux Accumulator, open the suction valve on one of the Stripper Reflux Pumps and use its drain valve to be sure the pump is flooded with water. Open the block valves upstream and downstream of the reflux flow
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SULFUR BLOCK control valve, place the reflux flow controller in "automatic" with its setpoint set to its normal value, then start the pump and open its discharge valve. K.
Open the block valves on the Stripper Reflux Accumulator level control valve and place the level controller in the DCS in "automatic" with its setpoint set to its normal value. The Stripper Reflux Accumulator level control valve will now open as needed to pump water back into the Stripper and maintain the desired level in the Stripper Reflux Accumulator.
L.
If the control loops on the solvent have not already been placed in service, do so at this time. Switch the Amine Absorber level controller, and the lean solvent flow controller in the DCS to "automatic" with their setpoints set to their normal values.
M.
Place the Amine flow controller to the Flash Gas Contactor in “automatic” and set its setpoint to its normal value.
N.
Place the level controller for the Rich Amine Flash Tank in service as follows:
O.
Issued 30 August 2011
(1)
Confirm that the level controller in the DCS is in "automatic".
(2)
Confirm that the remote setpoint the level controller is supplying to the rich amine flow controller matches the current local setpoint on the flow controller.
(3)
Switch the rich amine flow controller to "cascade" mode so that the setpoint for the rich amine flow will now be adjusted automatically by the level controller.
(4)
The setpoint of the level controller will be set at the last reading. Adjust the setpoint to its normal value.
Place each of the solvent filters in service as follows: (1)
Open the vent valve on the top of the filter.
(2)
"Crack" the filter inlet block valve open slightly and allow the filter to fill with solvent. When the filter is full, close its vent valve.
(3)
Open the inlet and outlet block valves on the filter.
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SULFUR BLOCK (4)
Slowly close the valve in the bypass line around the filter.
P.
Analyze a sample of the circulating solvent using the procedure in these guidelines to determine the amine concentration. Add more fresh MDEA using the solvent transfer line if needed to bring the concentration up to the design value, 45 wt %.
Q.
Confirm that the bleed water flow controller is in "manual' with its output set at 0% and that the bleed water flow control valve is closed, then open its upstream and downstream block valves.
The solvent system is now ready for service. It can remain in this operating mode indefinitely while the rest of the Sulfur Block is prepared for startup. Check the system periodically for indications of plugging, etc. (low flow, erratic pump discharge pressure, high filter pressure drop), as solid materials may accumulate at various points in the system over time.
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SULFUR BLOCK 7.7.6
Purging the Low Pressure Columns Prior to starting up the using the procedures in Section 7.8 of these guidelines, nitrogen should be used to purge the Wash Water Column and the Amine Absorber. This will displace the air introduced into the columns while washing and filling them earlier. At this point, the following conditions should exist in the ATU: The Wash Water system and perhaps the amine system have been cleaned and loaded with their respective initial fills of water and amine. (The amine system may be waiting on purging of the Amine Absorber before the system is loaded with amine.)
7.7.6.1
Purging the Columns To establish nitrogen flow into the ATU, proceed as follows: A.
Reduce the output from the Sour Fuel Gas hand control in the DCS to 0% to close the Sour Fuel Gas inlet valve.
B.
Confirm that the Wash Water Column is isolated from the wash water circulation loop by confirming that the following valves are all closed:
C.
Issued 30 August 2011
(1)
The bypass valve and downstream block valve at the wash water flow control valve.
(2)
The suction valves at the Wash Water Pumps.
(3)
The drain valve on the suction line to the pumps.
(4)
The bypass valve and downstream block valve at the make-up water flow control valve.
Confirm that the Amine Absorber is isolated from the solvent circulation loop by confirming that the following valves are all closed: (1)
The bypass valve and downstream block valve at the lean solvent flow control valve.
(2)
The bypass valve and upstream block valve at the Absorber level control valve.
(3)
The drain valve upstream of the level control valve.
(4)
The block valves in the water makeup line.
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SULFUR BLOCK (5)
D.
Open all of the vent valves on the PI and PDT taps on the Wash Water Column and the Amine Absorber, and the vent valves at the tops of the columns.
E.
Use a temporary "jumper" to connect a nitrogen supply to one of the level bridles on the Wash Water Feed Knock-out Drum and establish a flow of nitrogen into the unit.
F.
Allow the nitrogen to continue flowing long enough to reduce the oxygen concentration in the equipment and piping to less than 1%. Use a portable oxygen analyzer to determine the oxygen concentration.
G.
Disconnect the nitrogen jumper.
H.
Re-open valves as necessary to restore the wash water and solvent circulation loops that were isolated from the columns in the previous steps.
NOTE:
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The bypass valve and upstream block valve at the Absorber overhead pressure control valve.
If the initial solvent fill was not loaded into the solvent system earlier to avoid exposing the MDEA to oxygen, this can be accomplished now. Follow the procedure given in the previous section to fill the solvent system with its initial solvent charge.
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SULFUR BLOCK
7.8
Startup Procedures The ATU is now ready to accept sour fuel gas from the complex.
7.8.1
Wash Water and Amine Systems Before routing sour fuel gas into the Wash Water Column and the Amine Absorber, the wash water and amine systems should be operating and ready to accept sour gas. The operating conditions described below should have been established previously at the conclusion of the washing operations but are repeated below to serve as a "checklist" before introducing sour fuel gas to the columns as described in the sections that follow.
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A.
The H2S analyzer has been calibrated.
B.
The Wash Water system should be charged with its initial fill of water, so that the level in the Wash Water Column is at the normal setpoint for the Wash Water Column level controller.
C.
Wash Water should be circulating to the Wash Water Column at the normal setpoint for the Wash Water flow controller.
D.
The Wash Water Filter should be in service.
E.
The amine system should be charged with its initial fill of amine, with the level control in the DCS controlling the level in the Amine Absorber at its normal setpoint and the level control in the DCS controlling the level in the Rich Amine Flash Tank at its normal setpoint.
F.
The MDEA concentration in the amine should be close to its design value (45 wt %). Add more fresh MDEA if necessary to bring the amine to this strength.
G.
Amine should be circulating through the Stripper, the Lean/Rich Exchanger, and the Lean Amine Cooler to the distributor tray at the top of the Amine Absorber at the normal setpoint for the flow controller.
H.
The fans should be operating on the Lean Amine Cooler, with the temperature controllers on the lean amine controlling at their normal setpoints.
I.
The Rich Amine Filters should be in service.
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SULFUR BLOCK J.
The lean amine filters should be in service, with the bypass flow controller controlling at its normal setpoint.
K.
Steam should be flowing to the Stripper Reboiler at the normal setpoint for the flow control.
L.
The overhead temperature from the Stripper should be above the low temperature alarm point for the temperature indicator.
M.
The fans should be operating on the Stripper Reflux Condenser with the temperature controller on the outlet from the Stripper Reflux Condenser controlling at its normal setpoint or lower.
N.
The Stripper pressure controller to the SRU, should be in "manual" with its output set to 0% so that the pressure control valve is fully closed.
O.
The Stripper pressure controller to the flare should be in "automatic" with a setpoint of 0.85 kg/cm2(g).
P.
The level in the Stripper Reflux Accumulator should be at the normal setpoint for the level control.
Q.
A Stripper Reflux Pump should be operating with the minimum flow lined up to allow reflux to spill back into the Stripper Reflux Accumulator whenever the level valve back to the Stripper is closed.
With these operating conditions established, the ATU is ready to accept the sour fuel gas and begin treating it.
7.8.2
Sour Fuel Gas Flow to the Columns The last step in the startup of the ATU is to bring the sour gas from the rest of the complex into the Wash Water Column and the Amine Absorber. They will then remove the H2S from the gas before sending it to the treated fuel gas system. The H2S removed will be stripped from the amine and sent to the flare initially. Once operation of the amine system stabilizes, this acid gas will be routed to the SRUs. Before introducing sour fuel gas into the columns, confirm that the proper operating conditions have been established for the Wash Water and amine systems.
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SULFUR BLOCK If any of the proper conditions have not been established, do not proceed until correcting the problem(s). Once all of the conditions are satisfied, complete the startup of the as follows: A.
Confirm that the sour fuel gas inlet hand control in the DCS is set to 0% output with the Sour Fuel Gas Inlet Valve closed.
B.
Slowly increase the output from the sour fuel gas inlet hand control to 100%, which will open the Sour Fuel Gas Inlet Valve and admit sour fuel gas to the Wash Water Column.
C.
When the output of the sour fuel gas inlet hand control reaches 100%, the Sour Fuel Gas Inlet Valve should be fully open and the pressure control valve to the flare should be closed to send all of the sour fuel gas into the Wash Water Column. Visually confirm that these valves are properly positioned.
D.
Once the operation of the Stripper has stabilized, route its acid gas, which is presently going to the flare through a pressure valve, to the SRUs as follows: (1)
Confirm that the Stripper pressure controller to the SRUs in the DCS is in "manual" with its output set to 0%.
(2)
Confirm that the setpoint of the Stripper pressure controller to the SRU is tracking its current reading, then place it in "automatic".
(3)
Slowly raise the setpoint of the Stripper pressure controller to the flare to 1.0 kg/cm2(g).
(4)
If, necessary, adjust the setpoint of the Stripper pressure controller to the SRU to its normal setpoint.
The Stripper pressure controller will now take over control of the Stripper pressure by opening the pressure valve to send the acid gas to the Acid Gas Knock-Out Drum in the SRUs. The Stripper pressure controller to the flare will close the acid gas pressure valve and stop the flow of acid gas to the flare. If the SRUs shut down (or some other upset causes the Stripper pressure to rise), the Stripper pressure controller to the flare will act as an over-ride and divert the acid gas to the flare.
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SULFUR BLOCK E.
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The ATU is now fully on-stream. away from the ATU, be sure that:
Before directing your attention
(1)
All controllers are functioning properly.
(2)
The steam heating systems are in service and the level control on the Reboiler condensate pot is functioning properly.
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SULFUR BLOCK
7.9
Shutdown Procedures The procedures to be used in performing a planned shutdown of the ATU, or the ATU and ARU, will vary depending on the extent and type of work to be performed in and around the units during the downtime period. If maintenance is to be performed on the ATU, there is no need to also shut down the ARU. This greatly simplifies and shortens the shutdown procedure. Section 7.9.1 that follows is an example of such a procedure. If the ARU must also be shut down, then more extensive procedures must be followed to accomplish a satisfactory shutdown and minimize the time required for performance of the desired maintenance work. Section 7.9.2 that follows is an example of a procedure for this circumstance. Section 7.9.3 is a discussion of emergency shutdown situations. A guide to troubleshooting the causes of unplanned shutdowns is presented to assist in quickly identifying and correcting the problem so that the ATU/ARU can be put back on-line in a minimum amount of time. The ATU/ARU is affected directly and indirectly by shutdowns and outages that occur in other systems within the complex. The more important aspects of the effects these other systems can have on the ATU/ARU are discussed in Section 7.9.4. Typical shutdown procedures are outlined and discussed in the sections that follow for the more common cases. Your existing company procedures and common sense operational judgment should be used to modify these procedures as needed to serve the purpose of any given planned shutdown situation.
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SULFUR BLOCK 7.9.1
Planned Shutdown - ATU Any equipment to be opened should be properly blinded and purged with inert gas before admission of air, to avoid exposure to potentially toxic gases or the formation of flammable vapor mixtures. Any equipment containing amine solution that is to be opened or entered should be drained completely, then flushed with condensate or steamed out to avoid the possibility of skin or eye irritation. It is generally preferable to shut down the ATU in a controlled fashion to minimize the impact on the other process units. If time does not allow performing a controlled shutdown, however, the unit can be shut down by simply activating the ESD system (using the manual shutdown switch). This will automatically block the feed into the ATU (sour fuel gas) and divert the feed gas to the flare system. To shut the ATU down in a controlled fashion proceed as follows: A.
Slowly reduce the output from the Sour Fuel Gas hand control in the DCS. As the pressure in the sour fuel gas inlet line begins to increase, the override pressure controller will open the pressure control valve and begin diverting the sour fuel gas to the flare system.
B.
When the output of the Sour Fuel Gas hand control reaches 0%, the pressure control valve should be open and the Sour Fuel Gas inlet valve should be fully closed to send all of the sour fuel gas to the flare system. Visually confirm that these valves are properly positioned. Confirm that the DCS indicates that the Sour Fuel Gas Inlet Valve is closed.
C.
Allow the amine to continue to circulate until the all of the H2S and CO2 have been stripped from the amine. Once the H2S/CO2 content of the "rich" amine leaving the Absorber is essentially the same as the "lean" amine, the ATU can be shut down and isolated from the ARU.
D.
Depending upon the type and extent of the maintenance work to be done, the wash water can continue to circulate while maintenance is being performed on the Amine Absorber. However, if desired, the wash water system can be shut down as follows: (1)
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Shut down the Wash Water Pump
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SULFUR BLOCK
E.
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(2)
Place the Wash Water flow controller in the DCS in "manual" and set its output to 0% to fully close the wash water flow control valve.
(3)
Place the Wash Water Column level controller in the DCS in "manual" and set its output to 0% to fully close the level control valve.
(4)
Place the make-up water flow controller in the DCS in "manual" and set its output to 0% to fully close the make-up water flow control valve.
(5)
Verify that the wash water flow control valve is fully closed. Close both of its isolation block valves and its bypass valve.
(6)
Verify that the Wash Water Column level control valve is fully closed. Close both of its isolation block valves and its bypass valve.
(7)
Verify that the make-up water flow control valve is fully closed. Close both of its isolation block valves and its bypass valve.
Once the H2S/CO2 content of the "rich" amine leaving the Absorber is essentially the same as the "lean" amine, the ATU can be shut down as follows: (1)
Shut down the Lean Amine Pump
(2)
Place the lean amine flow controller in the DCS in "manual" and set its output to 0% to fully close the lean amine control valve.
(3)
Place the amine make-up water flow controller in the DCS in "manual" and set its output to 0% to fully close the amine make-up water flow control valve.
(4)
Place the Amine Absorber level controller in the DCS in "manual" and set its output to 100% to fully open the level control valve.
(5)
Allow the amine to drain from the Amine Absorber until the low-low level shutdown is activated. This should close the level control valve. Monitor the level in the Amine Absorber
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SULFUR BLOCK and be prepared to close the level control valve if the low-low level shutdown fails to activate. (6)
Monitor the level in the Rich Amine Flash Tank to ensure that rich amine does not spill over into the hydrocarbon section of the vessel. Be prepared to take action and close the Amine Absorber level control valve if the amine level gets too high in the Rich Amine Flash Tank.
(7)
Drain the remaining amine from the Amine Absorber by opening the manual block valve in the drain line upstream of the level control valve to send the remaining amine to the Solvent Drain System.
(8)
Verify that the Amine Absorber level control valve is fully closed. Close both of its isolation block valves and its bypass valve.
(9)
Verify that the lean amine flow control valve is fully closed. Close both of its isolation block valves and its bypass valve.
(10) Verify that the make-up water flow control valve is fully closed. Close both of its isolation block valves and its bypass valve. (11) Verify that the spill-back flow control valve is fully closed. Close both of its isolation block valves and its bypass valve. F.
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The ATU is now ready to be isolated and made safe for entry.
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SULFUR BLOCK 7.9.2
Planned Shutdown - ATU and ARU Any equipment to be opened should be properly blinded and purged with inert gas before admission of air, to avoid exposure to potentially toxic gases or the formation of flammable vapor mixtures. Any equipment containing amine solution that is to be opened or entered should be drained completely, then flushed with condensate or steamed out to avoid the possibility of skin or eye irritation. To shut the ATU and ARU down in a controlled fashion proceed as follows: A.
Shutdown and isolate the DHT Unit and the LPG Treating Unit using the operating procedures for those units.
B.
Slowly reduce the output from the Sour Fuel Gas hand control in the DCS. As the pressure in the sour fuel gas inlet line begins to increase, the pressure controller will open the pressure control valve and begin diverting the sour fuel gas to the flare system.
C.
When the output of the Sour Fuel Gas hand control reaches 0%, the pressure control valve should be open and the Sour Fuel Gas inlet valve should be fully closed to send all of the sour fuel gas to the flare system. Visually confirm that these valves are properly positioned. Confirm that the DCS indicates that the Sour Fuel Gas Inlet Valve is closed.
D.
Allow the amine to continue to circulate with steam flowing to the Stripper Reboiler, until the all of the H2S and CO2 have been stripped from the amine. Once the H2S/CO2 content of the "rich" amine is essentially the same as the "lean" amine, the steam can be shut off to the Stripper Reboiler.
E.
Continue to circulate the amine and operate the Lean Amine Cooler and the Stripper Reflux Condenser until the amine is cool.
F.
Depending upon the type and extent of the maintenance work to be done, the wash water can continue to circulate while maintenance is being performed on the Amine Absorber or on the equipment in the ARU. However, if desired, the wash water system can be shut down as follows: (1)
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Shut down the Wash Water Pump
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SULFUR BLOCK
G.
(2)
Place the Wash Water flow controller in the DCS in "manual" and set its output to 0% to fully close the wash water flow control valve.
(3)
Place the Wash Water Column level controller in the DCS in "manual" and set its output to 0% to fully close the level control valve.
(4)
Place the make-up water flow controller in the DCS in "manual" and set its output to 0% to fully close the make-up water flow control valve.
(5)
Verify that the wash water flow control valve is fully closed. Close both of its isolation block valves and its bypass valve.
(6)
Verify that the Wash Water Column level control valve is fully closed. Close both of its isolation block valves and its bypass valve.
(7)
Verify that the make-up water flow control valve is fully closed. Close both of its isolation block valves and its bypass valve.
Once the amine is cool (60°C or less throughout the system), shut down the equipment in the following order: (1) The Rich Amine Pump. (2) The Lean Amine Booster Pump (3) The Lean Amine Pump. (4) The Stripper Reflux Pump. (5)
H.
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The fans on the Lean Amine Cooler and Stripper Reflux Condenser.
The ATU and ARU are now ready to be isolated and made safe for entry.
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SULFUR BLOCK 7.9.3
Emergency Shutdown The ATU ESD system can be initiated by any of the actuating devices outlined in Section 7.5.2.1 of these guidelines. The operator must determine and correct the condition causing the shutdown before the can be restarted. The problems outlined below should be investigated first by the operator in his troubleshooting procedure. S/D Actuation Device Wash Water Feed Knock-Out Drum High-High Level
Amine Absorber Feed Knock-Out Drum High-High Level
Amine Absorber Low-Low Level
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Possible Causes 1. Excessive liquids being received by the Knock-Out Drum. 2. Malfunction of level control system. 3. Level warning transmitters on the Knock-Out Drum are plugged or inoperable. 1. Excessive liquids being received by the Knock-Out Drum. 2. Malfunction of level control system. 3. Level warning transmitters on the Knock-Out Drum are plugged or inoperable. 1. Malfunction of the Lean Amine Pump 2. Malfunction of the Lean Amine Booster Pump 3. Malfunction of the lean amine flow control system 4. Malfunction of the level control system. 5. Manual drain valve left open.
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SULFUR BLOCK 7.9.4
Effects of Shutdowns and Outages in Other Systems The ATU/ARU system is directly affected by a shutdown and/or outage in the LP steam system for the complex. These effects are described below.
7.9.4.1
Steam System Outage The most immediate impact on the ATU/ARU will be the loss of LP steam to the Stripper Reboiler if the steam outage lasts long enough. As the heat input to the reboiler declines, stripping of the acid gas from the amine will decline and the H2S in the treated fuel gas leaving the Amine Absorber will begin to increase. This will cause the Treated Fuel Gas analyzer to close the pressure control valve to the treated fuel gas system to avoid sending off-spec fuel gas into the complex’s fuel gas system. The override pressure control valve will then open and begin routing the sour fuel gas to the flare system.
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SULFUR BLOCK
7.10 Analytical Procedures This Section contains analytical procedures for determining:
7.10.1
1.
The concentrations of total amine in the ATU/ARU solvent (Section 7.10.2).
2.
The concentrations of H2S and CO2 in the ATU/ARU solvent (Sections 7.10.3 and 7.10.4).
3.
The foaming tendency of ATU/ARU solvent (Section 7.10.5).
4.
The H2S content of the ATU/ARU Amine Absorber overhead gas (Sections 7.10.6 and 7.10.7).
General Procedures for Analyzing ATU/ARU Solvent1,2 An amine solution which is to be analyzed should first be inspected visually. If conducted by an experienced person, such an inspection will often yield important clues to the identity of a number of contaminants. For example, a green color in an amine solution usually indicates finely divided iron sulfide in sub-colloidal particle size (<1 micron), whereas a finely divided black suspension indicates the presence of larger (>3 micron) iron sulfide particles. A green or blue solution can indicate the possibility of either copper or nickel, while an amber colored solution may contain suspended or dissolved iron oxide. Iron may complex with the amine an give the solution an amber or dark red color. Thermal degradation of the amine may give the solution a dark red to brown color. Amines sometimes display a red or dark brown color resulting from oxidation, particularly when combined with thermal degradation. An oil slick on the solution or an oil-like odor is indicative of hydrocarbon contamination. The presence of these contaminants, however, must be proven by analysis. The next step in analyzing an amine solution is the determination of the percent amine and the acid gas content (H2S and CO2). Both rich and lean solutions may be analyzed for these constituents, and from the analyses the extent of acid gas loading and efficiency of stripping can be ascertained. Procedures for these analyses are given in Sections 7.10.2 through 7.10.4 that follow.
1 2
The Dow Chemical Company, Gas Conditioning Fact Book, 1962, pp. 310-311. Dow Chemical U.S.A., Gas Treating from Dow, 1987, pp. 8-1-1 – 8-1-2.
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SULFUR BLOCK In addition to the procedure in Section 7.10.2, the amine concentration of the solvent can be determined by performing Kjeldahl and Van Slyke nitrogen analyses. The Kjeldahl determination indicates the total nitrogen content of the solution, including nitrogen from the amine and from amine degradation products. The Van Slyke method, on the other hand, shows amine content, but does not reveal the extent to which the original amine has been degraded or tied up as heat stable salts. The difference between the results obtained through Kjeldahl and Van Slyke analyses usually indicates the degree of amine degradation. As would be expected, little difference is obtained with initial or unused solution. These analyses are not commonly performed in plant laboratories, but are generally left to the chemical solvent supplier. Heat stable salts can also be determined by a total anion assay. The amine solution is passed through an ion exchange column containing ion exchange resin in the hydrogen form. Acid salts are thus broken down and the acids recovered in the column effluent, while the amine is absorbed in the column. The acid in the effluent is determined by potentiometric titration, and from these results plus the original amine concentration the amount of amine in the form of heat stable salts is calculated. Again, this type of analysis is commonly left for the chemical solvent supplier to perform. The foaming characteristics of an amine solution are determined empirically in a simple apparatus consisting of an air (or gas) supply, pressure regulator or gas manometer, graduated glass cylinder, and a gas dispersion tube. The amine solution is poured into the graduated cylinder and air passed through at a constant rate. After five minutes, the height of the foam is recorded, the air flow is interrupted, and the time for the foam to break is determined. The results thus obtained will indicate whether or not evaluation of anti-foam agents is desirable. Section 7.10.5 describes this procedure more completely. A water analysis can be conducted on the amine solution to obtain a material balance and serve as an approximate check on the amine concentration. This is typically determined using the Karl Fischer method of analysis, but most plant laboratories leave this procedure to the chemical solvent supplier. Ordinarily, the above analyses will provide an accurate picture of the condition of the amine plant solution. At times, however, unusual operational difficulties may be encountered in amine sweetening units
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SULFUR BLOCK because of contaminants which are not revealed by the usual analytical methods. When this occurs, infrared spectroscopic analysis may often be utilized to good advantage. Infrared spectroscopy is based on the principle that each molecule or functional group exhibits its own particular absorption characteristics when exposed to infrared light of a definite wavelength. A wide variety of functional groups can be readily detected and identified by infrared techniques. For example, it has been found that degraded or oxidized amine solutions may contain ammonia, formic acid, a di-functional acid, a carbonyl compound yielding a glyoxal dinitrophenylhydrazone derivative, and a high molecular weight material that exhibits the characteristics of a Jones polymer. Also, both mono- and di-substituted amines have been identified. Each component exhibits its own particular effects on corrosion, foaming, and acid gas absorption, effects which can be determined only by the separate evaluation of each contaminant. Once these effects are determined, a knowledge of functional groups present and their relative concentration makes it possible to anticipate which types of contaminants may be causing difficulties. The chemical solvent supplier can usually perform this type of analysis more easily than the plant laboratory. Steps should be taken to ensure that the amine solution samples taken are representative of the circulating solvent. Samples should be taken in glass or plastic containers. Metal containers will cause low results for H2S because sulfides will react with the metal walls of the container. Do not use copper tubing to withdraw the samples; the copper will contaminate the amine solution, and H2S will react with the copper and give low results. Special care should be exercised when taking samples of the rich amine solution to avoid personnel exposure to H2S. Hot, fully loaded amine solution can flash acid gas when released to atmospheric pressure, causing low acid gas loading results in addition to the dispersion of H2S to the surroundings. Take samples of the rich solution from the coolest point in the process (the Amine Absorber outlet, usually), and cool the samples in a stainless steel coil immersed in an ice bath or cold water to prevent flashing. The solution should be allowed to flow to a drain in this fashion for several minutes before taking the sample to be sure that circulating amine is being taken.
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SULFUR BLOCK In the laboratory procedures that follow, several different reagents are used that can be harmful if proper care is not exercised. Acids, bases, and flammable substances are utilized in these procedures, so adherence to proper laboratory safety practices is necessary to ensure the safety of all personnel.
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SULFUR BLOCK 7.10.2
Determination of Amine Concentration in ATU/ARU Solvent The amine concentration in the ATU/ARU solvent can be determined by acid titration of the lean solution. This technique is not specific for free amine, however, as amine present in the solution as an amine-acid salt will also react during the titration. This technique will also give erroneous results if there are other basic materials in the solution, such as caustic or soda ash (sometimes used to "neutralize" heat stable salts). 1.
Reagents:
2.
Procedure:
3.
Distilled or Deionized Water 0.5 N Hydrochloric Acid (HCl) Bromophenol Blue Indicator (3',3'',5',5''-tetrabromophenolsulfonephthalein)
a.
Place about 95 ml of distilled or deionized water in a 250 ml beaker or Erlenmeyer flask.
b.
Add about 5 ml of lean amine solution to the water in the beaker via pipette, recording the actual quantity.
c.
Add 5 drops of Bromophenol Blue indicator to the solution in the beaker and stir well.
d.
Titrate the solution in the beaker with 0.5 N HCl to a faint yellow color. Alternatively, if a pH meter is available, titrate to a pH of 4.5. Record the amount of HCl used in the titration.
Chemical reaction involved: R2HN + HCl
+
R2HNH + Cl
–
where R2HN = CH3-N-(CH2-CH2-OH)2 = MDEA (methyldiethanolamine) As the hydrochloric acid is added to the solution, it reacts with the amine to form a chloride salt. Once all the amine has reacted, the continued addition of acid causes the pH of the solution to drop, until the Bromophenol Blue indicator changes from blue to yellow. Note that HCl reacts with the amine on a 1:1 molar basis.
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 4.
Calculation of Weight Percent Amine:
ml HCl Normality of Amine 100% Used HCl Solution Weight % Mole Amine Weight 1000 ml / l ml of Sp. Gravity of Sample Amine Sample The molecular weight of MDEA is 119.17, and the specific gravity of the solution at room temperature (20°C) is about 1.059, assuming the solution is about 45 wt% MDEA. The equation can then be simplified to:
ml HCl Normality of Used HCl Solution Weight % Amine 11.253 ml of Sample
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 7.10.3
Determination of Total Acid Gas Loading in ATU/ARU Solvent The total acid gas (H2S + CO2) loading, relative to the amine concentration, in either the lean or rich ATU/ARU solvent can be determined by base titration of the solution. This procedure does not distinguish between H2S and CO2. However, together with the procedure in Section 7.10.4, the individual concentrations of H2S and CO2 can be determined. 1.
Reagents:
2.
Procedure:
3.
Methanol (CH3OH), Anhydrous 0.5 N Potassium Hydroxide (KOH) Solution in Methanol Thymolphthalein Indicator in Methanol
a.
Place about 125 ml of methanol in a 250 ml beaker or Erlenmeyer flask.
b.
If a pH meter is available, insert the pH meter probe into the methanol in the beaker and adjust the pH of the methanol to 11.2 by titrating the methanol in the beaker with the 0.5 N KOH.
c.
If a pH meter is not available, add 5 drops of Thymolphthalein indicator to the methanol in the beaker. Titrate the solution in the beaker with 0.5 N KOH until the solution turns a faint blue color, indicating a pH of 11.2. The change to faint blue will be sudden, so add the KOH slowly (one drop at a time).
d.
Add about 20 ml of lean amine solution to the methanol in the beaker via pipette, recording the actual quantity. If rich amine solution is being tested, use about 10 ml of solution instead.
e.
Titrate the solution in the beaker with 0.5 N KOH back to a pH of 11.2 (or until the solution again turns a faint blue color when using Thymolphthalein indicator). Record the amount of KOH used in this titration.
Chemical reactions involved: +
–
H2S + KOH
K + HS + H2O
CO2 + KOH
K + HCO3
+
–
As the potassium hydroxide is added to the solution, it reacts with the H2S and CO2 to form potassium hydrosulfide and potassium
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK hydrogen carbonate salts. Once all of the acid gas has reacted, the continued addition of base causes the pH of the solution to rise, until the Thymolphthalein indicator changes from colorless to blue. Note that KOH reacts with H2S and CO2 on a 1:1 molar basis. 4.
Calculation of Acid Gas Loading (molar basis): ml KOH Normality of Used KOH Solution Moles Acid Gas Amine 100% Mole Mole Amine Weight 1000 ml / l ml of S.G. of Wt % Amine Sample Sample in Solvent
Note that "ml KOH used" refers to the amount used in the second titration, step 2.e. The "wt % amine in solvent" can be determined using the procedure in Section 7.10.2. The molecular weight of MDEA is 119.17, and the specific gravity of the solution at room temperature (20°C) is about 1.059, assuming the solution is about 45 wt% MDEA. The equation can then be simplified to:
ml KOH Normality of Used KOH Solution Moles Acid Gas 11.253 ml of Wt % Amine Mole Amine Sample in Solvent 5.
Issued 30 August 2011
Special Considerations: a.
Excess moisture in the equipment will give false readings. Water may be used to clean the equipment if the equipment is thoroughly dried prior to use with the anhydrous methanol.
b.
The faint blue titration endpoint using Thymolphthalein indicator is not definite. It may best be determined by comparing the color of the solution against a reference prepared by titrating a second sample of methanol-Thymolphthalein to the same color.
c.
The KOH solution and Thymolphthalein indicator solution should be kept tightly closed to prevent loss of methanol by vaporization. Any vaporization of methanol from the KOH solution will change the normality of the solution.
d.
The Thymolphthalein indicator solution can be prepared by dissolving 5 grams of thymolphthalein in 100 ml of anhydrous methanol.
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 7.10.4
Determination of H2S and CO2 Loading in ATU/ARU Solvent The H2S loading, relative to the amine concentration, in either the lean or rich ATU/ARU solvent can be determined by titration of the solution with iodine. Since CO2 does not react with iodine, this procedure is specific for H2S. Together with the total acid gas loading determined using the procedure in Section 7.10.3, the individual concentrations of H2S and CO2 can be determined. 1.
Reagents:
Distilled or Deionized Water Concentrated Hydrochloric Acid (HCl) or Sulfuric Acid (H2SO4) Standard Starch Solution - 1% 0.1 N Iodine Solution (I2) 0.1 N Sodium Thiosulfate Solution (Na2S2O3)
2.
Issued 30 August 2011
Procedure: a.
Measure about 25 ml of chilled iodine solution and place it in a 250 ml beaker or Erlenmeyer flask. Record the amount of iodine solution used.
b.
Carefully add about 25 ml of concentrated acid to the beaker.
c.
Add about 5 ml of standard starch solution to the beaker, then re-chill the beaker in an ice batch for 2-3 minutes.
d.
Slowly add 10-20 ml of lean amine solution to the solution in the beaker via pipette, recording the actual quantity. If rich amine solution is being tested, use 1-2 ml of solution instead.
e.
Use about 25 ml of distilled or deionized water to rinse the inside of the beaker, then swirl the contents gently to mix the solution without splashing it.
f.
Titrate the excess iodine in the sample with the sodium thiosulfate solution until the blue color disappears. The end point is a pale yellow or clear color. The approach of the endpoint is usually indicated by a milky brown tint at the top of the liquid surface. As the endpoint nears, slow the rate of titration and use a small amount of distilled or deionized water to wash the flask. Record the amount of sodium thiosulfate solution used in this titration.
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK g.
3.
Check the pH of the titrated solution with pH paper to be sure the solution is acidic. If the solution is not acidic, repeat the procedure but use more acid in step 2.b.
Chemical reactions involved: H2S + I2
S + 2 HI
I2 + Na2S2O3
2 S + NaI + NaIO3
When the solvent is added to the iodine solution, the H2S in the solvent reacts with the iodine to form hydrogen iodide and elemental sulfur. The solution contains an excess of iodine to ensure that all of the H2S reacts. The iodine solution is chilled prior to adding the solvent to eliminate or minimize the evolution of H2S gas. Note that H2S reacts with iodine on a 1:1 molar basis. When the sodium thiosulfate solution is added to the solution, it reacts with the remaining iodine to form sodium iodide and sodium iodate, along with more elemental sulfur. (It is this elemental sulfur that may cause the titrated solution to appear pale yellow.) Once the last bit of iodine is consumed, the starch solution loses its characteristic blue color. The amount of H2S in the solvent sample is then calculated from the difference between the total iodine and the iodine that reacts with the sodium thiosulfate. Note that sodium thiosulfate reacts with iodine on a 1:1 molar basis. The purpose of the concentrated acid is to neutralize the amine so that it will release the H2S (a weaker acid) so it can react with the iodine. If the titrated solution is not acidic in step 2.g, then the amine was not fully neutralized and the H2S determination will not be correct. 4.
Calculation of H2S Loading (Molar Basis): g - moles ml I2 Normality of 1 liter 1 g - mole I2 Used used I2 Solution 1000 ml 2 g - equivalent
g - moles ml Normality of 1 liter 1 g - mole Na2S2O3 Na2S2O3 Na2S2O3 used Solution 1000 ml 2 g - equivalent Used
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK g - moles g - moles Amine I2 Used Na2S2O3 Used Moles H2S Mole 100 % Mole Amine Weight ml of S.G. of Wt % Amine Sample Sample in Solvent
The "wt % amine in solvent" can be determined using the procedure in Section 7.10.2. The molecular weight of MDEA is 119.17, and the specific gravity of the solution at room temperature (20°C) is about 1.059, assuming the solution is about 45 wt% MDEA. Using these values and substituting the first and second equations into the third, these equations can be simplified to: Normality Normality of ml I2 of I ml Na2S2O3 Na S O 2 2 3 2 Used Used Solution Solution Moles H2S 5.626 Mole Amine ml of Wt % Amine Sample in Solvent
5.
Calculation of CO2 Loading (Molar Basis): Using the total acid gas loading determined with the procedure in Section 7.10.3, the CO2 loading of the solvent is determined by difference:
Moles CO2 Moles Acid Gas Moles H2S Mole Amine Mole Amine Mole Amine 6.
Other Common Units: The loadings calculated above can be easily converted to other units commonly used within the industry:
Grains H2S Moles H2S Wt % Amine S.G. of 166.7 Gallon Solvent Mole Amine in Sample Sample Moles H2S Wt % Amine Wt % H2S 0.2858 in Sample Mole Amine
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK SCF CO2 Moles CO2 Wt % Amine S.G. of 0.2653 Gallon Solvent Mole Amine in Sample Sample
Moles CO2 Wt % Amine Wt % CO2 0.3693 in Sample Mole Amine Note that these conversions are specifically for MDEA. amines require different conversion factors.
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Amine Treating & Regeneration
Other
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 7.10.5
Determination of Foaming Tendency of ATU/ARU Solvent The procedure described in this section is an empirical method for measuring the foaming tendency of aqueous amine solvents, universally accepted within the industry. 1.
Principle: Air is bubbled through a solvent sample at a fixed rate for five minutes, at which time the foam height is measured. The air flow is stopped and the time for the foam to disappear is measured. The foam height and "break" time are indicative of how high the foaming tendency of the solvent is.
2.
Equipment:
3.
Procedure:
4.
1000 ml Graduated Cylinder Aquarium Air Pump (or laboratory air supply) with Bubble Stone Stop Watch (or regular watch with a second hand)
a.
Pour about 200 ml of the sample solution into the graduated cylinder and insert the bubble stone into the bottom of the cylinder.
b.
Record the level of sample in the cylinder (in ml).
c.
Start the air pump or air supply to agitate the sample with oil-free air at 4 liters per minute (0.2 Nm3/H).
d.
After five minutes, record the height of the foam in the cylinder (in ml). Then turn off the air supply and measure the time in seconds for the foam to "break". For consistency, foam "break" is defined as the first clear "fish eye" in the surface of the liquid in the cylinder.
Calculation: Foam Height = Height of Foam - Initial Height of Sample (in ml)
5.
Interpretation: Considerable experience with this test has shown that if the foam height exceeds 200 ml or the "break" time exceeds 5 seconds, the plant may be experiencing a foaming problem. The higher the foam
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK height and/or the longer it takes to "break", the more severe the problem. 6.
Issued 30 August 2011
Other Considerations: a.
A nitrogen cylinder with the pressure regulated to about 0.35 kg/cm2(g), equipped with a flow rotameter, may be used instead of air. Be sure to keep the tubing and fittings oil-free.
b.
This procedure can be used to evaluate the effects of anti-foam agents on the solvent. However, care must be exercised in cleaning the equipment between tests since a very small quantity of residual anti-foam agent will affect the test.
c.
Foaming is sometimes caused by contaminants in the solvent that can be removed by activated carbon treatment. The effect of activated carbon filtration can be evaluated by running foam tests on treated and untreated samples. The sample is treated by mixing it with a quantity of carbon (12-20 mesh) to remove the contaminant, then filtering the mixture through Whatman No. 41 filter paper.
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 7.10.6
H2S Conc. in Amine Absorber Ovhd by the Tutweiler Method The overhead gas from the Amine Absorber Overhead Knock-out Drum can be sampled from the sample connection near the sample line for the H2S analyzer. 1.
Using a 500 ml Tutweiler apparatus, sample and titrate the treated gas leaving the Amine Absorber Overhead Knock-out Drum as outlined in Section 7.10.1 of these guidelines.
2.
Chemical reaction involved: H2S + I2
2 HI + S
The hydrogen sulfide (H2S) is converted to small particles of elemental sulfur by the iodine during the shaking. Good shaking is required to get good contact between the hydrogen sulfide in the gas and the iodine in the liquid. When all of the hydrogen sulfide is converted, the excess iodine causes the characteristic blue color in the presence of starch. This is a universal test for starch. (Iodine causes a blue color when it contacts starchy foods, such as potato for example.) 5.
Calculation of Mole (or Volume) percent H2S (dry basis): ml Iodine Normality of 273 T 760 Mole % H2S Iodine Solution (11.85) Solution Used 289 P - V.P.
Where
T P
= =
sample temperature, °C atmospheric pressure at particular location, mm Hg
V.P
=
vapor pressure of water at sample temperature, mm Hg
The Normality of the standard iodine solution will be 0.1 N. The last three factors (which correct the actual H2S content to compensate for expansion due to temperature, pressure, and water content) can be combined and calculated as a function of temperature only. This has been done for the 500-ml gas sample and is included as the Tutweiler Factor Chart in Section 7.10.3 of these guidelines (Chart 2). Therefore, the equation above can be simplified to:
ml Iodine Normality Factor from PPM H2S 10,000 Solution of Iodine Tutweiler Used Solution Factor Chart
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 7.10.7
H2S Conc. in Amine Absorber Ovhd Using Gas Detector Tubes As an alternative to the traditional wet-chemistry method described in the preceding Section 7.10.6 for determining the concentration of H2S in the Amine Absorber overhead gas, gas detector tubes can be used to quickly and easily make this determination. Although the discussion that follows specifically addresses using gas detector tubes manufactured by Drägerwerk AG of West Germany, there may be suitable detector tubes available from other manufacturers. Dräger tubes can be purchased from most safety equipment supply companies. The following Dräger tubes can be used with this procedure:
7.10.7.1
H2S 5/b
Dräger Cat. No. CH 298 01
H2S 100/a
Dräger Cat. No. CH 291 01
Operating Principles
Dräger tubes and other gas detector tubes measure gas concentrations by using a sample pump to draw a specific volume of the gas to be sampled into a glass tube containing a suitable reagent. The gaseous compound of interest chemically reacts with the reagent to produce a color change. The length of the "stain" line is a direct function of the concentration of the compound in the sample gas. Some detector tubes are calibrated with measured lines to allow reading the concentration directly on the tube. Others, such as the two listed above, have reference marks on the tube that can be multiplied by a factor to compute the concentration. Dräger tubes are designed to be used with a Dräger Model 31 gas detector pump. This is a hand-operated bellows pump that will draw a 100 cc sample volume for each pump stroke. Some tubes are designed for a single sample stroke, while others may use 5, 10, or even 20 strokes. In some cases, a tube may be used for measuring different concentration ranges by using a different number of strokes. a.
Dräger Cat. No. CH 298 01, H2S 5/b This tube will measure H2S concentrations in the range of 50 PPM to 600 PPM when one sample stroke is used. If desired, the range can be reduced to 5 PPM to 60 PPM by using 10 sample strokes. Each tube contains a substrate of a white lead compound. When exposed to H2S, the lead
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK compound is converted to brown lead sulfide. The H2S concentration in PPM can be read directly from the marks on the tube according to the length of the brown stain when using 10 sample strokes. If only one sample stroke is used, the tube reading is multiplied by 10 to give the PPM of H2S. This lead sulfide reaction is not affected by any of the other compounds normally found in the overhead gas from the ATU/ARU Amine Absorber. b.
Dräger Cat. No. CH 291 01, H2S 100/a This tube will measure H2S concentrations in the range of 100 PPM to 2,000 PPM when one sample stroke is used. Each tube contains a substrate of a white lead compound. When exposed to H2S, the lead compound is converted to brown lead sulfide. The H2S concentration in PPM can be read directly from the marks on the tube according to the length of the brown stain. This lead sulfide reaction is not affected by any of the other compounds normally found in the overhead gas from the ATU/ARU Amine Absorber.
7.10.7.2
Sampling the Amine Absorber Overhead Gas
The overhead gas from the Amine Absorber Overhead Knock-out Drum can be sampled from the sample connection near the sample line for the H2/H2S analyzer.
Issued 30 August 2011
a.
Before beginning, check the Dräger pump for leaks by inserting an unopened tube into the pump and stroking the pump. Confirm that the bellows does not re-expand. If it does, either the pump or its seal around the tube is leaking, and the test results will not be accurate.
b.
Attach a short piece of rubber tubing to the process sample valve.
c.
Break off the tips at each end of a Dräger tube and insert it into the sample pump (with the arrow on the side of the tube pointing toward the pump).
d.
Purge the rubber tubing by venting gas to the atmosphere for a few seconds. Pinch the rubber tubing closed at the end, close the gas sample valve, slip the end of the rubber tubing onto the end of the Dräger tube, and reopen the sample valve. Amine Treating & Regeneration
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SULFUR BLOCK
7.10.7.3
e.
Stroke the sample pump one time (be sure to compress the bellows until reaching the stops) and allow the pump to draw the gas sample into the detector tube. The sample stroke is complete when the metal chain on the bellows is taut.
f.
Close the sample valve and remove the rubber tubing from the end of the Dräger tube and from the sample valve.
g.
Read the length of the brown stain using the marks on the tube and record the reading.
Calculations
Mole (or Volume) PPM H2S (wet basis):
1013 Stain Tube PPM H2S Length Factor Baro. Pres., mbar The last factor corrects the measurement for pressure effects when samples are taken at elevations above sea level. Note that the average barometric pressure at the compex is 14.7 PSIA = 1013 mbar. The "Tube Factor" depends on the type of Dräger tube used and the number of sample strokes:
Issued 30 August 2011
Dräger Tube
Catalog No.
Sample Strokes
Tube Factor
H2S 5/b H2S 5/b H2S 100/a
CH 298 01 CH 298 01 CH 291 01
1 10 1
10 1 1
Amine Treating & Regeneration
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SULFUR BLOCK
Table of Contents 8. SOUR WATER STRIPPING ......................................................................................... 8-1 8.1 PURPOSE OF SYSTEM ....................................................................................... 8-1 8.2 SAFETY ................................................................................................................. 8-1 8.3 PROCESS DESCRIPTION.................................................................................... 8-2 8.3.1 General ........................................................................................................... 8-2 8.3.2 Sour Water Collection..................................................................................... 8-2 8.3.3 Sour Water Stripping ...................................................................................... 8-3 8.4 EQUIPMENT DESCRIPTION ................................................................................ 8-5 8.4.1 Sour Water Stripper, A2-DA1520 ................................................................... 8-5 8.4.2 Sour Water Stripper Packing and Internals, A2-DB1520 ................................ 8-5 8.4.3 Stripper Trays, A2-DB1521 ............................................................................ 8-5 8.4.4 SWS Cross Exchanger, A2-EA1520 .............................................................. 8-5 8.4.5 Sour Water Stripper Reboiler, A2-EA1521 ..................................................... 8-6 8.4.6 SWS Quench Water Cooler, A2-EC1520 ....................................................... 8-6 8.4.7 SWS Bottoms Cooler, A2-EC1521 ................................................................. 8-6 8.4.8 Sour Water Flash Drum, A2-FA1520.............................................................. 8-6 8.4.9 SWS Skim Oil Sump, A2-FA1522 .................................................................. 8-7 8.4.10 SWS Skim Oil Pump Sump, A2-FA1523A/B .................................................. 8-7 8.4.11 Sour Water Tank, A2-FB1520 ........................................................................ 8-7 8.4.12 Sour Water Filter, A2-FD1520A/B .................................................................. 8-7 8.4.13 Sour Water Transfer Pump, A2-GA1520A/B .................................................. 8-7 8.4.14 SWS Feed Pump, A2-GA1521A/B ................................................................. 8-8 8.4.15 SWS Quench Water Pump, A2-GA1522A/B .................................................. 8-8 8.4.16 SWS Bottoms Pump, A2-GA1523A/B ............................................................ 8-8 8.4.17 SWS Skim Oil Pump, A2-GA1524A/B ............................................................ 8-8 8.5 INSTRUMENTATION AND CONTROL SYSTEMS ............................................... 8-9 8.5.1 SWS Shutdowns and Alarms ......................................................................... 8-9 8.6 PROCESS PRINCIPLES AND OPERATING TECHNIQUES ............................. 8-11 8.6.1 SWS Stripper Operation ............................................................................... 8-11 8.6.2 Quench Water Circulation ............................................................................ 8-12 8.6.3 pH Control .................................................................................................... 8-13 8.7 PRECOMMISSIONING PROCEDURES ............................................................. 8-14 8.7.1 Preliminary Check-out .................................................................................. 8-14 8.7.2 Washing the Sour Water System ................................................................. 8-15 8.8 STARTUP PROCEDURES.................................................................................. 8-19 8.8.1 Initial Startup of the SWS ............................................................................. 8-19 8.8.1.1 Initial Water Fill ...................................................................................... 8-19
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 8.8.1.2 Exporting Treated Water ....................................................................... 8-21 8.8.2 Normal Startup of the SWS .......................................................................... 8-23 8.8.2.1 Initial Water Fill ...................................................................................... 8-23 8.8.2.2 Exporting Treated Water ....................................................................... 8-26 8.9 SHUTDOWN PROCEDURES ............................................................................. 8-29 8.9.1 Planned Shutdown ....................................................................................... 8-29 8.9.2 Effects of Shutdowns and Outages in Other Systems.................................. 8-31 8.9.2.1 Steam System Outage .......................................................................... 8-31
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
8. SOUR WATER STRIPPING 8.1
Purpose of System The purpose of the Sour Water Stripping (SWS) system is to remove H2S and ammonia (NH3) from various sour water streams produced in the Sulfur Block and elsewhere in the aromatics complex. The resulting treated water (containing less than 20 PPMW of H2S and less than 20 PPMW of NH3) is returned to the aromatics complex for reuse elsewhere, while the SWS off-gas (NH3, H2S, and water vapor) is routed to the Sulfur Recovery Units (SRUs).
8.2
Safety
WARNING
ALL PIPING AND VESSELS INCLUDED IN THIS UNIT EITHER CONTAIN OR HAVE THE POTENTIAL FOR CONTAINING HAZARDOUS GASES THAT MAY CAUSE SERIOUS INJURY OR DEATH. THE TWO GASES THAT ARE MOST COMMON AND HAZARDOUS IN A TOXIC WAY ARE HYDROGEN SULFIDE AND AMMONIA. CLOSE ATTENTION SHOULD BE PAID TO THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES AS TO THE NATURE AND ABILITY OF THESE GASES TO CONTAMINATE OTHER ELEMENTS IN THIS UNIT. AN EMPLOYEE'S KNOWLEDGE OF THE HAZARDOUS CHEMICALS AND COMPOUNDS WITH WHICH HE WILL BE WORKING IS ONE OF THE MOST BASIC PREREQUISITES FOR HIS OWN SAFETY, THE SAFETY OF OTHERS, AND THE PROTECTION OF EQUIPMENT. ALL EMPLOYEES SHOULD REVIEW THE "GENERAL SAFETY" SECTION OCCASIONALLY TO REFRESH THEIR MEMORIES. NEW EMPLOYEES SHOULD STUDY IT UNTIL THE INFORMATION IS THOROUGHLY UNDERSTOOD. PEOPLE WHO HAVE NOT BEEN PROPERLY TRAINED SHOULD NOT BE ALLOWED TO OPERATE OR WORK IN AND AROUND THIS PLANT.
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
8.3
Process Description
8.3.1
General The Systems Diagram, Material Balance and Process Flow Diagram, Dwg. Nos. 507000-7000-01, and 507000-7000-05 through -06, are contained in the "Process Flow Diagrams" Section of the Basic Engineering Package. Please refer to these drawings to follow this description of the process. The Sour Water Stripping Unit (SWS) receives sour water streams containing ammonia (NH3) and hydrogen sulfide (H2S) from other units in the No. 2 Aromatics Complex. These sour water streams are combined with sour water produced in the Sulfur Block (predominately Sour Water from the ATU and excess quench water from the SWS) and steam stripped to remove essentially all of the NH3 and H2S from the water. The resulting treated water (containing less than 20 PPMW of H2S and less than 20 PPMW of NH3) is returned to the complex for reuse elsewhere, while the SWS off-gas (NH3, H2S, and water vapor) is routed to the SRUs.
8.3.2
Sour Water Collection Sour water from other units within the complex is combined with the sour water streams generated within the Sulfur Block and flows to the Sour Water Flash Drum, A2-FA1520, at 54°C [129°F]. This vessel is operated at low pressure (1.05 kg/cm2(g) [15 PSIG]) to maximize the vaporization and removal of any light hydrocarbons that may be entrained or dissolved in the sour water. Any flash gases are directed to the flare header for disposal. The flash drum is large enough to provide 30 minutes or more of residence time for the sour water. This allows time for any heavy hydrocarbons entrained in the water to separate as a second liquid phase that spills over the internal weir at the inlet end of the drum, collecting in the SWS Skim Oil Sump, A2-FA1522. The SWS Skim Oil, A2-GA1524A/B, sends the collected hydrocarbon to the Condensate Feed Tank on start/stop level control. After removal of any liquid hydrocarbon, the heavier water phase passes under the internal weir at the outlet end of the drum to be pumped to the Sour Water Tank, A2-FB1520, by the Sour Water Transfer Pump, A2-GA1520A/B, on level control. This tank is large enough to provide 3-4 days of residence time to allow "working off " an accumulation of sour
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SULFUR BLOCK water after an outage. The tank also provides time for mixing which minimizes Sour Water Stripper feed composition fluctuations due to the many sources of sour water in the complex.
8.3.3
Sour Water Stripping After residing in the Sour Water Tank for several days, the sour water is pumped by the SWS Feed Pump, A2-GA1521A/B, on flow control through the tube side of the SWS Cross Exchanger, A2-EA1520. The sour water is preheated to 100°C [211°F] by cooling the treated water before flowing to the Sour Water Stripper, A2-DA1520, to enter the column above the first valve tray, tray #2. Traditional reflux systems do not work well for strippers in this service because of the highly corrosion nature of concentrated NH3-H2S aqueous systems. For this reason, these systems often employ a direct-contact condenser instead, using a circulating stream of quench water to provide cooling for the upper section of the column. The Sour Water Stripper contains an upper section of packing to provide contact between the quench water and the stripped gases, and a lower section of valve trays to provide contact between the sour water and the stripping steam. The stripping section of the column contains 30 valve trays and one chimney draw tray. As the sour water flows down the column, the NH3 and H2S are stripped from the water by countercurrent contact with stripping steam rising upward. This stripping steam is generated in the Sour Water Stripper Reboiler, A2-EA1521, using LP (3.5 kg/cm2(g) [50 PSIG]) steam on flow control as the heat input. The stripping steam strips the NH3 and H2S from the water and carries it upward to the quench section of the column. The SWS Bottoms Pump, A2-GA1523A/B, pumps the treated water from the bottom of the column through the shell side of the SWS Cross Exchanger, cooling the treated water from 123°C [254°F] to 54°C [130°F] by countercurrent heat exchange with the cool sour water. The SWS Bottoms Cooler, A2-EC1521, provides final cooling to 49°C [120°F] before the treated water is returned to the complex for reuse elsewhere. The quench section of the column contains a packed bed and a chimney draw tray. As the stripping steam rises upward in this section, it is countercurrently contacted by the circulating quench water, cooling the off-gas to 85°C [185°F] as it condenses most of the steam. The chimney tray below the packed bed that collects the quench water leaving the
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SULFUR BLOCK bottom of the bed has overflow pipes to direct the condensed water onto the valve tray (tray #2) below. The quench water collecting on the chimney tray is pumped by the SWS Quench Water Pump, A2-GA1522A/B, to the SWS Quench Water Cooler, A2-EC1520, to cool the water from 99°C [210°F] to 66°C [150°F] to reject the heat removed from the stripping steam in the quench section of the column. The cooling rate is adjusted as necessary to control the column overhead temperature at 85°C [185°F]. This allows the NH3 and H2S stripped from the water to leave the column at 0.85 kg/cm2(g) [12 PSIG]and flow to the SRUs.
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SULFUR BLOCK
8.4
Equipment Description
8.4.1
Sour Water Stripper, A2-DA1520 The upper section of the Sour Water Stripper contains a chimney draw tray and a single bed of random packing to provide good contact between the circulating quench water and the stripped gases. The stripping section of the column contains 30 valve trays and one chimney draw tray. The valve trays provide good contact between the sour water and the reboiler vapors to strip H2S and NH3 from the water. A chimney tray is located below the bottom valve tray to gather all of the column liquids to feed the Sour Water Stripper Reboiler. The column section located below this chimney tray serves to separate the outlet steam and treated water from the reboiler.
8.4.2
Sour Water Stripper Packing and Internals, A2-DB1520 This bed of random packing provides good contact between the stripped gases entering below it and the quench fed above it inside the Sour Water Stripper. The packing has a bed limiter above it and rests on a bed support. The quench water is distributed over the packing by a distributor tray. The packing is aluminum; the other internals are 316L S.S.
8.4.3
Stripper Trays, A2-DB1521 These 1-pass valve trays provide good contact between the sour water fed above them and the reboiler vapors fed below them inside the Sour Water Stripper. The tray decks for Trays #1 and #2 are 316L S.S. with 316 S.S. valves and bolting. For the remaining trays, the tray decks are carbon steel and the valves are fabricated from 316 S.S. to resist corrosion and to prevent "sticking" to the tray decks. The bottom valve tray has a seal pan for its downcomer to maintain a liquid seal and prevent gas from blowing up the downcomer. The chimney tray gathers the tower liquids to feed the reboiler. The outlet from the reboiler reenters the column below the chimney tray, with the vapor produced by the reboiler flowing upward through the chimneys in order to reach the valve trays above.
8.4.4
SWS Cross Exchanger, A2-EA1520 This shell and tube exchanger conserves energy by providing heat exchange between the stripped sour water and the sour water feed
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SULFUR BLOCK stream, so that the hot water leaving the Sour Water Stripper can preheat the sour water before it feeds the Sour Water Stripper. This cross exchange saves reboiler duty by preheating the sour water, and reduces the load on the SWS Bottoms Cooler by partially cooling the hot stripped water.
8.4.5
Sour Water Stripper Reboiler, A2-EA1521 The Sour Water Stripper Reboiler is a fixed tubesheet shell and tube heat exchanger. The exchanger is arranged as once-through vertical thermosiphon reboiler, mounted on the side of the Sour Water Stripper. The static head of the water above the inlet nozzle on the lower channel provides the driving force to circulate the water through the tubes. LP steam on the shell of the exchanger heats the water inside the tubes, partially vaporizing it to create stripping steam to remove the H2S and the NH3 from the sour water flowing down the Sour Water Stripper.
8.4.6
SWS Quench Water Cooler, A2-EC1520 This forced-draft aerial exchanger is used to cool a circulating stream of quench water which enters above the packed section of the Sour Water Stripper and provides cooling for the upper section of the column. Fans are used to circulate air across the finned tubes to remove heat from the circulating quench water.
8.4.7
SWS Bottoms Cooler, A2-EC1521 This forced-draft aerial exchanger provides the final cooling of the stripped sour water stream leaving the bottom of the Sour Water Stripper. Fans are used to circulate air across the finned tubes to remove heat from the water.
8.4.8
Sour Water Flash Drum, A2-FA1520 This horizontal vessel allows for the removal of hydrocarbons that may be carried out of the various upstream processes with the sour water. The sour water enters the vessel through a slotted, vertical distributor. Any hydrocarbon that may be carried with the sour water from the upstream processes will accumulate in the center section of this vessel. When a sufficient amount of hydrocarbon has accumulated, the hydrocarbon will overflow the partition and flow into the hydrocarbon section. Lighter hydrocarbons are disengaged from the sour water and routed to the battery limits on pressure control. Hydrocarbon-free sour water then passes under another partition, at the opposite end of the vessel, and into
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SULFUR BLOCK the sour water outlet section, where the sour water is pumped to the Sour Water Tank.
8.4.9
SWS Skim Oil Sump, A2-FA1522 This horizontal vessel is located in a below-ground concrete vault. It collects the heavy hydrocarbons from the Sour Water Flash Tank. The collected hydrocarbon liquid is pumped back to the Condensate Feed Tank on stop/start level control.
8.4.10
SWS Skim Oil Pump Sump, A2-FA1523A/B These vertical vessels house the SWS Skim Oil pumps. Hydrocarbon liquids from the SWS Skim Oil Sump flow into this vessel and are pumped out by the SWS Skim Oil Pump.
8.4.11
Sour Water Tank, A2-FB1520 The Sour Water Tank is an above-ground vertical cylindrical tank with a floating roof. This tank is large enough to provide 2-3 days of residence time to allow "working off " an accumulation of sour water after an outage. It has two level transmitters to indicate the sour water level, with a low level alarm to alert the operators of a low level, and a low level shutdown which will shut down the SWS Feed Pump if the level in the tank drops too low. The tank also has multiple connections to the closed drain system which can be used to route hydrocarbons to the closed drain if a layer of hydrocarbon should form in the tank.
8.4.12
Sour Water Filter, A2-FD1520A/B These full-flow filters are designed to remove solid particles 5 microns and larger from the sour water, which will help prevent fouling of the downstream heat exchangers.
8.4.13
Sour Water Transfer Pump, A2-GA1520A/B These centrifugal pumps are used to transfer the sour water from the Sour Water Flash Drum to the Sour Water Tank. Each pump is designed for the total duty; the other pump is a 100% spare. These pumps are equipped with tandem seals to reduce the likelihood of releasing H2S to the surroundings.
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SULFUR BLOCK 8.4.14
SWS Feed Pump, A2-GA1521A/B These centrifugal pumps are used to send the sour water from the Sour Water Tank to the Sour Water Stripper. Each pump is designed for the total duty; the other pump is a 100% spare. These pumps are equipped with tandem seals to reduce the likelihood of releasing H2S to the surroundings.
8.4.15
SWS Quench Water Pump, A2-GA1522A/B These centrifugal pumps are used to circulate quench water to cool the stripped gases in the upper section of the Sour Water Stripper. Each pump is designed for the total duty; the other pump is a 100% spare. These pumps are equipped with tandem seals to reduce the likelihood of releasing H2S to the surroundings.
8.4.16
SWS Bottoms Pump, A2-GA1523A/B These centrifugal pumps are used to send the stripped water from the Sour Water Stripping Unit to the battery limits for use elsewhere in the complex. Each pump is designed for the total duty; the other pump is a 100% spare.
8.4.17
SWS Skim Oil Pump, A2-GA1524A/B These vertical sump-type pump is mounted in the SWS Skim Oil Pump Sump to transfer the recovered hydrocarbons back to the Condensate Feed Tank.
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SULFUR BLOCK
8.5
Instrumentation and Control Systems
8.5.1
SWS Shutdowns and Alarms There are several interlocks of significance in the SWS Unit that either generate an alarm or shut down an individual piece of equipment. These devices/interlocks and their effects are described in this section. a.
Sour Water Flash Drum Low-Low Level, A2-LT15209A/B/C The Sour Water Transfer Pump (A2-GA1520A/B) could be damaged if the pump loses suction because the level in the Sour Water Flash Drum drops too low. This device will protect the pump by stopping it before this can occur. The setpoint is 530 mm above the bottom of the vessel. Note that there are three independent transmitters and 2oo3 voting logic is used for the shutdown.
b.
Sour Water Tank Low-Low Level, A2-LT15218A/B/C The SWS Feed Pump (A2-GA1521A/B) could be damaged if the pump loses suction because the level in the Sour Water Tank drops too low. This device will protect the pump by stopping it before this can occur. The setpoint is 300 mm above the bottom of the vessel. Note that there are three independent transmitters and 2oo3 voting logic is used for the shutdown.
c.
SWS Bottoms Cooler Fan High Vibration, A2-WSH15234 Each fan on the SWS Bottoms Cooler (A2-EC1521) is provided with its own vibration switch. If the vibration sensed by the switch exceeds the preset level, the switch will trip to stop the associated fan and activate an alarm in the DCS.
d.
Sour Water Stripper Low-Low Level, A2-LT15247A/B/C The SWS Bottoms Pump (A2-GA1523A/B) could be damaged if the pump loses suction because the level in the Sour Water Stripper drops too low. This device will protect the pump by stopping it before this can occur. The setpoint is 300 mm above the bottom seam of the column. Note that there are three independent transmitters and 2oo3 voting logic is used for the shutdown.
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SULFUR BLOCK e.
SWS Quench Water Cooler Fan High Vibration, A2-WSH15263 Each fan on the SWS Quench Water Cooler (A2-EC1520) is provided with its own vibration switch. If the vibration sensed by the switch exceeds the preset level, the switch will trip to stop the associated fan and activate an alarm in the DCS.
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SULFUR BLOCK
8.6
Process Principles and Operating Techniques
8.6.1
SWS Stripper Operation The stripped water must be comparatively free of H2S and NH3 to assure attainment of the treated water specification. These contaminates are removed from the sour water in the Sour Water Stripper by stripping them out with steam. The stripping steam is produced by vaporizing some of the water in the in the Sour Water Stripper Reboiler, using LP (3.5-4.2 kg/cm2(g)) steam for the heat input. The steam rate to the reboiler (and, hence, the stripping rate) is controlled by the steam flow controller. Adjust this steam rate as needed to keep the H2S and NH3 in the treated water low, i.e., less than 20 PPMW of H2S and less than 20 PPMW of NH3.
CAUTION THE DESIGN STRIPPING STEAM RATE SHOWN ON THE PROCESS FLOW DIAGRAM SHOULD BE CLOSE TO OPTIMUM. ALTHOUGH IT MAY BE POSSIBLE TO REDUCE THIS SOMEWHAT WITHOUT GOING OUT OF COMPLIANCE, REDUCING THE STRIPPING STEAM RATE SIGNIFICANTLY CAN CAUSE THE CONCENTRATION OF H2S AND AMMONIA IN THE TREATED WATER TO EXCEED THE ALLOWABLE CONCENTRATION IN THE TREATED WATER SPECIFICATION. IF IT IS NECESSARY TO OPTIMIZE THE STEAM TO THE SOUR WATER STRIPPER REBOILER, REDUCE THE STEAM BY SMALL INCREMENTS AND CHECK THE CONCENTRATION OF AMMONIA AND H2S AFTER EACH CHANGE. DO NOT REDUCE THE STEAM FURTHER IF EITHER CONCENTRATION BEGINS TO RISE SIGNIFICANTLY.
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SULFUR BLOCK 8.6.2
Quench Water Circulation The operating conditions shown on the Process Flow Diagram for this system (in terms of the quench water circulation rate and water temperature) should generally be maintained. The quench water circulation rate is controlled by the quench water flow controller in the DCS, while the temperature is controlled by a temperature controller on the Sour Water Stripper overhead gas line adjusting the speed of one of the fans on the SWS Quench Water Cooler, A2-EC1520. In general, decreasing the quench water circulation rate will increase the quench water temperature upstream of the cooler (which increases the corrosion rate) and may increase the Sour Water Stripper Overhead temperature if the cooler cannot cool the quench water sufficiently. Care should be taken when reducing the quench water circulation rate to ensure that the corrosion rate in the quench water circulation loop does not become excessive. As the feed rate to the SWS Stripper decreases, the quench water circulation rate can decrease in proportion with the feed flow rate down to about 50% of design flow rate. Below this point, the quench water rate cannot be allowed to drop any further without risking poor performance in the packed section of the SWS Stripper due to uneven liquid distribution and wetting of the packing. At lower feed rates (below 50%) simply setting the quench water flow rate to the column at about 50% of design should maintain adequate performance. (It should be noted, however, that there is really no detrimental effect if the quench water circulation is simply left at the design value at all times. The only drawback is slightly higher power consumption by the pump and aerial cooler.) Increasing the quench water temperature will increase the overhead gas temperature and water content which increases the load on the downstream SRUs (since water is a product of the Claus reaction, higher water content in the SWS feed gas can negatively impact the recovery of in the SRUs). However, decreasing the quench water temperature (and correspondingly the overhead gas temperature) may lead operating issues including salt deposition and plugging in the downstream piping and equipment. Ammonium salts can form in the gas stream leaving the top of the Sour Water Stripper if the gas temperature falls below about 70°C. These salts can plug the mist eliminator in the top of the Sour Water Stripper as well as the downstream piping and equipment. In addition, decreasing the overhead gas temperature below about 82°C may prevent
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SULFUR BLOCK the ammonia from leaving the top of the column. Instead it may become “trapped” in the column where it will concentrate, or it may leave in the stripped water causing the treated water to exceed the specification for ammonia. The flow rate and temperatures shown on the Process Flow Diagram are usually a good compromise between minimizing corrosion, minimizing the load on the downstream SRUs, and minimizing operating issues within the SWS unit.
8.6.3
pH Control High pH water tends to hold H2S in solution and aids in releasing ammonia from sour water. Conversely, low pH water tends to hold ammonia in solution and improves the stripping of H2S. By injecting a small amount of caustic near the tower bottom, ammonia stripping in the bottom of the Sour Water Stripper can be improved while the H2S is still stripped in the upper part of the tower. Injection points for caustic addition have been supplied in the lower section of the Sour Water Stripper. In the event that the stripped water cannot meet the low ammonia specification, caustic can be added to the tower to increase the pH and improve the ammonia stripping in the tower. If caustic is added, injection control is critical to limit the pH of the stripped water to about 8.0.
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SULFUR BLOCK
8.7
Precommissioning Procedures Prior to the initial startup, there are a number of precommissioning activities that are necessary to ensure that the newly constructed plant is ready to be placed in service. The activities outlined below should serve as a guide, but there may be others required as a part of your normal plant procedures.
8.7.1
Preliminary Check-out Check all equipment to ensure that it is properly installed. This will probably require consulting Manufacturer's literature as well as construction drawings.
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A.
Check and lubricate all equipment, in accordance with the Manufacturer's recommendations.
B.
Check the rotation of the following pumps by "bumping" them: (1) (2)
Sour Water Transfer Pump. SWS Feed Pump
(3) (4) (5)
SWS Quench Water Pump SWS Bottoms Pump
SWS Skim Oil Pump
C.
Check the rotation of the fans on the SWS Quench Water Cooler and the SWS Bottoms Cooler, by operating each fan for a short period.
D.
Check all piping and equipment to be sure that all blinds have been removed and that no valves are vented to atmosphere.
E.
Place the Instrument Air System in service to all instruments and check the action of controllers and control valves.
F.
Check all relief valves to ensure that they are installed in the proper locations, the inlet and outlet block valves (if provided) are open, the bypass valves (if provided) are closed, and the relief valves are set for the correct relieving pressure.
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SULFUR BLOCK 8.7.2
Washing the Sour Water System The following procedure is intended to remove grease, rust, scale, dirt, and trash from the equipment and piping in the Sour Water Stripping system before it is placed in operation. Failure to clean the system properly prior to startup can lead to operating problems (heat exchanger fouling, rapid filter plugging, etc.). A.
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Place the following controllers in the DCS in "manual" with their outputs set as indicated: (1)
Set the output from the Sour Water Flash Drum level controller to 0% to fully close the Sour Water Flash Drum level control valve.
(2)
Set the output from the SWS Inlet flow controller to 100% to fully open the SWS Inlet flow control valve.
(3)
Set the output from the SWS level controller to 100% to fully open the level control valve.
(4)
Set the output from the Quench Water flow controller to 100% to fully open the Quench Water flow control valve.
(5)
Set the output from the SWS Stripper Reboiler steam flow controller to 0% to fully close the steam flow control valve.
(6)
Set the output from the SWS pressure controller to 0% to fully close the overhead pressure control valve to the SRUs.
B.
Place the other SWS pressure controller in "automatic" with a setpoint of 0.85 kg/cm2(g). This will open the pressure control valve to the flare if pressure builds in the Sour Water Stripper during this procedure.
C.
Verify that the bypass valve on the pressure control valve to the flare is closed. Open both of the isolation block valves at this control station.
D.
Place the H.P. Nitrogen supply to the Stripper overhead line in service and open the manual block valve. This will prevent a vacuum from forming in the Sour Water Stripper during this procedure.
E.
Set the Treated Water hand control in the DCS is to 0% output to fully open the automated valve in the Startup/Re-run line to the Sour
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SULFUR BLOCK Water Tank, and fully close the automated valve in the Treated Water line downstream of the SWS Bottoms Cooler. Visually confirm that these valves are properly positioned. F.
Verify that the manual block valve at the inlet to the Sour Water Tank is open.
G.
Verify that the manual block valve in the fill line for the Quench Water Loop is closed.
H.
Verify that the SWS Inlet flow control valve is fully open. Open both of its isolation block valves and its bypass valve.
I.
Verify that the SWS level control valve is fully open. Open both of its isolation block valves and its bypass valve.
J.
Verify that the Quench Water flow control valve is fully open. Open both of its isolation block valves and its bypass valve.
K.
Verify that the Sour Water Flash Drum level control valve is fully closed. (This will prevent water from entering the upstream equipment if the Sour Water Tank is accidentally over-filled.)
L.
The Sour Water Filters will not be used to filter solids during this time, but the filter vessels and their piping are to be flushed and cleaned. Remove the filter elements, then bolt-up the filters. Open the inlet and outlet block valves on the filters, and open the bypass valve around the filters.
M.
Use a temporary “jumper” to add cold condensate to the Sour Water Tank.
N.
Once there is an adequate level in the tank, open the suction valve on a SWS Feed Pump and use its drain valve to be sure the pump is flooded with water. Start the pump, then open its discharge valve. Watch the level in the Sour Water Tank as the pump fills the downstream piping and begins to fill the Sour Water Stripper. When the level drops to the low-low level shutdown it should shut down the pump. If it does not, stop the pump manually before it loses suction and correct the problem with the low level shutdown before proceeding.
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SULFUR BLOCK O.
Continue filling the Sour Water Tank with condensate and pumping the water to the Sour Water Stripper periodically, until the level in the Stripper is all the way to the top of its level gauge.
P.
Once there is an adequate level in the Stripper, open the suction valve on a SWS Bottoms Pump and use its drain valve to be sure the pump is flooded with water. Start the pump, then open its discharge valve. Watch the level in the Sour Water Stripper as the pump fills the downstream piping and begins to circulate back to the Sour Water Tank. When the level drops to the low-low level shutdown it should shut down the pump. If it does not, stop the pump manually before it loses suction and correct the problem with the low level shutdown before proceeding.
Q.
Once circulation is achieved and the level in the Sour Water Stripper is adequate (about halfway up in the level gauge), discontinue the addition of condensate.
R.
Circulate the water and blow down the low point drains until all of the drain water is clear. Add more condensate as necessary to maintain the level in the Sour Water Stripper. At some point during the washing procedure, the standby SWS Feed Pump and the standby SWS Bottoms pump should be placed in service while the other pumps are shut down. This will ensure cleaning out all pumps and their associated piping.
S.
When the drain water begins to clear, open the manual block valve in the Quench Water fill line, open the suction valve on a SWS Quench Water Pump and use its drain valve to be sure the pump is flooded with water. Start the pump, then open its discharge valve. Watch the level in the Sour Water Stripper as the pump fills the quench water circulation loop. Add additional condensate to the Sour Water Tank if necessary and pump the water to the Sour Water Stripper.
T.
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Once circulation is achieved in the Quench Water loop and the level in the Sour Water Stripper is adequate (about halfway up in the level gauge), discontinue the addition of condensate and close the manual block valve in the Quench Water fill line.
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SULFUR BLOCK U.
Circulate the water in the Quench Water loop and blow down the low point drains until all of the drain water is clear. At some point during the washing procedure, the standby SWS Quench Water Pump should be placed in service while the other pump is shut down. This will ensure cleaning out both pumps and their associated piping.
V.
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Once the drain water is clear in the main circulation loop and Quench Water loop, shutdown the pumps and completely drain the system. Drain the system as quickly as possible, so that the water velocity helps to flush the solids from all parts of the system.
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SULFUR BLOCK
8.8
Startup Procedures
8.8.1
Initial Startup of the SWS The SWS system should now be clean, ready to place in service. All that remains is to fill the system with water and establish the proper operating conditions.
8.8.1.1
Initial Water Fill A.
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Close the bypass valves around the following control stations: (1)
SWS Inlet flow control
(2)
SWS level control
(3)
Quench water flow control
B.
Close the inlet and outlet block valves (but leave the bypass valves open) on the Sour Water Filters, then install the proper elements in the filters. Leave the block valves closed on each filter for now.
C.
Use a temporary “jumper” to add cold condensate to the Sour Water Tank and reestablish the level in the Sour Water Stripper as before.
D.
Establish circulation of water in the system (including the Quench Water loop) using the procedures in Section 8.7.2.
E.
Start a fan on the SWS Bottoms Cooler and place the bottoms temperature controller in service with a setpoint of 60°C.
F.
Begin steam flow to the Sour Water Stripper Reboiler and gradually raise the temperature in the column. Place the steam flow controller in the DCS on "automatic" with its setpoint set to its normal value.
G.
Open the high point vent valve on the Stripper overhead line and allow the steam to purge any air from the vessel. As the pressure builds, the vent valve can be closed.
H.
When the temperature begins to rise in the SWS overhead line, start a fan on the SWS Quench Water Cooler and place the overhead temperature controller in service with a setpoint of 85°C.
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SULFUR BLOCK I.
Monitor the stripper pressure, and adjust the overhead pressure controller if necessary to maintain the stripper pressure at about 0.85 kg/cm2(g) as the system is heated to operating temperatures.
J.
Ensure that the fans are running on the SWS Bottoms Cooler and the SWS Quench Water Cooler.
K.
If the control loops for the Sour Water Stripper have not already been placed in service, do so at this time. Switch the SWS level controller, and the SWS Inlet flow controller in the DCS to "automatic" with their setpoints set to their normal values.
L.
Place the Quench Water flow controller in “automatic” and set its setpoint to its normal value.
M.
Place each of the sour water filters in service as follows: (1)
Open the vent valve on the top of the filter.
(2)
"Crack" the filter inlet block valve open slightly and allow the filter to fill with sour water. When the filter is full, close its vent valve.
(3)
Open the inlet and outlet block valves on the filter.
(4)
Slowly close the valve in the bypass line around the filter.
Note:
N.
At this point the sour water system is ready for service. It can remain in this operating mode indefinitely while the rest of the Complex is prepared for startup. Check the system periodically for indications of plugging, etc. (low flow, erratic pump discharge pressure, high filter pressure drop), as solid materials may accumulate at various points in the system over time.
Once there is an adequate level of Sour Water in the Sour Water Flash Drum, open the suction valve on a Sour Water Transfer Pump and use its drain valve to be sure the pump is flooded with water. Start the pump, then open its discharge valve. Watch the level in the Sour Flash Drum as the pump fills the downstream piping and begins to flow to the Sour Water Tank. When the level drops to the low-low level shutdown it should
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SULFUR BLOCK shut down the pump. If it does not, stop the pump manually before it loses suction and correct the problem with the low level shutdown before proceeding. O.
Place the Sour Water Flash Tank level controller in the DCS in “automatic” and set its setpoint to its normal value.
P.
Once a level of hydrocarbons has built up in the hydrocarbon side of the Sour Water Flash Tank, the oil level controller can also be placed “automatic” and its setpoint set to its normal value.
The sour water will continue to circulate from the Sour Water Tank to the Sour Water Stripper and back to the tank. The Sour Water Tank is large enough to provide 3-4 days of residence time for the produced sour water in the event the Sour Water System is not ready to export treated water at this time. 8.8.1.2
Exporting Treated Water Stripped sour water may not be routed to the complex’s treated water system until the temperature in the bottom of the Sour Water Stripper is high enough to satisfy the Stripped Water Low Temperature Interlock. This interlock disables the hand control in the DCS to prevent the operator from routing the stripped water to the complex’s treated water system until the temperature in the bottom of the Sour Water Stripper is sufficiently high. Once the temperature in the bottom of the Sour Water Stripper is high enough to satisfy the low-temperature interlock, and the complex is producing a sufficient quantity of sour water for processing:
Issued 30 August 2011
A.
Slowly increase the output from the Treated Water hand control to 100%, which will open the automated valve in the Treated Water line downstream of the SWS Bottoms Cooler and close the automated valve in the Startup/Re-run line to the Sour Water Tank.
B.
When the output of the Treated Water hand control reaches 100%, the automated valve in the Treated Water line downstream of the SWS Bottoms Cooler should be fully open and the automated valve in the Startup/Re-run line fully closed to send all of the treated water to the complex’s treated water Tailgas Cleanup
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SULFUR BLOCK system. Visually confirm that these valves are properly positioned. C.
Once the operation of the Sour Water Stripper has stabilized, route its acid gas, which is presently going to the flare through a pressure valve to the SRUs as follows: (1)
Confirm that the Sour Water Stripper pressure controller to the SRUs in the DCS is in "manual" with its output set to 0%.
(2)
Confirm that the setpoint of the Sour Water Stripper pressure controller to the SRUs is tracking its current reading, then place it in "automatic".
(3)
Slowly raise the setpoint of the Sour Water Stripper pressure controller to the flare to 1.0 kg/cm2(g).
(4)
If, necessary, adjust the setpoint of the Sour Water Stripper pressure controller to the SRU to its normal setpoint.
The Sour Water Stripper pressure controller will now take over control of the Sour Water Stripper pressure by opening the pressure valve to send the acid gas to the SWS Gas Knock-Out Drums in the SRUs. The Sour Water Stripper pressure controller to the flare will close the acid gas pressure valve and stop the flow of acid gas to the flare. If the SRUs shut down (or some other upset causes the Sour Water Stripper pressure to rise), the Sour Water Stripper pressure controller to the flare will act as an over-ride and divert the acid gas to the flare. D.
Issued 30 August 2011
The SWS is now fully on-stream. Before directing your attention away from the SWS, be sure that: (1)
All controllers are functioning properly.
(2)
The steam heating systems are in service and the level control on the Reboiler condensate pot is functioning properly.
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SULFUR BLOCK 8.8.2
Normal Startup of the SWS The procedure for startup of the SWS after it has been shut down will be very similar to the procedure for the initial startup, except that condensate will not be used to fill the system. For ease of reference, the steps to be performed are written in this Section to serve as a "check list" that can be easily followed on subsequent startups. Refer to the previous Sections for the reasons and details pertaining to the different steps performed. Prior to commencing SWS startup, check for the completion of all maintenance work (connecting lines, removing blinds, etc.) if such work was performed.
8.8.2.1
Issued 30 August 2011
Initial Water Fill A.
Confirm that the Treated Water hand control in the DCS is to 0% output to fully open the automated valve in the Startup/Rerun line to the Sour Water Tank, and fully close the automated valve in the Treated Water line downstream of the SWS Bottoms Cooler. Visually confirm that these valves are properly positioned.
B.
Place the following controllers in the DCS in "manual" with their outputs set as indicated: (1)
Set the output from the SWS Inlet flow controller to 100% to fully open the SWS Inlet flow control valve.
(2)
Set the output from the SWS level controller to 100% to fully open the level control valve.
(3)
Set the output from the Quench Water flow controller to 100% to fully open the Quench Water flow control valve.
C.
Confirm that the output from the SWS Stripper Reboiler steam flow controller is set to 0% and the steam flow control valve is fully closed.
D.
Confirm that the output from the SWS pressure controller is set to 0% and the overhead pressure control valve to the SRUs is fully closed.
E.
Place the other SWS pressure controller in "automatic" with a setpoint of 0.85 kg/cm2(g). This will open the pressure control
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SULFUR BLOCK valve to the flare if pressure builds in the Sour Water Stripper during this procedure. F.
Verify that the bypass valve on the pressure control valve to the flare is closed and that both of the isolation block valves are open.
G.
If not already in service, place the H.P. Nitrogen supply to the Stripper overhead line in service and open the manual block valve.
H.
Verify that the manual block valve at the inlet to the Sour Water Tank is open.
I.
Verify that the manual block valve in the fill line for the Quench Water loop is closed.
J.
If the Sour Water Flash Drum is already in service and sending sour water to the Sour Water Tank, proceed to Step L. Otherwise, if the Sour Water Flash Drum is not in service, open the isolation valves upstream of the flash drum to allow sour water to enter the flash drum from the upstream Units.
K.
Once there is an adequate level of sour water in the Sour Water Flash Drum, open the suction valve on a Sour Water Transfer Pump and use its drain valve to be sure the pump is flooded with water. Start the pump, then open its discharge valve. Watch the level in the Sour Flash Drum as the pump fills the downstream piping and begins to send sour water to the Sour Water Tank. When the level drops to the low-low level shutdown it should shut down the pump. If it does not, stop the pump manually before it loses suction and correct the problem with the low level shutdown before proceeding.
L.
Confirm that there is an adequate level of sour water in the Sour Water Tank, then open the suction valve on a SWS Feed Pump and use its drain valve to be sure the pump is flooded with water. Start the pump, then open its discharge valve. Watch the level in the Sour Water Tank as the pump fills the downstream piping and begins to fill the Sour Water Stripper.
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SULFUR BLOCK M.
Continue pumping sour water to the Sour Water Stripper until the level in the Stripper is all the way to the top of its level gauge.
N.
When there is an adequate level in the Stripper, open the suction valve on a SWS Bottoms Pump and use its drain valve to be sure the pump is flooded with water. Start the pump, then open its discharge valve to begin circulating sour water back to the Sour Water Tank.
O.
Once circulation is achieved and the level in the Sour Water Stripper is adequate, open the manual block valve in the Quench Water fill line, open the suction valve on a SWS Quench Water Pump and use its drain valve to be sure the pump is flooded with water. Start the pump, then open its discharge valve. Watch the level in the Sour Water Stripper as the pump fills the quench water circulation loop. If the level in the stripper falls below the low level alarm point, stop the SWS Quench Water Pump and pump additional sour water to the Stripper from the Sour Water Tank to bring the level in the level back up before restarting the SWS Quench Water Pump.
Issued 30 August 2011
P.
Once circulation is achieved in the Quench Water loop and the level in the Sour Water Stripper is adequate (about halfway up in the level gauge), close the manual block valve in the Quench Water fill line.
Q.
Start a fan on the SWS Bottoms Cooler and place the bottoms temperature controller in service with a setpoint of 60°C.
R.
Begin steam flow to the Sour Water Stripper Reboiler and gradually raise the temperature in the column. Place the steam flow controller in the DCS on "automatic" with its setpoint set to its normal value.
S.
When the temperature begins to rise in the SWS overhead line, start a fan on the SWS Quench Water Cooler and place the overhead temperature controller in service with a setpoint of 85°C.
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SULFUR BLOCK T.
Monitor the stripper pressure, and adjust the overhead pressure controller if necessary to maintain the stripper pressure at about 0.85 kg/cm2(g) as the system is heated to operating temperatures.
U.
Ensure that the fans are running on the SWS Bottoms Cooler and the SWS Quench Water Cooler.
V.
If the control loops for the Sour Water Stripper have not already been placed in service, do so at this time. Switch the Sour Water Flash Tank level controllers, the SWS level controller, and the SWS Inlet flow controller in the DCS to "automatic" with their setpoints set to their normal values.
W.
Place the Quench Water flow controller in “automatic” and set its setpoint to its normal value.
The sour water will continue to circulate from the Sour Water Tank to the Sour Water Stripper and back to the tank. The Sour Water Tank is large enough to provide 3-4 days of residence time for the produced sour water in the event the Sour Water System is not ready to export treated water at this time. 8.8.2.2
Exporting Treated Water Stripped sour water may not be routed to the complex’s treated water system until the temperature in the bottom of the Sour Water Stripper is high enough to satisfy the Stripped Water Low Temperature Interlock. This interlock disables the hand control in the DCS to prevent the operator from routing the stripped water to the complex’s treated water system until the temperature in the bottom of the Sour Water Stripper is sufficiently high. Once the temperature in the bottom of the Sour Water Stripper is high enough to satisfy the low-temperature interlock, and the complex is producing a sufficient quantity of sour water for processing: A.
Issued 30 August 2011
Slowly increase the output from the Treated Water hand control to 100%, which will open the automated valve in the Treated Water line downstream of the SWS Bottoms Cooler and close the automated valve in the Startup/Re-run line to the Sour Water Tank.
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SULFUR BLOCK B.
When the output of the Treated Water hand control reaches 100%, the automated valve in the Treated Water line downstream of the SWS Bottoms Cooler should be fully open and the automated valve in the Startup/Re-run line fully closed to send all of the treated water to the complex’s treated water system. Visually confirm that these valves are properly positioned.
C.
Once the operation of the Sour Water Stripper has stabilized, route its acid gas, which is presently going to the flare through a pressure valve to the SRUs as follows: (1)
Confirm that the Sour Water Stripper pressure controller to the SRUs in the DCS is in "manual" with its output set to 0%.
(2)
Confirm that the setpoint of the Sour Water Stripper pressure controller to the SRUs is tracking its current reading, then place it in "automatic".
(3)
Slowly raise the setpoint of the Sour Water Stripper pressure controller to the flare to 1.0 kg/cm2(g).
(4)
If, necessary, adjust the setpoint of the Sour Water Stripper pressure controller to the SRU to its normal setpoint.
The Sour Water Stripper pressure controller will now take over control of the Sour Water Stripper pressure by opening the pressure valve to send the acid gas to the SWS Gas Knock-Out Drums in the SRUs. The Sour Water Stripper pressure controller to the flare will close the acid gas pressure valve and stop the flow of acid gas to the flare. If the SRUs shut down (or some other upset causes the Sour Water Stripper pressure to rise), the Sour Water Stripper pressure controller to the flare will act as an over-ride and divert the acid gas to the flare. D.
The SWS is now fully on-stream. Before directing your attention away from the SWS, be sure that: (1)
Issued 30 August 2011
All controllers are functioning properly.
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SULFUR BLOCK (2)
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The steam heating systems are in service and the level control on the Reboiler condensate pot is functioning properly.
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SULFUR BLOCK
8.9
Shutdown Procedures Typical shutdown procedures for the Sour Water Stripping Unit are outlined and discussed in the sections that follow for the more common cases. Your existing company procedures and common sense operational judgment should be used to modify these procedures as needed to serve the purpose of any given planned shutdown situation.
8.9.1
Planned Shutdown Any equipment to be opened should be properly blinded and purged with inert gas before admission of air, to avoid exposure to potentially toxic gases or the formation of flammable vapor mixtures. To shut the SWS down in a controlled fashion proceed as follows:
Issued 30 August 2011
A.
Slowly reduce the output from the Treated Water hand control in the DCS is to 0% output to fully open the automated valve in the Startup/Re-run line to the Sour Water Tank, and fully close the automated valve in the Treated Water line downstream of the SWS Bottoms Cooler. Visually confirm that these valves are properly positioned.
B.
Place the stream flow controller in manual and set its output to 0% to close the stream flow control valve and stop the steam flow to the Sour Water Stripper Reboiler.
C.
Continue to circulate the sour water and operate the SWS Bottoms Cooler and the SWS Quench Water Cooler until the sour water is cool.
D.
Once the sour water is cool, shut down the SWS Feed Pump to stop the flow of sour water to the Sour Water Stripper and close the block valves in the pump suction lines.
E.
Place the SWS flow controller in the DCS in "manual" and set its output to 0% to fully close the sour water inlet flow control valve.
F.
Shutdown the SWS Quench Water Pumps and shut down the fans on the SWS Quench Water Cooler.
G.
Place the quench water flow controller in the DCS in "manual" and set its output to 0% to fully close the quench water flow control valve.
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SULFUR BLOCK
Issued 30 August 2011
H.
Use the SWS Bottoms pump to pump the sour water from the Sour Water Stripper to the Sour Water Tank until the low-low level shutdown is activated. This should shut down the SWS Bottoms Pump. Monitor the level in the Sour Water Stripper and be prepared to shut down the pump if the low-low level shutdown fails to activate.
I.
Place the SWS level controller in the DCS in "manual" and set its output to 0% to fully close the SWS level control valve.
J.
Shut down the fans on the SWS Bottoms Cooler
K.
Drain the remaining sour water in the SWS equipment to the Closed Drain System.
L.
Verify that the SWS level control valve is fully closed. Close both of its isolation block valves and its bypass valve.
M.
Verify that the SWS flow control valve is fully closed. Close both of its isolation block valves and its bypass valve.
N.
Verify that the quench water flow control valve is fully closed. Close both of its isolation block valves and its bypass valve.
O.
The SWS is now ready to be isolated and made safe for entry.
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SULFUR BLOCK 8.9.2
Effects of Shutdowns and Outages in Other Systems The SWS system is directly affected by a shutdown and/or outage in the LP steam system for the complex. These effects are described below.
8.9.2.1
Steam System Outage The most immediate impact on the SWS will be the loss of LP steam to the Stripper Reboiler if the steam outage lasts long enough. As the heat input to the reboiler declines, stripping of the acid gas from the sour water will decline and the H2S and NH3 in the treated water leaving the Sour Water Stripper will begin to increase. If this happens, use the Treated Water hand control in the DCS to route the treated water back to the Sour Water Tank until the LP steam system can be brought back on-line.
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SULFUR BLOCK
Table of Contents 9. SULFUR RECOVERY .................................................................................................. 9-4 9.1 PURPOSE OF SYSTEM ....................................................................................... 9-4 9.2 SAFETY ................................................................................................................. 9-4 9.3 PROCESS DESCRIPTION.................................................................................... 9-5 9.3.1 Overview......................................................................................................... 9-5 9.3.2 General ........................................................................................................... 9-6 9.3.3 Feed Gas Processing ..................................................................................... 9-6 9.3.4 Thermal Processing........................................................................................ 9-7 9.3.5 Catalytic Processing ....................................................................................... 9-8 9.3.6 Air Control System.......................................................................................... 9-9 9.3.7 Molten Sulfur Handling ................................................................................. 9-10 9.3.8 Steam Production ......................................................................................... 9-10 9.4 EQUIPMENT DESCRIPTION .............................................................................. 9-11 9.4.1 Reactor Furnace, A2-BA1530 (A2-BA1540) ................................................. 9-11 9.4.2 Acid Gas Burner Assembly, A2-BA1531 (A2-BA1541) ................................ 9-12 9.4.3 Acid Gas Knock-Out Drum, A2-FA1530 (A2-FA1540) ................................. 9-12 9.4.4 SWS Gas Knock-Out Drum, A2-FA1531 (A2-FA1541) ................................ 9-12 9.4.5 Reactor, A2-DC1530 (A2-DC1540) .............................................................. 9-13 9.4.6 Catalyst for Sulfur Plant Reactors, A2-MC1530 (A2-MC1540) ..................... 9-13 9.4.7 Acid Gas Preheater, A2-EA1530 (A2-EA1540) ............................................ 9-13 9.4.8 Sulfur Condenser, A2-EA1531 (A2-EA1541) ............................................... 9-13 9.4.9 Reactor No. 1 Feed Heater, A2-EA1532 (A2-EA1542) ................................ 9-14 9.4.10 Reactor No. 2 Feed Heater, A2-EA1533 (A2-EA1543) ................................ 9-14 9.4.11 Reactor No. 3 Feed Heater, A2-EA1534 (A2-EA1544) ................................ 9-15 9.4.12 Sulfur Surge Tank, A2-FB1530 (A2-FB1540) ............................................... 9-15 9.4.13 Acid Gas Knock-Out Drum Pump, A2-GA1530A/B (A2-GA1540A/B) .......... 9-16 9.4.14 SWS Gas Knock-Out Drum Pump, A2-GA1531A/B (A2-GA1541A/B) ......... 9-17 9.4.15 Sulfur Storage Tank Vent Ejector, A2-EE1530 (A2-EE1540) ....................... 9-17 9.4.16 Process Air Blower, A2-GB1530A/B (A2-GB1540A/B)................................. 9-18 9.4.17 Air Blower Suction Screen/Silencer, A2-FD1530A/B (A2-FD1540A/B) ........ 9-19 9.4.18 Process Air Vent Silencer, A2-FG1530A/B (A2-FG1540A/B) ....................... 9-19 9.4.19 Sulfur Drain Seal Assembly, A2-ME1530A-D (A2-ME1540A-D) .................. 9-19 9.4.20 Refractory for Reactor Furnace and Waste Heat Boiler, A2-MR1530 (A2-MR1540) .............................................................................................................. 9-20 9.4.21 Ceramic Ferrules for Waste Heat Boiler, A2-MR1532 (A2-MR1542) ........... 9-20 9.4.22 Refractory for Waste Heat Boiler, A2-MR1533 (A2-MR1543) ...................... 9-20 9.4.23 Refractory for Sulfur Condenser, A2-MR1534 (A2-MR1544) ....................... 9-20
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SULFUR BLOCK 9.4.24 Refractory for Reactor, A2-MR1535 (A2-MR1545) ...................................... 9-21 9.4.25 Rainshield for Reactor Furnace, A2-ME1531 (A2-ME1541) ........................ 9-21 9.4.26 Ceramic Ferrule for Reactor Furnace, A2-MR1531 (A2-MR1541) ............... 9-21 9.4.27 Waste Heat Boiler, A2-BF1530 (A2-BF1540) ............................................... 9-22 9.5 INSTRUMENTATION AND CONTROL SYSTEMS ............................................. 9-24 9.5.1 SRU Air:Acid Gas Ratio Control Loop .......................................................... 9-24 9.5.2 Acid Gas Burner Management System ........................................................ 9-30 9.5.3 Process Air Blower Controls ......................................................................... 9-34 9.5.4 Reactor Furnace Temperature Control......................................................... 9-39 9.5.5 Knock-Out Drum Pump Control .................................................................... 9-41 9.5.6 "Ride-Through" System Considerations ....................................................... 9-41 9.5.7 Boiler Low-Low Level S/D Transmitter Testing ............................................ 9-44 9.5.8 SRU Emergency Shutdown Systems ........................................................... 9-46 9.6 PROCESS PRINCIPLES AND OPERATING TECHNIQUES ............................. 9-56 9.6.1 Equipment Damage ...................................................................................... 9-56 9.6.2 Cold Catalyst Bed Startup ............................................................................ 9-58 9.6.3 Sulfur Solidification ....................................................................................... 9-60 9.6.4 Ammonia Salt Formation .............................................................................. 9-61 9.6.5 Catalyst Fouling ............................................................................................ 9-62 9.6.6 Operation of SRUs in Parallel....................................................................... 9-62 9.6.7 Process air Blower Operation ....................................................................... 9-65 9.6.8 Reactor Furnace Temperature ..................................................................... 9-70 9.6.9 Ammonia Destruction Considerations .......................................................... 9-73 9.6.10 Sulfur Recovery Efficiency............................................................................ 9-76 9.6.11 Operation at Low Flow Rates ....................................................................... 9-78 9.6.12 Pressure Drop Surveys ................................................................................ 9-82 9.6.13 Boiler Water Treatment ................................................................................ 9-84 9.7 PRECOMMISSIONING PROCEDURES ............................................................. 9-86 9.7.1 Preliminary Check-out .................................................................................. 9-86 9.7.2 Shutdown System Check-out ....................................................................... 9-87 9.7.3 Leak Testing the Process Piping and Equipment ......................................... 9-88 9.7.4 Purging the Inlet Knock-Out Drums .............................................................. 9-93 9.7.5 Commissioning Fuel Gas and Instrument Air to the Process ....................... 9-95 9.7.6 Commissioning Nitrogen to the Process ...................................................... 9-99 9.7.7 Commissioning the Sulfur Surge Tank Heating and Ventilation ................. 9-102 9.7.8 Pre-filling the Sulfur Drain Seal Assemblies ............................................... 9-104 9.8 STARTUP PROCEDURES................................................................................ 9-105 9.8.1 Initial Firing / Refractory Cure-out............................................................... 9-105 9.8.2 Amine Acid Gas Flow ................................................................................. 9-117 9.8.3 SWS Gas Flow ........................................................................................... 9-124 Issued 30 August 2011
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SULFUR BLOCK 9.8.4 Routing SRU Tailgas to the TGCU ............................................................. 9-127 9.8.5 Normal Startup - Cold System .................................................................... 9-129 9.8.6 Normal Startup - Hot System...................................................................... 9-146 9.8.7 Firing Supplemental Fuel Gas .................................................................... 9-158 9.9 SHUTDOWN PROCEDURES ........................................................................... 9-164 9.9.1 Planned Shutdown - No Reactor Entry....................................................... 9-165 9.9.2 Planned Shutdown for Reactor Entry ......................................................... 9-170 9.9.3 Shutting Down When Boiler Tubes Are Leaking ........................................ 9-180 9.9.4 Emergency Shutdown ................................................................................ 9-181 9.9.5 Effects of Shutdowns and Outages in Other Systems................................ 9-183 9.10 ANALYTICAL PROCEDURES .......................................................................... 9-187 9.10.1 Procedure for Sampling and Titrating with a Tutweiler Apparatus ............. 9-187 9.10.2 H2S Concentration in Acid Gas by the Tutweiler Method ........................... 9-189 9.10.3 H2S and SO2 Concentration in Tailgas by the Tutweiler Method ................ 9-192 9.10.4 Tailgas Analysis Table................................................................................ 9-196 9.10.5 Tailgas Analysis Operating Chart ............................................................... 9-197 9.10.6 Essential Apparatus for Tutweiler Analysis ................................................ 9-199 9.10.7 Materials for Tutweiler Analysis .................................................................. 9-200 9.10.8 H2S and SO2 Conc. in Tailgas Using Gas Detector Tubes ......................... 9-200 9.11 ADJUSTING STACKMATCH® IGNITOR/PILOTS ............................................. 9-205
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SULFUR BLOCK
9. SULFUR RECOVERY 9.1
Purpose of System The purpose of the Sulfur Recovery Units (SRUs) is to dispose of H2S-laden acid gas. This gas is produced by the new Amine Regeneration Unit and Sour Water Stripping Unit. Acid gases of this type are not allowed into the atmosphere, as they are highly toxic. If burned in a flare system, the pollutants would exceed emission standards. Each Sulfur Recovery Unit can take enough H2S out of the acid gas so that the remaining tailgas can be processed in a Tailgas Cleanup Unit to meet the emission standards after incineration. Also, the byproduct of pure sulfur is a marketable product.
9.2
Safety WARNING ALL PIPING AND VESSELS INCLUDED IN THIS UNIT EITHER CONTAIN OR HAVE THE POTENTIAL FOR CONTAINING HAZARDOUS GASES THAT MAY CAUSE SERIOUS INJURY OR DEATH. THE TWO GASES THAT ARE MOST COMMON AND HAZARDOUS IN A TOXIC WAY ARE HYDROGEN SULFIDE AND WARNING SULFUR DIOXIDE. CLOSE ATTENTION SHOULD BE PAID TO THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES AS TO THE NATURE AND ABILITY OF THESE GASES TO CONTAMINATE OTHER ELEMENTS IN THIS UNIT. AN EMPLOYEE'S KNOWLEDGE OF THE HAZARDOUS CHEMICALS AND COMPOUNDS WITH WHICH HE WILL BE WORKING IS ONE OF THE MOST BASIC PREREQUISITES FOR HIS OWN SAFETY, THE SAFETY WARNING OF OTHERS, AND THE PROTECTION OF EQUIPMENT. ALL EMPLOYEES SHOULD REVIEW THE "GENERAL SAFETY" SECTION OCCASIONALLY TO REFRESH THEIR MEMORIES. NEW EMPLOYEES SHOULD STUDY IT UNTIL THE INFORMATION IS THOROUGHLY UNDERSTOOD. PEOPLE WHO HAVE NOT BEEN PROPERLY TRAINED SHOULD NOT BE ALLOWED TO OPERATE OR WORK IN AND AROUND THIS PLANT.
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SULFUR BLOCK
9.3
Process Description
9.3.1
Overview The Systems Diagram, Material Balance and Process Flow Diagrams, Dwg. Nos. 507000-7000-01, and 507000-7000-07 through -09, are contained in the "Process Flow Diagrams" Section of the Basic Engineering Package. Please refer to these drawings to follow this description of the process. The new Sulfur Recovery Units, consisting of SRU Train 1 and SRU Train 2, are designed to operate in parallel and recover elemental sulfur from the off-gases produced by the new Amine Regeneration and Sour Water Stripper Units. It is intended that the Sulfur Recovery Facility convert and recover 99.9% or more of the hydrogen sulfide (H2S) contained in the feed streams as elemental sulfur in compliance with environmental requirements. The acid gases produced by the new Amine Regeneration Unit (ARU) and the new Sour Water Stripping Unit (SWS) are routed to two parallel Claus Sulfur Recovery Units (SRUs) using technology licensed from BP Amoco Corporation. The H2S is converted into molten elemental sulfur and routed to the common Sulfur Degassing Unit (SDU) that uses technology licensed from BP Amoco Corporation to reduce the H2S content of the sulfur to less than 10 PPMW. The combined tailgas from the sulfur plants is processed in a Tailgas Cleanup Unit (TGCU) using the Shell Claus Off-gas Treating (TGCU) process licensed by Shell Global Solutions (US) Inc. to produce an acid gas stream that is recycled back to the Claus plant so that the overall sulfur recovery is 99.9 wt. % or better. The effluent gas from the TGCU is thermally incinerated in a Tailgas Thermal Oxidation Unit (TTO) to convert all of the remaining sulfur compounds into sulfur dioxide (SO2) before dispersion of the gas to the atmosphere. Due to the sulfur removal by the TGCU process, the incinerated effluent gas will contain less than 200 PPMV of SO2 on a dry, 0% oxygen basis. The two process trains are identical, so all of the information that follows applies to both trains. Where references to equipment or instrument tag numbers are given, the SRU Train 1 tag number is given first followed by the SRU Train 1 tag number in parentheses.
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SULFUR BLOCK 9.3.2
General Each sulfur plant processes 1,181 Nm3/H of acid gas from the Amine Regeneration Unit and 33 Nm3/H of off-gas from Sour Water Stripping (SWS) Unit, plus 50% of the recycle acid gas from the Tailgas Cleanup Unit. Each sulfur plant will recover 94-96% of the sulfur contained in the total acid gas feed as elemental sulfur, producing about 34.6 MT/D of molten sulfur product. The tailgas leaving each sulfur plant is routed to the common TGCU. Each sulfur plant uses the modified straight-through Claus process licensed from BP Amoco Corporation, with a number of special design features to accomplish the required recovery performance while providing exceptionally good on-stream reliability and ease of operation. The Claus process utilizes the following chemical reactions to convert hydrogen sulfide to elemental sulfur: (1)
H2S + 3/2 O2
SO2 + H2O
(2)
2 H2S + SO2
3/n Sn + 2 H2O
The overall reaction for the process is: (3)
3 H2S + 3/2 O2
3/n Sn + 3 H2O
The sulfur plant contains one non-catalytic conversion stage and three catalytic conversion stages in series. The Claus reaction is highly exothermic, releasing a great deal of heat energy that is recovered as HP and LP steam in heat exchangers following the conversion stages.
9.3.3
Feed Gas Processing Acid gas from the Amine Regeneration Unit is combined with the recycle acid gas from the Tailgas Cleanup Unit and is routed to the Acid Gas Knock-Out Drum, A2-FA1530 (A2-FA1540), at 49°C [120°F] and Entrained liquids are separated and 0.74 kg/cm2(g) [10.5 PSIG]. automatically routed back to the Rich Amine Flash Drum by Acid Gas Knock-Out Drum Pump, A2-GA1530A/B (A2-GA1540A/B), on start/stop level control. The scrubbed acid gas stream flows through the Acid Gas Preheater, A2-EA1530 (A2-EA1540), where a portion of the LP (4.2 kg/cm2(g) [60 PSIG]) steam generated elsewhere in the SRU heats the acid gas to 126°C [259°F]. Preheating the amine acid gas allows it to be mixed with the SWS gas without causing ammonium salt precipitation. The preheater is also an energy conservation device, as preheating with
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SULFUR BLOCK LP steam allows more HP (48.5 kg/cm2(g) [690 PSIG]) steam to be produced in the sulfur plant. SWS gas from the Sour Water Stripping Unit is routed to the SWS Gas knock-Out Drum, A2-FA1531 (A2-FA1541), at 85°C [185°F] and 0.70 kg/cm2(g) [10.0 PSIG]. Entrained liquids are separated and automatically routed back to the Sour Water Flash Drum by the SWS Gas Knock-Out Drum Pump, A2-GA1531A/B (A2-GA1541A/B), on start/stop level control. The scrubbed SWS gas mixes with the majority of the preheated amine acid gas and flows to the Acid Gas Burner, A2-BA1531 (A2-BA1541). The remainder of the amine acid gas is routed into the sides of the Reactor Furnace, A2-BA1530 (A2-BA1540), on flow ratio control to ensure proper destruction of the ammonia in the first zone of the furnace as described below.
9.3.4
Thermal Processing One-third of the hydrogen sulfide in the feed stream must be converted to sulfur dioxide before the Claus reaction (2) can be utilized to produce elemental sulfur. Accordingly, the acid gas feed stream flows to the Acid Gas Burner to be combusted with air provided by the Process Air Blower, A2-GB1530A/B (A2-GB1540A/B). The amount of air is controlled to combust one-third of the hydrogen sulfide to sulfur dioxide via reaction (1). Sufficient air is also provided to combust the ammonia and hydrocarbons entering with the acid gas. The combustion products pass into the first combustion zone of the Reactor Furnace, which provides the necessary residence time to allow these reactions to reach equilibrium. At 1370°C [2500°F] or above (with the proper residence time), ammonia is almost completely destructed to nitrogen and water. The first combustion zone is controlled at or above this temperature by adjusting the amount of amine acid gas bypassing the burner. Combustion of the SWS gas at or above this temperature in a reducing atmosphere is essential for destruction of the ammonia, and avoids formation of undesirable and troublesome compounds such as sulfur trioxide. The first combustion zone of the Reactor Furnace is separated from the second zone by a refractory checker wall. The amine acid gas bypassing the burner is injected into the Reactor Furnace immediately downstream of the checker wall, where it mixes with the burner effluent. The second zone is large enough to provide sufficient residence time for the
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SULFUR BLOCK sulfur-forming and hydrocarbon-oxidizing reactions to reach equilibrium. The Reactor Furnace functions as a non-catalytic conversion stage, as 67% of the hydrogen sulfide is converted to elemental sulfur. The effluent from the Reactor Furnace enters the tubes in the Waste Heat Boiler, A2-BF1530 (A2-BF1540), where the gas is cooled to 328°C [622°F] by producing HP steam. The gas is then routed through the first condensing pass of the Sulfur Condenser, A2-EA1531 (A2-EA1541), and further cooled to 165°C [329°F] by producing LP steam. The outlet channel of the Sulfur Condenser is extended and contains a compartment that serves as a separator for the condensed sulfur that is formed as the gases are cooled. About 65% of the sulfur entering the sulfur plant is recovered as condensed liquid sulfur here.
9.3.5
Catalytic Processing The vapor from the first condensing pass of the Sulfur Condenser flows to the Reactor No. 1 Feed Heater, A2-EA1532 (A2-EA1542), and is heated by a portion of the HP steam generated in the Waste Heat Boiler, which circulates in a thermosiphon loop. The reheated stream then enters the first catalyst chamber in the Reactor, A2-DC1530 (A2-DC1540), at 232°C [450°F]. In this first catalytic conversion stage, the majority of the remaining sulfur compounds are converted to elemental sulfur vapor by reaction (2). In addition, much of the organic sulfur compounds formed by side reactions in the Reactor Furnace, carbonyl sulfide (COS) and carbon disulfide (CS2), are hydrolyzed back to H2S in this catalyst bed. Hydrolysis of the organic sulfur compounds helps achieve high sulfur recovery by converting the organic sulfur compounds into sulfur species that will react via the Claus reaction to produce sulfur. Special promoted catalysts are often employed for higher COS/CS2 conversion, and this catalytic stage is often operated at higher temperatures since this also increases conversion. The sulfur vapor produced the first catalyst bed is then condensed at about 161°C [322°F] in the second condensing pass of the Sulfur Condenser by generating additional LP steam. About 20% of the inlet sulfur is condensed and recovered as liquid sulfur in the separator chamber at the outlet of this condenser pass. The vapor from the second condensing pass is reheated to 210°C [410°F] using HP steam in the Reactor No. 2 Feed Heater, A2-EA1533 (A2-EA1543), and is routed to the
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SULFUR BLOCK second catalyst chamber in the Reactor where further conversion of H2S and SO2 occurs. The reactor effluent is then cooled to 157°C [314°F] in the third condensing pass of the Sulfur Condenser by generating additional LP steam. About 7% of the inlet sulfur is recovered as condensed liquid sulfur in the separator chamber at the outlet of this condensing pass. The vapor leaving the third condensing pass is reheated to 204°C [400°F] using HP steam in the Reactor No. 3 Feed Heater, A2-EA1534 (A2-EA1544), and flows to the third catalyst chamber in the Reactor, the final conversion stage. More conversion occurs in this third catalytic stage before the gas is cooled in the fourth pass of the Sulfur Condenser by generating additional LP steam. An additional 2% of the total sulfur is recovered in the separator chamber at the outlet of this fourth and final condensing pass, bringing the total sulfur recovery to approximately 94% in the Claus sulfur plant. The remaining vapor leaves the fourth pass of the Sulfur Condenser at about 156°C [313°F] and flows to the TGCU.
9.3.6
Air Control System For optimum sulfur recovery, the hydrogen sulfide:sulfur dioxide ratio of the process gas at all points downstream of the Reactor Furnace should be exactly 2:1. This ratio depends on the amount of air sent to the Acid Gas Burner by the Process Air Blower. A combination of feed-forward/feed-back control is used in the sulfur plant to control the proper quantity of air. The amine acid gas flow rate and SWS gas flow rate (and fuel gas flow rate, if any) are measured, summed together, and sent to the ratio controller which adjusts the air flow, yielding feed-forward control that allows the sulfur plant to compensate for changes in the amine acid gas and SWS gas flow rates (and the fuel gas flow rate, also). The H2S:SO2 ratio of the gas from the fourth condensing pass of the Sulfur Condenser is continuously analyzed by the air demand analyzer. This analyzer signal is then used to change the setpoint of the flow ratio controller, thus providing feed-back control to allow the sulfur plant to adjust to variations in amine acid gas and/or SWS gas composition, temperature, and pressure.
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SULFUR BLOCK 9.3.7
Molten Sulfur Handling Liquid sulfur from each of the four condensing passes is routed to an individual Sulfur Drain Seal Assembly, A2-ME1530A-D (A2-ME1540A-D), in the below-ground Sulfur Surge Tank, A2-FB1530 (A2-FB1540). Each drain seal has a "U"-tube that uses static head from a column of liquid sulfur to serve as a seal and prevent the process gases from escaping. The drain seals are steam-jacketed to prevent sulfur from freezing and have view hatches to allow verifying that each rundown line is flowing. The Sulfur Surge Tank provides storage for about 160 metric tons of raw sulfur production from the sulfur plant. The Sulfur Surge Tank is a horizontal cylindrical tank resting in a concrete vault. The tank is constructed of carbon steel and is equipped with internal steam coils. The Sulfur Surge Tank Vent Ejector, A2-EE1530 (A2-EE1540), uses HP motive steam to route the tank vapors to the Tailgas Thermal Oxidation system.
9.3.8
Steam Production The Sulfur Recovery Unit produces steam at two pressure levels. High pressure steam is generated at 48.5 kg/cm2(g) [690 PSIG] in the Waste Heat Boiler. A portion of this steam is used to reheat the reactor feed streams and in the TGCU Reactor Feed Heater, A2-EA1560. The remaining HP steam from the SRU is routed to the Tailgas Thermal Oxidation system to be superheated in the Thermal Oxidizer Waste Heat Boiler, A2-BF1570. Low pressure steam at 4.2 kg/cm2(g) [60 PSIG] is produced in the Sulfur Condenser. Part of this steam is used to preheat the amine acid gas, heat the Sulfur Storage Tank, heat the steam-jacketed lines, and for steam tracing services. The remainder is routed to the complex's LP steam header.
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SULFUR BLOCK
9.4
Equipment Description
9.4.1
Reactor Furnace, A2-BA1530 (A2-BA1540) The Reactor Furnace is a combustion and non-catalytic reaction chamber. The furnace shell is internally lined with refractory insulation to protect it against the extreme process temperatures inside. The maximum operating temperature is about 1600°C. Although the furnace can withstand short excursions above this temperature, prolonged operation above this temperature will damage the refractory. The refractory is designed to keep the furnace shell at 200-340°C to protect it from acid corrosion on its interior. Periodic surveys of the temperature all along the shell of the furnace should be conducted (using a hand-held infrared pyrometer) to ensure that the shell is always in the desired temperature range. The furnace is divided into two combustion/reaction zones by a refractory checker wall. In the first zone, the SWS gas and most of the amine acid gas are combusted with process air to destroy the ammonia, oxidize the hydrocarbons, produce sulfur dioxide, and form sulfur. The remaining amine acid gas enters the furnace through side injection nozzles and mixes with the combustion products flowing through the checker wall into the second zone of the furnace. This second zone provides additional residence time for the sulfur-forming and hydrocarbon-oxidizing reactions to reach equilibrium. The furnace is covered by a protective metal shroud to prevent thermal shock to the hot metal shell by severe weather, such as heavy rains.
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SULFUR BLOCK 9.4.2
Acid Gas Burner Assembly, A2-BA1531 (A2-BA1541) The burner assembly is specifically designed to burn the acid gas stream for this facility. The unit consists of an acid gas burner tip, a fuel gas burner ring with multiple tips for combusting fuel gas during plant warmup, a pilot gas burner with an integral ignitor, two flame scanners, two viewports, and specially designed air distribution baffles for proper combustion. This complete unit is installed in the front of the Reactor Furnace The StackMatch® ignitor/pilot assembly is designed to be retracted or extracted after the main fuel gas burner ring or the acid gas burner tip has been lit. If the assembly is extracted, the block valve can be closed to isolate it from the furnace atmosphere. The assembly includes filters for the incoming fuel gas and air, which should be checked (and cleaned, if necessary) after each use so that there is no chance of a plugged filter causing delays during the next startup.
9.4.3
Acid Gas Knock-Out Drum, A2-FA1530 (A2-FA1540) This vertical vessel is installed in the inlet amine acid gas line to remove liquids from the gas stream before it is routed to the Acid Gas Burner and Reactor Furnace. The liquid produced in this vessel is pumped on automatic start/stop control to the Rich Amine Flash Drum. The vessel is equipped with high level alarms to warn of a rising level in the drum, and a high-high level shutdown to activate the SRU ESD system before liquids can reach the hot furnace. The shutdown requires that 2 out of 3 transmitters have a high-high level indicated.
9.4.4
SWS Gas Knock-Out Drum, A2-FA1531 (A2-FA1541) This vertical vessel is installed in the inlet SWS gas line to remove liquids from the gas stream before it is routed to the Acid Gas Burner. The liquid removed in this vessel is pumped on automatic start/stop control to the Sour Water Flash Drum. The vessel is equipped with high level alarms to warn of a rising level in the drum, and a high-high level shutdown to block-in the SWS gas before liquids can reach the hot furnace.
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SULFUR BLOCK 9.4.5
Reactor, A2-DC1530 (A2-DC1540) The Reactor is a single horizontal vessel divided by two vertical partitions into three separate catalyst chambers. This reactor is of the axial down-flow type, with the feed gas entering the top of each chamber (via a standpipe from the bottom of the vessel) and proceeding vertically downward through its catalyst bed. These standpipes discharge the feed gases against the top of the vessel shell to distribute the gases over the length of each chamber and prevent the inlet gas streams from impinging directly on the catalyst beds. A catalyst support grating is installed in each chamber to support its catalyst bed in the center of the vessel. The support grating is covered with a stainless steel screen to prevent the catalyst from sifting through the grating. A small bead of castable refractory is used to seal the edges of the support grating to prevent catalyst leaks between the grating and the vessel shell.
9.4.6
Catalyst for Sulfur Plant Reactors, A2-MC1530 (A2-MC1540) Refer to the Basic Engineering Package for the type of catalyst used in the Reactor.
9.4.7
Acid Gas Preheater, A2-EA1530 (A2-EA1540) This shell and tube exchanger uses LP steam to heat the inlet amine acid gas stream before it mixes with the SWS gas and is combusted in the Acid Gas Burner and the Reactor Furnace. This minimizes the possibility of having ammonia salts precipitate when the amine acid gas mixes with the high ammonia content SWS gas. The preheating also increases the production of HP steam in the Waste Heat Boiler.
9.4.8
Sulfur Condenser, A2-EA1531 (A2-EA1541) The Sulfur Condenser contains four different sets of tubes. Divider plates in the inlet and outlet channels segregate the four different gas streams flowing through this exchanger. The four sets of condensing pass tubes are immersed in the water-filled section of the shell, allowing them to cool the hot gases leaving the Waste Heat Boiler and the three catalyst beds in the Reactor. The boiling water in the shell of the exchanger cools the gases and condenses sulfur from the process streams. The steam produced will be controlled at about
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SULFUR BLOCK 4.2 kg/cm2(g). The outlet channel of the exchanger is extended to serve as gas/liquid separators to remove entrained sulfur droplets from the gas streams by gravity separation. The separator chambers also contain woven wire mist eliminators to assist in removing sulfur from the gas streams. Steam-jacketed sulfur drains are located in the bottom of each separator chamber to remove the liquid sulfur produced. The boiler is equipped with level transmitters that will shut down the SRU should the water level fall to within 75 mm of the top row of condensing tubes. The shutdown requires that 2 out of 3 transmitters have a low-low level indicated. Operation of the boiler without a sufficient water level could possibly damage the tubes.
9.4.9
Reactor No. 1 Feed Heater, A2-EA1532 (A2-EA1542) This shell and tube exchanger uses HP steam to heat the process gas stream leaving the first condensing pass of the Sulfur Condenser before it enters the first catalyst bed in the Claus Reactor. This exchanger operates in a thermosiphon loop with the Waste Heat Boiler using a portion of the steam produced by the Waste Heat Boiler to provide the heat input. The temperature of the gas leaving the exchanger is controlled at the desired value by adjusting a control valve in the condensate outlet line. This control valve can raise the level of condensate in the exchanger shell to submerge some of the tubes in condensate to reduce the heat input.
9.4.10
Reactor No. 2 Feed Heater, A2-EA1533 (A2-EA1543) This shell and tube exchanger uses HP steam to heat the process gas stream leaving the second condensing pass of the Sulfur Condenser before it enters the second catalyst bed in the Claus Reactor. This exchanger operates in a thermosiphon loop with the Waste Heat Boiler using a portion of the steam produced by the Waste Heat Boiler to provide the heat input. The temperature of the gas leaving the exchanger is controlled at the desired value by adjusting a control valve in the condensate outlet line. This control valve can raise the level of condensate in the exchanger shell to submerge some of the tubes in condensate to reduce the heat input.
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SULFUR BLOCK 9.4.11
Reactor No. 3 Feed Heater, A2-EA1534 (A2-EA1544) This shell and tube exchanger uses HP steam to heat the process gas stream leaving the third condensing pass of the Sulfur Condenser before it enters the third catalyst bed in the Claus Reactor. This exchanger operates in a thermosiphon loop with the Waste Heat Boiler using a portion of the steam produced by the Waste Heat Boiler to provide the heat input. The temperature of the gas leaving the exchanger is controlled at the desired value by adjusting a control valve in the condensate outlet line. This control valve can raise the level of condensate in the exchanger shell to submerge some of the tubes in condensate to reduce the heat input.
9.4.12
Sulfur Surge Tank, A2-FB1530 (A2-FB1540) This horizontal vessel is installed in a below-ground concrete vault. It receives the produced liquid sulfur from the SRU and holds it in a molten state for pumping to the Sulfur Degassing Unit. There are steam coils installed in the bottom of the tank to keep the sulfur molten, each with its own steam supply and trap. Should a steam coil develop a leak, it can be shut off while the others keep the sulfur hot. The tank is installed below ground to accept the sulfur production by gravity flow. Liquid-sealed Sulfur Drain Seal Assemblies are provided to allow draining of the produced liquid sulfur while preventing passage of the process gases. Liquid sulfur flows through these drain seals and then into the tank. The primary ventilation system for the Sulfur Storage Tank is the Sulfur Surge Tank Vent Ejector, A2-EE1530 (A2-EE1540). It uses HP steam as the motive force to circulate air through the tank. Ambient air enters through the breather vents at each end of the tank and is educted to the ejector suction. The discharge from the ejector is routed to the TTO for disposal. This air circulation dilutes the H2S that "weathers off" from the liquid sulfur so that the concentration remains below the lower explosive limit. The circulation also prevents accumulation of water in the tank that could cause rapid corrosion. In addition to the steam-powered ejector, there is a backup natural-draft ventilation system provided for the Sulfur Storage Tank when the ejector is out of service. The tank vapors are vented from the tank through a heated vent stack mounted on the top of the tank. Air to displace these vapors enters through the breather vents at each end of the tank and
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SULFUR BLOCK sweeps through the tank before entering the vent stack. The steam-jacketing on the vent stack heats the air in the stack, providing the natural-draft driving force that makes the system work.
WARNING
IT IS VERY IMPORTANT TO KEEP HEAT (STEAM) ON THE VENT STACK TO MAINTAIN THE NATURAL DRAFT. IN ADDITION, THE STEAM JACKET ON THE VENT STACK MUST VENTED PERIODICALLY TO PREVENT NON-CONDENSIBLES FROM ACCUMULATING AND "BLANKING OFF" THE STEAM HEATING SURFACES. A VENT LINE IS PROVIDED EXPRESSLY FOR THIS PURPOSE.
9.4.13
Acid Gas Knock-Out Drum Pump, A2-GA1530A/B (A2-GA1540A/B) These pumps send liquids that accumulate in the Acid Gas Knock-Out Drum to the Rich Amine Flash Drum. The pumps are designed to start and stop automatically when the level rises in the vessel. Level transmitters mounted on the vessel alert the operator if the level in the vessel exceeds the automatic start point. These pumps are equipped with tandem seals to reduce the likelihood of releasing H2S to the surroundings.
WARNING THE LIQUID IN THESE PUMPS CONTAINS DISSOLVED H2S. THIS H2S CAN BE RELEASED TO THE SURROUNDINGS WHEN LIQUID IS DRAINED FROM THESE PUMPS OR FROM THE PIPING CONNECTED TO THE PUMPS. ALWAYS OBSERVE PROPER PROCEDURES AND PRECAUTIONS WHEN DRAINING LIQUID FROM THESE PUMPS OR PERFORMING MAINTENANCE ON THEM. THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES SHOULD BE CONSULTED IF THERE IS ANY DOUBT ABOUT HOW TO WORK SAFELY WHEN H2S MAY BE PRESENT.
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SULFUR BLOCK 9.4.14
SWS Gas Knock-Out Drum Pump, A2-GA1531A/B (A2-GA1541A/B) These pumps send liquids that accumulate in the SWS Gas Knock-Out Drum to the Sour Water Flash Drum. The pumps are designed to start and stop automatically when the level rises in the vessel. Level transmitters mounted on the vessel alert the operator if the level in the vessel exceeds the automatic start point. These pumps are equipped with tandem seals to reduce the likelihood of releasing H2S to the surroundings. WARNING THE LIQUID IN THESE PUMPS CONTAINS DISSOLVED H2S AND NH3. THIS H2S AND/OR NH3 CAN BE RELEASED TO THE SURROUNDINGS WHEN LIQUID IS DRAINED FROM THESE PUMPS OR FROM THE PIPING CONNECTED TO THE PUMPS. ALWAYS OBSERVE PROPER PROCEDURES AND PRECAUTIONS WHEN DRAINING LIQUID FROM THESE PUMPS OR PERFORMING MAINTENANCE ON THEM. THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES SHOULD BE CONSULTED IF THERE IS ANY DOUBT ABOUT HOW TO WORK SAFELY WHEN H2S AND/OR NH3 MAY BE PRESENT.
9.4.15
Sulfur Storage Tank Vent Ejector, A2-EE1530 (A2-EE1540) This jet ejector uses HP motive steam to circulate air through the Sulfur Surge Tank and route it to the Thermal Oxidizer. This air dilutes the H2S that "weathers off " from the liquid sulfur product so that the H2S concentration in the Sulfur Surge Tank is well below the lower explosive limit (LEL). The ejector body is steam-jacketed to prevent sulfur contained in the circulating air from freezing and plugging the ejector. Whenever motive steam to the ejector is not available, the ejector discharge valve should be closed. This will prevent back-flow of Thermal Oxidizer gases into the Sulfur Surge Tank.
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SULFUR BLOCK
WARNING
NEVER BLOCK-IN THE EJECTOR COMPLETELY (CLOSING BOTH THE SUCTION AND DISCHARGE VALVES) WHILE THE HP MOTIVE STEAM IS CONNECTED TO THE EJECTOR. A LEAK IN THE MOTIVE STEAM BLOCK VALVE COULD ALLOW THE HP STEAM TO OVER-PRESSURE THE EJECTOR BODY.
9.4.16
Process Air Blower, A2-GB1530A/B (A2-GB1540A/B) These multi-stage centrifugal blowers provide the combustion air required to combust the amine acid gas and SWS gas in the Acid Gas Burner. The air flow rate is controlled by throttling a valve in each blower suction line. A vent valve on each blower discharge line is used to vent air to the atmosphere when the process air flow is low so that the blower does not go into "surge".
CAUTION
THE BOLT HOLES IN THE BLOWER/MOTOR BASEPLATES ARE PROVIDED FOR SHIPPING AND POSITIONING PURPOSES ONLY. DO NOT BOLT THE BASEPLATES DOWN TIGHTLY. EITHER LEAVE THE NUTS OFF, OR HAND-TIGHTEN THEM ONLY. EXCESSIVE TIGHTENING MAY DISTORT THE BASEPLATES AND CAUSE MISALIGNMENT AND/OR VIBRATION DAMAGE TO THE UNITS. THE BASEPLATES ARE TO REST ON RESILIENT FOUNDATION PADS. DO NOT GROUT UNDER THE BASEPLATES. RIGIDLY CONNECTING THE BASEPLATES TO THEIR FOUNDATIONS WILL INCREASE THE BLOWER VIBRATION LEVELS AND LEAD TO BLOWER DAMAGE.
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SULFUR BLOCK 9.4.17
Air Blower Suction Screen/Silencer, A2-FD1530A/B (A2-FD1540A/B) This filter/silencer is designed to keep rainwater and large solid particles from entering the Process Air Blower. It also helps reduce the noise produced by the Process Air Blowers.
9.4.18
Process Air Vent Silencer, A2-FG1530A/B (A2-FG1540A/B) These silencers help reduce the noise produced when the blow-off valves on the discharge of the Process Air Blowers are being used to prevent the blowers from "surging".
9.4.19
Sulfur Drain Seal Assembly, A2-ME1530A-D (A2-ME1540A-D) Ortloff's proprietary Sulfur Drain Seal Assemblies are designed to drain liquid sulfur from the four outlet channels of the Sulfur Condenser. The seals are built as "U-type" traps that use liquid sulfur to seal and prevent process gases from flowing to the Sulfur Surge Tank along with the liquid sulfur product. The drain seals are sized to provide a seal leg which should not blow out at the maximum discharge pressure of the Process Air Blower. The seals are fully steam-jacketed and designed to be installed in the top of the Sulfur Surge Tank. Each seal has a hinged inspection hatch to allow observation and sampling of the flow from each condenser pass. The liquid sulfur from the inspection basin flows down to the bottom of the Sulfur Surge Tank through a drain pipe to prevent free-fall of the liquid sulfur, which could cause static electricity to build up. The drain seals are mostly carbon steel, except for the inspection hatches which are aluminum. Each drain seal has removable blind flanges to allow "rodding" its rundown line and its dip leg. Before removing either flange, close the block valve in the rundown line to prevent the escape of process gas to the surroundings when the plugging is cleared. When the rodding operation is complete and the flange(s) are back in place, remember to reopen the block valve.
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SULFUR BLOCK 9.4.20
Refractory for Reactor Furnace and Waste Heat Boiler, A2-MR1530 (A2-MR1540) The firing chamber of the Reactor Furnace and the transition piece on the Waste Heat Boiler have a refractory lining consisting of alumina firebrick backed heavy duty firebrick. The checker wall in the Reactor Furnace is also constructed from alumina firebrick. Mortar used for installing the brick is alumina air-setting mortar. The inlet tubesheet on the Waste Heat Boiler is covered with a layer of alumina castable refractory.
9.4.21
Ceramic Ferrules for Waste Heat Boiler, A2-MR1532 (A2-MR1542) The ceramic ferrules are inserted into the inlet ends of the tubes in the Waste Heat Boiler, then a layer of castable refractory is installed over the tubesheet. The ceramic ferrules are flush with the outside of the refractory and extend into each tube. The ferrules and refractory protect the tube ends from being directly exposed to the hot combustion gas and give very long operating life to the Waste Heat Boiler.
9.4.22
Refractory for Waste Heat Boiler, A2-MR1533 (A2-MR1543) The outlet channel of the Waste Heat Boiler is covered with a lining of castable refractory. This refractory protects the steel surfaces of the channel from accelerated sulfide corrosion rates due to the high process gas temperature.
9.4.23
Refractory for Sulfur Condenser, A2-MR1534 (A2-MR1544) The inlet channel of the first pass of the Sulfur Condenser is covered with a lining of castable refractory. This refractory protects the steel surfaces of the channel from accelerated sulfide corrosion rates due to the high process gas temperature. The refractory is built up on the bottom of the channel so that it is flush with the bottom of the inlet nozzle and with the bottom of the tubes in the lowest row of tubes, so that the entire inlet channel free-drains from the inlet nozzle into the tubes and liquid sulfur cannot "puddle" in the inlet channel.
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SULFUR BLOCK 9.4.24
Refractory for Reactor, A2-MR1535 (A2-MR1545) A 50 mm bead of castable refractory is installed around the edges of the catalyst bed supports inside each chamber of the Reactor. This seals the edges of the bed supports so that the small catalyst pellets cannot escape from the beds.
9.4.25
Rainshield for Reactor Furnace, A2-ME1531 (A2-ME1541) The Reactor Furnace shell is internally lined with refractory insulation to protect it against the extreme process temperatures inside. The refractory is designed to keep the furnace shell at 200-340°C to protect it from corrosion on its interior. Shell temperatures higher than this can result in high temperature sulfidic corrosion of the steel shell, while temperatures lower than this can cause the steel to drop below the acid dewpoint of the process gas and suffer acid corrosion. The upper 240° of the Reactor Furnace is covered by a metal rainshield to prevent over-cooling of the furnace shell by rain and/or wind, which would cause shorter refractory life (due to thermal cycling) and corrosion of the furnace shell (due to acid condensation). The rainshield is mounted on stand-off rings to protect the furnace shell from direct exposure to the elements without restricting the free circulation of cooling air over the furnace shell. The rainshield is formed from corrugated galvanized steel.
9.4.26
Ceramic Ferrule for Reactor Furnace, A2-MR1531 (A2-MR1541) These ceramic ferrules are inserted into the side ports on the Reactor Furnace where the bypassed acid gas is to be injected into the second zone of the furnace. The ceramic ferrules extend to the outside of the refractory lining inside the furnace so that essentially no part of the nozzle is directly exposed to the hot furnace gases or to radiation from the hot furnace. This will help protect the nozzles from overheating whenever the bypass acid gas is not flowing.
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SULFUR BLOCK 9.4.27
Waste Heat Boiler, A2-BF1530 (A2-BF1540) The Waste Heat Boiler contains the cooling pass tubes which cool the hot gases leaving the Reactor Furnace. The cooling pass tubes are immersed in the water-filled section of the shell, allowing them to cool the hot gases leaving the Reactor Furnace from by boiling water in the shell of the exchanger. The steam produced will be controlled at about 2 48.5 kg/cm (g). Because of the high inlet temperature to these tubes, the inlet tubesheet is refractory-lined and the inlet of each tube contains a ceramic ferrule insert. Most of the steam produced by the Waste Heat Boiler is routed to the Thermal Oxidizer Waste Heat Boiler, A2-BF1570, to be superheated before it is exported to the HP Steam header. The remaining portion of this steam is withdrawn and directed to the three heaters for the Reactor feeds, the Reactor No. 1 Feed Heater, the Reactor No. 2 Feed Heater, and the Reactor No. 3 Feed Heater, which operate in a thermosiphon loop with the Waste Heat Boiler. The steam flows over and condenses on the outside of the tubes in these exchangers, heating the gas within the tubes to raise the temperatures of the gas streams to the desired feed temperatures for the catalyst beds. The condensate from these three exchangers returns to the Waste Heat Boiler by gravity flow. The boiler is equipped with level transmitters that will shut down the SRU should the water level fall to within 75 mm of the top row of tubes. The shutdown requires that 2 out of 3 transmitters have a low-low level indicated. Operation of the boiler without a sufficient water level will result in severe damage to the tubes and the shell.
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SULFUR BLOCK
WARNING
AS DISCUSSED ABOVE, THE BOILING WATER IN THE SHELL KEEPS THE COOLING PASS TUBES FROM OVERHEATING. IF THE WATER LEVEL IN THE BOILER DROPS BELOW THESE TUBES, THE HOT COMBUSTION GAS INSIDE WILL DESTROY THE TUBES. ALTHOUGH LOW LEVEL SHUTDOWN SHOULD ACTIVATE THE SRU ESD IF THE WATER LEVEL FALLS TO 75 MM ABOVE THE COOLING PASS TUBES, THE LOW LEVEL ALARMS IN THE DCS ARE EARLY WARNINGS OF BFW LOSS. THESE LOW LEVEL ALARMS SHOULD RECEIVE IMMEDIATE ATTENTION TO MINIMIZE THE POTENTIAL FOR DAMAGE TO THE BOILER. THE LEVEL GAUGES SHOULD ALSO BE MONITORED CLOSELY BY THE OUTSIDE OPERATOR.
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SULFUR BLOCK
9.5
Instrumentation and Control Systems
9.5.1
SRU Air:Acid Gas Ratio Control Loop The chemistry of the Claus reaction dictates that optimum sulfur recovery is achieved when the ratio of hydrogen sulfide (H2S) to sulfur dioxide (SO2) in the process gases is maintained at 2:1. This ratio is determined by the amount of H2S in the acid gas feed that is combusted to SO2 by the oxygen in the process air stream fed to the burner. Each sulfur plant uses a combination of feed-forward and feed-back control to adjust the ratio of the air flow rate to the acid gas and fuel gas flow rates and maintain the optimum 2:1 H2S:SO2 ratio. The loop diagram on page 9-29 illustrates the components of this control scheme when implemented in a distributed control system (DCS). (All of the instrument tag numbers used below refer to the instruments as they are numbered in the Train 1 SRU. The control algorithm and the relay settings for the Train 2 SRU will be identical.) The feed-forward portion of the control loop uses the acid gas and fuel gas flow rates to compute the setpoint for the air flow controller, A2-FIC15370. Since the amine acid gas, SWS gas, and fuel gas require different amounts of air, the three flow rates are metered separately and then summed by A2-FY15345 and A2-FY15349. The three signals are also biased (by A2-FY15320, A2-FY15331, and A2-FY15355) to allow for the differences in air requirements. In this manner, the setpoint for A2-FIC15370 will be properly adjusted as the individual gas flow rates vary. A special photometric analyzer samples the process gas in the sulfur plant tailgas to determine the relative amounts of H2S and SO2 in the gas. The analyzer provides an output signal that is proportional to the amount the air flow rate must change in order to bring the H2S:SO2 ratio to the optimum 2:1 value. This signal is the feed-back part of the control loop, and is used to make minor adjustments to the air:acid gas ratio and allow the control system to respond to compositional variations in one or more of the acid gas feeds. The control loop is discussed in detail in the sections that follow. The discussions are divided into five sections: air requirement computation for the acid gas streams, air:acid gas ratio adjustment, air requirement computation for fuel gas, air flow control, and local/remote control.
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SULFUR BLOCK 9.5.1.1
Air Requirement Computation for the Acid Gas Streams The purpose of the acid gas bias/summing circuit is to compute the theoretical process air required for the acid gas streams, properly adjusted to account for the differing amounts of oxygen that the two streams require. The amine acid gas and SWS gas flow rate signals are linearized and input to the DCS by A2-FT15320 and A2-FT15331, respectively. Flow indicators A2-FI15320 and A2-FI15331 in the DCS indicate these flow rates in engineering units. Each flow rate is multiplied by a scale factor (relays A2-FY15320 and A2-FY15331, respectively) to compute the process air required by each stream, then added together by summing relay A2-FY15345 to give the theoretical air flow requirement for the acid gas streams. The two bias calculation blocks multiply each gas flow rate by a gain factor equal to the process air required per unit of flow for that stream. The appropriate gain factors are 2.563 Nm3/Nm3 for the amine acid gas (A2-FY15320) and 2.186 Nm3/Nm3 for the SWS gas (A2-FY15331). A2-FY15345 then sums the two outputs from the bias relays, providing an output that (at design conditions) is equal to the required air flow rate for the acid gas streams. This output is then supplied to the ratio adjustment relay, A2-AY15348. These factors can be revised periodically if changes in feedstocks, etc. cause long-term changes in the compositions of one or both of the acid gas streams. Note that each bias relay has a "zero" switch (A2-HS15320 for A2-FY15320 and A2-HS15331 for A2-FY15331). These switches can be used to "turn off " their respective relays when there is no flow of the corresponding gas stream. This prevents an erroneous reading from a flow transmitter causing errors in the theoretical air flow computations. A similar switch (A2-HS15356) is included for the fuel gas bias relay (A2-FY15355) discussed in Section 9.5.1.3.
9.5.1.2
Air:Acid Gas Ratio Adjustment By choosing the appropriate gain factors for A2-FY15320 and A2-FY15331, the output from A2-FY15345 (the theoretical air flow rate) is equal to the required process air flow rate for the acid gas streams, assuming the composition and conditions of the amine acid gas and SWS gas streams remain constant. This will seldom be true, however, so there must be a means to adjust the air:acid gas ratio for temporary changes in composition, such as increased
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SULFUR BLOCK hydrocarbon content. This is the reason for including the ratio adjustment relay, A2-AY15348. The "coarse" ratio adjustment is set manually by the DCS operator in the range of 0.0-2.0 via A2-HIC15347. This ratio setting is then "fine tuned" by the air demand controller, A2-AIC15347. The action of limit relay A2-AY15347 is to allow A2-AIC15347 to vary the "coarse" ratio setting up or down by about 10%, so that the controller acts as a "trim" on the control loop. This is accomplished with two calculation blocks: bias relay A2-AY15347 and summing relay A2-HY15347. The bias relay, A2-AY15347, reduces the magnitude of the A2-AIC15347 output signal and centers it around zero by multiplying the signal by a gain factor of 0.002 and adding a constant of -0.1. Thus, as the output from A2-AIC15347 varies from 0% to 100%, the output from A2-AY15347 will vary from -0.1 to +0.1. Summing relay A2-HY15347 then adds this output to the output from A2-HIC15347 to yield the ratio adjustment setting that is input to A2-AY15348 and indicated by A2-HI15347. The ratio adjustment relay, A2-AY15348, multiplies the ratio adjustment setting from A2-HY15347 by the theoretical air flow rate from A2-FY15345 to produce the corrected air flow rate for the acid gas streams. The effective ratio at A2-AY15348 will vary from 0.0 to 2.0 as the output from A2-HY15347 varies from 0.0 to 2.0. For example, if the output from A2-HY15347 is 1.1, the effective ratio applied to the theoretical air flow by A2-AY15348 will be 1.1, and the corresponding corrected air flow rate will be 1.1 times the theoretical air flow rate. The output from A2-AY15348 (the corrected air flow rate for the acid gas streams) is then supplied to the fuel gas summing relay, A2-FY15349. The design setting for A2-HIC15347 is 1.0 (i.e., a ratio adjustment multiplier of 1.0, which is no adjustment). 9.5.1.3
Air Requirement Computation for Fuel gas If an SRU is operating at very low load, it may be necessary to burn supplemental fuel gas in its Acid Gas Burner. When operating in this mode, the air flow control scheme must also add the air required to burn the fuel gas. Since most fuel gas has a nearly constant composition, it is not necessary to adjust the air:fuel gas ratio like it is with the acid gas streams. Instead, the fuel gas flow rate can simply
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SULFUR BLOCK be multiplied by a gain factor to compute its air requirement, then summed together with the corrected air flow described earlier that is computed by A2-AY15348. The fuel gas flow rate is linearized and input to the DCS by A2-FT15355. Flow controller A2-FIC15355 in the DCS converts this linear signal into a flow rate in engineering units. Bias relay A2-FY15355 then multiplies the fuel gas flow rate by the appropriate gain factor for this fuel gas, 32.509 Nm3/Nm3 (For the C4 LPG), to give the computed air flow for the fuel gas. This is added to the corrected air flow for the acid gas streams by summing relay A2-FY15349, giving the total air flow rate that is then supplied to the air flow controller, A2-FIC15370, as a remote setpoint. For reference, the total theoretical air flow requirement is also computed and displayed in the DCS. This is accomplished by summing relay A2-FY15346, which sums the theoretical air flow rate for the acid gas streams (the output from A2-FY15345) with the theoretical air flow rate for the fuel gas (the output from A2-FY15355). The output from A2-FY15346 is the total theoretical air flow requirement, which is displayed on A2-FI15346 in the DCS. 9.5.1.4
Air Flow Control All of the complicated parts of the control loop are contained in the calculation blocks discussed above. The resulting output from A2-FY15349 is the required air flow rate, so it is simply supplied to the air flow controller, A2-FIC15370, as its setpoint. A2-FIC15370 is a standard PID controller with remote setpoint adjustment. Its output controls the Process Air Blower suction valve, either A2-FV15333A on A2-GB1530A or A2-FV15333B on A2-GB1530B. Note that the signal from A2-FIC15370 actually controls A2-FV15333A or A2-FV15333B together with the control valves on the blower discharge lines using split ranges. This split-range action is discussed in later sections as its details are not important to this discussion.
9.5.1.5
Local/Remote Control The initial startup of an Acid Gas Burner is performed by an outside operator stationed at the local control panel near the burner. Since the operator must be able to control the air flow rate while purging
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SULFUR BLOCK the furnace and lighting the burner, a hand controller (A2-HIC15370) is mounted on the local Train 1 SRU control panel to allow manual control of the air flow valve, A2-FV15333A or A2-FV15333B, and the other blower control valves. After startup, control is then switched back to the DCS. A2-HS15370 in the DCS selects whether A2-FV15333A/B is controlled by the local operator or by the controller in the DCS, A2-FIC15370. During startup, when the outside operator has control, A2-HS15370 is positioned such that the signal from A2-HIC15370 is supplied to A2-FV15333A/B. When the DCS operator is ready to assume control, the output of A2-FIC15370 can be matched to that of A2-HIC15370 (as indicated by A2-HI15370 in the DCS) and A2-HS15370 repositioned to send the output of A2-FIC15370 to A2-FV15333A/B, resulting in a "bump-less" transfer.
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SULFUR BLOCK
Air:Acid Gas Ratio Control Loop (SRU Train 1)
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SULFUR BLOCK 9.5.2
Acid Gas Burner Management System The burner management system (BMS) for the Acid Gas Burner in each SRU is controlled by a sequential logic controller (most commonly a programmable logic controller or PLC). The ESD reset, BMS, and Startup/Run Logic Flowcharts for the Train 1 SRU, contained in the Instrumentation and Controls Diagrams section of the Basic Engineering Package, describe the sequence of steps required before permitting ignition to ensure a safe firing order. The function of the various system components is described below. (All of the instrument tag numbers used below refer to the instruments as they are numbered in the Train 1 SRU. The logic for the Train 2 SRU is identical.)
9.5.2.1
Startup/Run Interlocks The "startup" and "run" interlock logic for the Train 1 SRU is shown on the Startup/Run Logic Flowcharts. The purpose of this logic is to simplify lighting the Acid Gas Burner and switching to acid gas firing in the Train 1 SRU by automatically positioning the process gas switching valves in the proper sequence for safe operation:
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(1)
Before attempting ignition of the burner, the catalyst beds should be bypassed so that air cannot reach them and cause sulfur fires. Setting selector switch A2-HS15314 on the local Train 1 SRU control panel to "STARTUP" will open the two Warmup Bypass Valves, A2-HV15441 and A2-HV15454, close the Tailgas Valve to the TTO, A2-HV15457, and close the Tailgas Valve to the TGCU, A2-HV15462, so that air and/or combustion products from the Reactor Furnace are diverted upstream of the first catalyst bed in the Reactor to flow directly to the TTO.
(2)
Once the pilot burner in the Acid Gas Burner has been lit and the SRU is ready to accept acid gas (furnace up to temperature, etc.), the Warmup Bypass Valves must be closed before acid gas can be introduced into the SRU. However, in order to avoid activating the "complete flowpath interlock" alarm and possibly tripping the Reactor Furnace high-high pressure S/D, there must be an open flowpath through the SRU before the bypass valves are closed.
(3)
Setting selector switch A2-HS15314 to "RUN" will automatically open the Tailgas Valve to the TTO, prove the valve open, then
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SULFUR BLOCK close the two bypass valves and initiate the nitrogen purge, A2-HV15453, between the two valves. By automating the valve switching steps and including checks of the limits switches in the logic, the chance of accidentally causing an SRU1 ESD due to over-pressure during startup are greatly reduced. While the switching valves are moving, the corresponding status lights on the local Train 1 SRU control panel should blink to provide feedback to the operator. If a switching valve does not move to the proper position, its status light should continue to blink. This will alert the operators to investigate the problem and take any required corrective action so that the BMS then allows proceeding. 9.5.2.2
Flame Scanners The flame scanners, A2-BE15369A and A2-BE15369B, monitor the pilot, warmup, and acid gas burners. If a scanner detects a flame, the associated "flame proven" signal will indicate. If neither scanner detects a flame, the SRU1 ESD system is activated. Since a "flame proven" signal from either scanner satisfies the ESD system, maintenance may be performed on one flame scanner while the other remains in service. Note that a third flame scanner, A2-BE15368, is furnished with the pilot to detect its flame, but it is used only to activate its status light (A2-GL15368) on the local Train 1 SRU control panel and a status indicator (A2-BL15368) in the DCS.
9.5.2.3
Purge Cycle To ensure the unit is safe for firing, a purge cycle must be completed before the pilot can be ignited. To purge the Reactor Furnace, a Process Air Blower is used to send a high flow rate of air through the furnace for 25 seconds to satisfy the purge timer. The air flow must then be reduced to a low rate to allow ignition of the pilot.
9.5.2.4
Ignition Cycle After the purge cycle is complete, pressing the "IGNITION" push-button (A2-HPB15368) on the local Train 1 SRU control panel causes the BMS to initiate an attempt to ignite the pilot. The BMS closes the pilot burner purge gas valve (A2-HV15381), opens the pilot air block valve (A2-NV15367), closes the vent valve in the fuel gas to the pilot (A2-NV15364), opens the pilot fuel gas block valves,
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SULFUR BLOCK (A2-NV15363 and A2-NV15365), and energizes the ignition system, (A2-BX15368). After a 15 second ignition trial, the ignition system is de-energized. If a pilot flame is established, one or both flame scanners will indicate "flame proven" and the block valves in the air and fuel gas supplies to the pilot will remain open. Otherwise, the air and fuel gas supplies to the pilot are blocked-in and the purge cycle must be repeated. 9.5.2.5
Fuel gas Firing After the pilot burner is lit, the main fuel gas supply is enabled. Pressing push-button A2-HPB15391 on the local Train 1 SRU control panel will close the main burner purge gas valve, (A2-HV15382), close the vent valve in the fuel gas to the main burner (A2-NV15358), and open the main fuel gas block valves (A2-NV15357 and A2-NV15359). The fuel gas control valve (A2-FV15355) can then be adjusted using either A2-HIC15355 on the local SRU control panel or A2-FIC15355 in the DCS to manually fire fuel gas on the warmup burner ring in the Acid Gas Burner to heat the refractory in the Reactor Furnace and heat the water in the Waste Heat Reclaimer and Sulfur Condenser.
9.5.2.6
Acid Gas Firing After the pilot burner is lit, the acid gas controls can also be enabled. Turning startup/run selector switch A2-HS15314 on the local Train 1 SRU control panel to "RUN" will open the Tailgas Valve to the TTO, A2-HV15457, prove it open, then close the two Warmup Bypass Valves, A2-HV15441 and A2-HV15454, and establish a nitrogen purge between them. Turning acid gas firing selector switch A2-HS15315 on the local Train 1 SRU control panel to "ENABLED" will then allow using the manual acid gas controls, A2-HIC15320 and A2-HIC15331, on the local Train 1 SRU control panel to introduce amine acid gas and SWS gas, respectively, into the Train 1 SRU.
9.5.2.7
Pilot and Main Fuel gas On/Off Switches Push-buttons A2-HPB15390 and A2-HPB15391 on the local Train 1 SRU control panel are used to turn the pilot burner and main fuel gas burner, respectively, on and off. If the burner is already "on", pressing its push-button will extinguish the burner by closing the two block valves and opening the vent valve in its fuel gas supply, and
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SULFUR BLOCK then open the valve in its purge gas supply to begin purging the burner. For the pilot burner, the block valve in its air supply is also closed and the ignition system, A2-BX15368, is de-energized. If the burner is "off " (and the "flame proven" is already satisfied by one of the other burner tips), pressing its push-button will ignite the burner by closing the valve in its purge gas supply to cease purging the burner, and closing the vent valve and opening the two block valves in its fuel gas supply. For the pilot burner, the block valve in its air supply is also opened and its ignition system, A2-BX15368, is energized for 15 seconds.
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SULFUR BLOCK 9.5.3
Process Air Blower Controls The depiction of the controls for the Process Air Blower (A2-GB1530A/B) shown on P&ID 507000-7100-23 is fairly straightforward in how the control elements are to be arranged. What may not be clear, however, is why the controls are implemented in this manner. The discussion that follows will describe what purposes these controls serve. (The Train 1 SRU blower controls for A2-GB1530A are used as examples below. The concepts for the "B" blower and for the Train 2 SRU blower controls are the same.) In general, the process air flow to the Train 1 SRU is controlled at a specified ratio to the acid gas and fuel gas flows by A2-FIC15370. A2-FIC15370 is given a remote setpoint computed from the amine acid gas flow rate, the SWS gas flow rate, the fuel gas flow rate, and the air demand reading. A2-FIC15370 then adjusts the blower suction valve, A2-FV15333A, to control the desired air flow rate.
9.5.3.1
Blower Operation at Low Air Flow At low flow rates, the air flow can drop below the blower's surge line. If this is allowed to occur, the air flow will become erratic and the blower may be damaged. To prevent this from happening, the blower is equipped with a blow-off valve, A2-FV15335A, on its discharge line. When the air flow to the SRU is low, the blow-off valve will open and allow some of the air from the blower to vent to the atmosphere, increasing the air flow through the blower to keep it above the surge line. The discharge pressure from the air blower depends on the back-pressure from the SRU, the TGCU, and the TTO, which is a function of plant throughput. At low plant throughput, the pressure drop through these units is low and the resulting back-pressure on the air blower is low. If the back-pressure gets low enough, it can limit the air flow through the blow-off valve and cause the blower to drop below its surge line. To prevent this from happening, the air blower discharge valve, A2-FV15334A, is designed to begin throttling the blower discharge at very low flow rates, so that the discharge pressure from the blower will remain high enough to allow the blow-off valve to keep the blower from surging. The three valves on the A2-GB1530A blower operate together over the following controller ranges to give the response described above:
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SULFUR BLOCK A2-FV15333A:
Fully open at 100% output from A2-FIC15370 33.3% open at 0-66.7% output from A2-FIC15370 (software "min. stop" keeps valve from closing further)
A2-FV15334A:
Fully open at 100% output from A2-FIC15370 Fully closed at 0% output from A2-FIC15370
A2-FV15335A:
Fully closed A2-FIC15370
at
66.7-100%
output
from
Fully open at 0% output from A2-FIC15370 This results in the following actions by the blower control valves: 1.
At 100% output from A2-FIC15370, the suction valve and discharge valve will be fully open, the blow-off valve will be fully closed, and all of the air will be flowing to the SRU.
2.
As the output from A2-FIC15370 drops from 100% to 66.7%, the suction valve will begin throttling from 100% open to 33.3% open, the discharge valve will begin closing and going from fully open to throttling at 66.7% open, the blow-off valve will still be fully closed, and all of the air will still be flowing to the SRU.
3.
As the output drops below 66.7%, the suction valve will not close any further (to prevent starving the blower for air), the discharge valve will continue to throttle, and the blow-off valve will begin to open and vent part of the air to the atmosphere instead of flowing to the process.
4.
At 0% output, the suction valve will still be 33.3% open, the discharge valve will be fully closed, the blow-off valve will be 100% open, and all of the air will be venting rather than flowing to the SRU. These split-range control actions are accomplished by the function relays in the DCS shown on the P&ID. For the A2-GB1530A blower, the actions of the relays are as follows: A2-FY15333A:
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For an input of 66.7-100%, the output from this relay varies linearly from 33.3-100%. For an input below 66.7%, the output is constant at 33.3% (minimum output limit).
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SULFUR BLOCK A2-FY15334A:
For an input of 0-100%, the output from this relay is direct.
A2-FY15335A:
For an input of 0-66.7%, the output from this relay varies linearly from 100% to 0%, providing reverse action for the fail-closed control valve. For an input above 66.7%, the output is constant at 0%.
The output signals from the DCS to each of the control valves should be displayed on the DCS console. The I/P transducers mounted on the valves in the field are direct (i.e., 4-20 mA to the transducer gives an output of 0-100% from the valve positioner). The split-range values on the P&IDs are the suggested initial settings for the control schemes on these blowers. These values may need adjustment once the SRUs are placed in operation, depending on the operating characteristics of each particular air blower and its control valves. These adjustments can be made during plant startup. 9.5.3.2
Blower "Swapping" Controls While the SRUs are operating, it is sometimes necessary to "swap" air blowers for maintenance purposes, etc. This means switching from A2-GB1530A to A2-GB1530B or vice versa in the Train 1 SRU, for instance. The DCS provides controls for slowly reducing the air flow from the on-line blower while increasing the air flow from the off-line blower, so that switching from one blower to the other can be accomplished without disturbing SRU operations. (Although we have attempted to automate this concurrent ramping operation on a couple of past projects, we have not found this to be very satisfactory. The way that the blower controls need to be ramped will depend on the current plant throughput and whether or not the blower suction valve is still in control. This is classic "fuzzy logic", something that is easy for a human to do but very difficult for a computer.) Bias controller A2-HIC15339A and bias relay A2-HY15339A in the DCS adjust the controller output to the control valves on A2-GB1530A. A setting of 1.0 on A2-HIC15339A results in multiplying the output of A2-FIC15370 by 1.0 before sending the signal to the valves on A2-GB1530A (i.e., no change). A setting of 0.0 on A2-HIC15339A results in multiplying by 0.0, so zero signal is sent to the valves on A2-GB1530A (resulting in all its air venting to atmosphere with no air flow to the process). At settings between 0.0
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SULFUR BLOCK and 1.0 on A2-HIC15339A, the output to the valves on A2-GB1530A is the corresponding fraction of the output from A2-FIC15370. The bias controllers and relays (A2-HIC15339B and A2-HY15339B) for the other blower (A2-GB1530B) work in the same fashion. With these controls in the DCS, it is a relatively simple matter to swap air blowers by gradually shifting the air flow control from one blower to the other. After the off-line blower has been started, the DCS operator can begin to reduce the control signal to the on-line blower while increasing the control signal to the off-line blower, making changes as needed to maintain a stable air flow to the SRU. Once all of the control signal is going to the off-line blower and none is going to the on-line blower, the off-line blower has become the on-line blower. What was the on-line blower is now the off-line blower, and it can then be shut down without affecting the SRU. 9.5.3.3
Blower Start Interlocks and Controls The interlocks and control actions for starting a Process Air Blower are shown on the BMS Logic Flowchart contained in the Instrumentation and Controls Diagrams section of the Basic Engineering Package. These interlocks and actions ensure that these blowers are started in a safe manner while minimizing the starting load on the blowers and motors:
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a.
It is best to start a blower in an unloaded condition, with its suction valve partially open and its blow-off valve wide open. The "blower start permissive" relays, A2-HSL15338A/B, require that the control signal to the blower in question be set to 0% in order to start that blower. As described earlier in Section 9.5.3.1, this will place the suction valve and blow-off valve in the proper positions.
b.
There is always the potential to have acid gas in the process air piping, so having the blower suction and blow-off valves open while its blower is not running should be minimized to reduce the risk of releasing acid gas to the atmosphere. When the operator presses the "permit to start" push-button, A2-HPB15338A/B, for a blower, its suction and blow-off valves will open for 30 seconds to allow time for the operator to start the blower using the local start/stop control.
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SULFUR BLOCK If the blower is not started within this time, the suction and blow-off valves are closed and the "permit to start" is disabled. The operator will have to press A2-HPB15338A/B again before the blower can be started. c.
If the operator starts the blower and the motor starter contacts for the blower indicate that the blower is running within this time, the solenoid valve on the blower discharge valve is then energized so that the operator can increase the control signal to the blower to open the discharge valve and commence air flow to the process. The solenoid valve for the fail-closed discharge valve on each blower is not energized unless that blower is running. This minimizes the potential to have acid gas "back down" the process air line and be released to the atmosphere.
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SULFUR BLOCK 9.5.4
Reactor Furnace Temperature Control The temperature in the first combustion zone of each Reactor Furnace, A2-BA1530 and A2-BA1540, must be 1370°C [2500°F] or higher to insure maximum ammonia destruction. The temperature in each furnace can be controlled at this value by varying the amount of amine acid gas bypassing its Acid Gas Burner, A2-BA1531 or A2-BA1541, respectively. Increasing the portion of bypassed acid gas increases the flame temperature at an Acid Gas Burner, which is the opposite of what would be expected for typical burner systems. However, remember that an Acid Gas Burner operates at substoichiometric conditions - combustion is limited by the amount of process air provided, not by the amount of acid gas (i.e., the fuel) at the burner. The process air rate is determined by the total acid gas inlet flow rate to an SRU, not by the amount of acid gas routed to its burner. Claus plant operation is based on converting one-third of the H2S in the total feed gas to SO2 at the burner. Any hydrocarbons and ammonia present are also oxidized, but the rest of the H2S passes through un-oxidized. Bypassing some of the acid gas around the burner permits combustion of a larger fraction of the H2S in the feed to the burner, resulting in a higher flame temperature. For a simplified example, consider the case where there is no SWS acid gas flow. Without any amine acid gas bypassed, only 33% of the H2S at the burner would be burned. If one-third of the total amine acid gas bypasses the burner, then 50% of the H2S in the amine acid gas sent to the burner must be burned in order to convert one-third of the total H2S to SO2. Thus, a larger fraction of the H2S entering the burner is combusted when part of the acid gas bypasses the burner, which raises the flame temperature. The furnace temperature control loop for the Train 1 SRU consists of: the optical pyrometer, A2-TT15375; the Reactor Furnace temperature controller, A2-TIC15375; the acid gas bypass flow ratio controller, A2-FFIC15350; the acid gas valve to the burner, A2-FV15351, and the acid gas bypass valve, A2-FV15350. (Note that an optical pyrometer does not actually measure temperature. Instead, it infers the furnace temperature by measuring the infrared radiation inside the Reactor Furnace. Experience has shown that the temperature indicated by an
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SULFUR BLOCK optical pyrometer is usually 100-200°C lower than the calculated temperature for a given set of conditions.) The furnace temperature is not directly controlled. Instead, it is controlled indirectly via remote setpoint adjustment of A2-FFIC15350. (Past experience has shown that measurement of the front zone temperature using optical pyrometers is not always consistent and/or repeatable, and flow ratio control of the bypass amine acid gas has proven to be more stable for control purposes.) By placing A2-FFIC15350 in "cascade", A2-TIC15375 can adjust its ratio setpoint within the range of 0.00:1 to 0.65:1. Thus, if the temperature in the first zone of the Reactor Furnace is too low, A2-TIC15375 will raise the ratio setpoint of A2-FFIC15350, which will then bypass more amine acid gas around the Acid Gas Burner and raise the furnace temperature. The 1370°C furnace temperature for ammonia destruction discussed earlier is a calculated temperature. As stated earlier, the temperature indicated by an optical pyrometer is usually 100-2300°C lower than the calculated temperature for a given set of conditions, so a normal operating temperature of 1200°C as indicated by the pyrometer is suggested for the first zone in the Reactor Furnace. Operating experience will dictate the minimum indicated furnace temperature at which SWS gas can be admitted to the furnace. When the Train 1 SRU is operating at low flow rates, there may not be enough pressure drop in its Acid Gas Burner to give good control of the bypass acid gas with A2-FV15350. For this reason A2-FV15351 is designed to work together with A2-FV15350 over split ranges of the A2-FFIC15350 controller output. If A2-FV15350 goes fully open at lower flow rates, the controller output will continue to increase so that A2-FV15351 begins to "throttle" in the amine acid gas line to the burner and force more of the acid gas to flow through A2-FV15350. It is critical that A2-FV15351 never closes completely, as there should always be some amine acid gas flowing to the burner to be sure that the front zone of the Reactor Furnace does not become an oxidizing atmosphere. The DCS limit relay, A2-FY15351, will prevent this fail-open valve from closing completely by limiting the output to the valve to 75% and below.
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SULFUR BLOCK 9.5.5
Knock-Out Drum Pump Control Under ordinary conditions, little (if any) liquid will drop out in the Acid Gas Knock-Out Drum, A2-FA1530. During upsets, however, liquid can rapidly accumulate in the drum. For this reason, the Acid Gas Knock-Out Drum Pump, A2-GA1530A/B has been designed to automatically start and stop as required by the liquid level in the drum, based on the level signal sent to the DCS. Level signals are provided to the PLC by three LTs for use as a 2oo3 voting shutdown if the level continues to rise. The local H-O-A switches near the pumps allow the operator to place these pump in "auto" start mode. The DCS should start the pump when the liquid level reaches the "pump start" level in the drum. After the liquid is pumped out, the DCS should stop the pump when the level reaches the "pump stop" level. If the pump fails to start, or the liquid level is rising faster than the pump can keep up with, the DCS should give a LAH. If the level continues to rise, the PLC will activate the SRU ESD system when the level reaches the LAHH setpoint to prevent carry-over of liquids into the Acid Gas Burner and the Reactor Furnace. If the pump fails to stop, the DCS should give a LAL. Similarly, little (if any) liquid will drop out in the SWS Gas Knock-Out Drum, A2-FA1531 under normal conditions. It can also have liquids accumulate rapidly during an upset, however, so the SWS Gas Knock-Out Drum Pump, A2-GA1531A/B has also been designed to automatically start and stop as required by the liquid level in the drum, based on the level signal sent to the DCS. Level signals are provided to the PLC by three LTs for use as a 2oo3 voting shutdown. The local H-O-A switches near the pumps allow the operator to place these pumps in "auto" start mode. The DCS should start the pump when the liquid level reaches the "pump start" level in the drum. After the liquid is pumped out, the DCS should stop the pump when the level reaches the "pump stop" level. If the pump fails to start, or the liquid level is rising faster than the pump can keep up with, the DCS should give a LAH. If the level continues to rise, the PLC will close the SWS gas inlet valve when the level reaches the LAHH setpoint to prevent carry-over of liquids to the Acid Gas Burner. If the pump fails to stop, the DCS should give a LAL.
9.5.6
"Ride-Through" System Considerations Field experience has shown that a brief interruption in the electric power to a typical air blower will not cause a substantial drop in the air flow as
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SULFUR BLOCK long as power is restored before the blower "spins down" too much. The rotors in Process Air Blowers have relatively large moments of inertia so it takes a relatively long time (usually many seconds) for the rotational speed to decline to the point that the air flow drops enough to extinguish the flame in the associated burner. It is possible to take advantage of this phenomenon by including provisions in the emergency shutdown (ESD) systems that will allow the blowers in the SRUs to "ride-through" momentary power interruptions. If power is restored quickly enough, the blower in a unit will come back up to speed before enough air flow is lost to cause a "flame failure" shutdown, so that the unit will not have to be restarted. If the power loss lasts long enough, of course, the unit will shut down on "flame failure" and will have to be restarted manually. For power "blips", however, there is a good chance the unit will stay on-line. In order for the blowers to "ride-through", the motor starter circuit must include an auxiliary contact that is held-in during a power outage, so that if power is restored the starter contactor will re-engage. The generic motor starter schematic below shows one way of accomplishing the "ride-through".
The key features on the schematic are: There is a "run permissive" contact from the PLC in the main power supply to the starter circuit. If the unit ESD is activated for any reason ("flame failure", for instance), this contact opens so that the blower is
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SULFUR BLOCK stopped. If the ESD is activated during a power interruption, the blower will not restart when power is restored because this contact will be open. There is a "ride-through" contact from the PLC that parallels the usual "m" latch relay in the starter circuit. The PLC closes this contact when it receives the "run" status from the blower. If power is restored before the ESD is activated, this closed contact allows the starter contact to re-engage and restore the "m" latch to keep the motor going. The start/stop control for the motor is interlocked, and has a momentary "start" contact and a maintained "stop" contact. This ensures that the blower remains off when an operator stops a blower using its local start/stop control station, regardless of what the "ride-through" logic may be doing at that time. Within the PLC logic for each ESD system, the "run" status for each blower is connected to a TDO (time delay off) timer set for 10 seconds. Normally-open contacts from the TDO are used in the PLC logic that determines whether a particular blower is running, as well as the logic that determines whether any blowers are running. Thus, if power is lost to a blower and the starter contactor disengages, the TDO contacts will continue to maintain the "blower running" logic as "true" for up to 10 seconds. If power is restored to the blower within this time and the starter contactor re-engages, the ESD logic will remain satisfied and the unit will not shut down. If power is not restored to the blower within this time, the TDO contacts will open and cause the "blower running" logic to become "false" and activate the unit ESD. While the TDO timer is running, all of the unit shutdowns besides "no blower running" are still active. If any of these other shutdowns are tripped, the ESD will be activated immediately to shut down the unit. For example, if the flame is lost in the burner during this time, "flame failure" will activate the ESD and the unit will shut down immediately. Among other things, the ESD will then remove the "run permissive" from the blowers so that the blowers cannot restart. The logic for an air blower "run permissive" is similar to the ESD logic for that ESD system, but there are a couple of key differences. First, each unit ESD includes all of the shutdowns, while the "run permissive" does not include the "no blower running" or "flame failure" S/Ds to allow starting an air blower in the first place. Second, the unit ESD requires that the "MANUAL RESET" push-button be pressed to reset the unit ESD, but the
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SULFUR BLOCK "run permissive" is auto-resetting since it must occur before the "MANUAL RESET" push-button is pressed. The auto-resetting should be inhibited for 20 seconds after an ESD event by an internal timer in the PLC to allow time for the 10 second blower "ride-through" relays and timers to time out, plus other inherent time delays such as flame scanner delays and valve travel times.
9.5.7
Boiler Low-Low Level S/D Transmitter Testing Both of the boilers in each SRU (the Waste Heat Boiler and the Sulfur Condenser) have three independent level transmitters connected to the PLC that activate the SRU ESD system before the water level can get low enough to cause tube damage. The shutdown in activated when two out of three transmitters show a low-low level. These transmitters should be tested periodically to determine that they are functioning properly. Since 2oo3 voting is used for the low-low level shutdowns in the SRU ESDs, the level transmitters can be tested one at a time without having to bypass the ESD system. Consider A2-LT15401A on the SRU Train 1 Waste Heat Boiler, for example. The procedure for testing A2-LT15401B and A2-LT15401C will be similar, as will A2-LT15431A/B/C on the Sulfur Condenser. The procedure for testing A2-LT15401A is as follows:
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(1)
The outside operator notifies the DCS operator that he is preparing to test shutdown level transmitter "A" on the Waste Heat Boiler.
(2)
The DCS operator confirms that A2-LI15401B and A2-LI15401C are both indicating adequate level in the boiler, then notifies the outside operator to proceed.
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SULFUR BLOCK
CAUTION
DO NOT PROCEED UNLESS THE OTHER TWO LEVEL INDICATORS SHOW ADEQUATE LEVEL IN THE BOILER. OTHERWISE THE LOW-LOW LEVEL SHUTDOWN IN THE SRU ESD WILL BE ACTIVATED AS SOON AS THE OUTSIDE OPERATOR BEGINS DRAINING THE LEVEL TRANSMITTER IN THE NEXT STEP. (3)
After being notified to proceed by the DCS operator, the outside operator blocks-in A2-LT15401A by closing its block valves, then opens the drain valve on the bottom of the transmitter to drain the water from the instrument.
(4)
If the transmitter is operating properly, the DCS will alarm that there is a low level in the Waste Heat Boiler on A2-LI15401A. The DCS operator acknowledges the alarm on the DCS and reports it to the outside operator.
(5)
After being notified of the alarm, the outside operator closes the drain valve on A2-LT15401A, slowly opens its bottom block valve to allow the transmitter to fill with water then opens its top block valve. This should clear the low level alarm on A2-LI15401A in the DCS.
(6)
After confirming that the low level alarm has cleared, the other level transmitters can be tested in a similar fashion.
NOTE:
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The DCS operator must not begin another task until confirming that the low level alarm has cleared. This is to guard against having a level transmitter malfunction that causes an SRU ESD when the other transmitters are tested.
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SULFUR BLOCK 9.5.8
SRU Emergency Shutdown Systems The purpose of the Sulfur Recovery Unit Emergency Shutdown systems (Train 1 SRU ESD and Train 2 SRU ESD) is to shut off the flow of amine acid gas, SWS gas, fuel gas, and process air to the affected SRU when serious problems occur. The Cause and Effect Diagram for the Train 1 SRU, contained in the Instrumentation and Controls Diagrams section of the Basic Engineering Package, describes the SRU1 ESD system in block format. For reference, the causes and effects of the SRU1 ESD system shown on this diagram are explained below. (All of the instrument tag numbers used below refer to the instruments as they are numbered in the Train 1 SRU. The logic for the Train 2 SRU is identical.) As noted on the Cause and Effect Diagram, it is recommended that a 5 second delay be used for most of the process parameters included in the causes of the ESD system. This is to prevent the "nuisance" shutdowns that are sometimes caused by momentary fluctuations in the process or the sensing elements.
9.5.8.1
Causes Any one of the causes listed below will activate the SRU1 ESD system: d.
Manual Shutdown Switches, A2-HS15310 and A2-HS15313 An operator can activate the SRU1 ESD system using either of two manual shutdown switches: (1)
A2-HS15310 is a NORMAL / ESD selector switch in the DCS.
(2)
A2-HS15313 is a NORMAL / ESD selector switch mounted on the local Train 1 SRU control panel.
(3)
Acid Gas Scrubber A2-LT15305A/B/C
High-High
Liquid
Level,
These devices prevent liquids in the Acid Gas Scrubber from flowing into the hot combustion chamber of the Reactor Furnace and causing an explosion. They are set to actuate if the liquid level reaches 1,280 mm above the bottom seam of the vessel. Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD (i.e., at least two
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SULFUR BLOCK transmitters must show high-high level) to avoid spurious "trips" due to the malfunction of a single transmitter. e.
No Process Air Blower A2-GB1530B starter contacts
Running,
A2-GB1530A
and
If neither Process Air Blower is sending air to the Train 1 SRU, acid gas could flow backwards down the process air line and escape from either the blowers or their suction screens. The motor starter contacts on A2-GB1530A/B are used to determine whether a blower is running, and will activate the SRU1 ESD system if neither blower is running. f.
Acid Gas Burner A2-BY15369B
Flame
Failure,
A2-BY15369A
and
Dual flame scanners are aimed to observe the flames from the pilot, warmup, and main acid gas burners. If neither scanner detects a flame (2oo2), a "flame failure" occurs and activates the SRU1 ESD system. If only one scanner detects a flame (1oo2), a malfunction alarm is activated in the DCS, but the SRU1 ESD system is not activated. A third flame scanner, A2-BY15368, is furnished with the pilot to detect its flame, but it is used only to activate its status light (A2-GL15368) on the local Train 1 SRU control panel and a status indicator (A2-BL15368) in the DCS. g.
Reactor Furnace High-High Pressure, A2-PT15372A/B/C These devices protect against over-pressuring the SRU and blowing out its Sulfur Drain Seal Assemblies (which would emit toxic H2S to the atmosphere) due to plugging by solid sulfur somewhere in the plant, a surge in acid gas flow to the furnace, etc. by activating the SRU1 ESD system before the pressure gets too high. The sensing lines for the pressure transmitters are mounted on the process air line to avoid corrosion and/or plugging with sulfur. The shutdown setpoint is 0.85 kg/cm2(g). Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD.
h.
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Waste Heat Reclaimer A2-LT15401A/B/C
Sulfur Recovery
Low-Low
Water
Level,
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SULFUR BLOCK These devices activate the SRU1 ESD system to prevent the water level from dropping below the top of the cooling pass tubes in this boiler while hot gas is flowing through the tubes. Hot furnace combustion gas flows inside the tubes and will destroy these tubes if they are not cooled by water boiling outside the tubes. These devices are set to actuate if the level falls to within 75 mm of the top of the cooling pass tubes. Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD. i.
Reactor 1st Bed A2-TT15419A/B/C
Outlet
High-High
Temperature,
These devices shut down the Train 1 SRU if a temperature of 400°C or higher is measured at the outlet from the first catalyst bed in the Reactor. Such a temperature would indicate a sulfur fire inside this catalyst bed, which could cause damage by overheating the equipment if allowed to continue burning. Free oxygen can leave the Reactor Furnace and reach this catalyst bed if burner performance becomes poor due to burner damage, low H2S concentration in the acid gas, etc. Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD. j.
Sulfur Condenser Low-Low Water Level, A2-LT15431A/B/C These devices activate the SRU1 ESD system to prevent the water level from dropping below the top of the condensing pass tubes in this boiler while hot gas is flowing through the tubes, thereby averting high effluent temperatures and higher than normal tube wall temperatures. High effluent temperatures would result in lower sulfur recovery due to insufficient condensing of liquid sulfur, and high tube wall temperatures could possibly damage the tubes due to differential expansion. These devices are set to actuate if the level falls to within 75 mm of the top of the condensing pass tubes. Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD.
k.
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Neither Warmup A2-ZSC15454
Bypass
Sulfur Recovery
Valve
Closed,
A2-ZSC15441,
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SULFUR BLOCK Amine acid gas or SWS gas should not be fed to the Train 1 SRU if its warmup bypass line to the TTO is in use. Otherwise, very high concentrations of H2S would be sent to the TTO, possibly leading to a high-high temperature S/D of the TTO and venting of un-combusted H2S to the atmosphere. The "closed" limit switches on the warmup bypass valves (A2-HV15441 and A2-HV15454) must indicate that at least one of these valves is closed, or the SRU1 ESD system will be activated. Note that the SRU1 ESD system is not to be activated if the Train 1 SRU is firing supplemental fuel gas in its Acid Gas Burner. The amine acid gas and SWS gas shutdown valves, A2-HV15320 and A2-HV15331, respectively, are to be closed automatically and an alarm is to be generated, but the ESD system is not to be activated since the Train 1 SRU can continue to fire on fuel gas through its warmup bypass line. Example logic to accomplish this is shown below:
l.
Pilot Ignition Safety Interlock Timer Expired, BMS logic Once the pre-ignition steps have been completed and the BMS gives a "PERMIT TO IGNITE" for the pilot burner in the Acid Gas Burner (signaled by illuminating status indicator light A2-AL15394 on the local Train 1 SRU control panel), an ignition safety interlock timer is started in the BMS. If an ignition attempt is not made within 5 minutes, the SRU1 ESD system will be activated to shut down the sulfur plant. This prevents a potentially unsafe condition from persisting, where a leaking fuel gas valve could cause an explosive mixture to form in the
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SULFUR BLOCK Reactor Furnace, since the air flow is low at this point in the startup procedure. 9.5.8.2
Effects An SRU1 ESD shutdown, activated either manually or automatically, has the following effects on the Train 1 Sulfur Recovery Unit:
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a.
Shuts off the amine acid gas flow to the Acid Gas Burner by closing the acid gas shutdown valve, A2-HV15320.
b.
Shuts off the SWS gas flow to the Acid Gas Burner by closing the SWS gas shutdown valve, A2-HV15331.
c.
Shuts down the Process Air Blower, A2-GB1530A/B.
d.
Closes the air blower suction valves, A2-FV15333A/B, to prevent possible venting of any hazardous gases to the atmosphere.
e.
Closes the air blower discharge valves, A2-FV15334A/B, to prevent back-flow and possible venting of any hazardous gases to the atmosphere.
f.
Closes the air blower vent valves, A2-FV15335A/B, to prevent possible venting of any hazardous gases to the atmosphere.
g.
Initiates the Train 1 SRU Fuel Gas Burner Shutdown system, which performs the following actions: (1)
Shuts off and depressurizes the main fuel gas supply by closing block valves A2-NV15357 and A2-NV15359 and opening vent valve A2-NV15358.
(2)
Shuts off the pilot air supply by closing block valve A2-NV15367.
(3)
Shuts off and depressurizes the pilot fuel gas supply by closing block valves A2-NV15363 and A2-NV15365 and opening vent valve A2-NV15364.
(4)
De-energizes the ignition system, A2-BX15368.
(5)
Begins purging the pilot burner with nitrogen by opening block valve A2-HV15381.
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SULFUR BLOCK (6)
Begins purging the warmup burner with nitrogen by opening block valve A2-HV15382.
h.
Sends the Train 1 SRU S/D status to the TGCU ESD system. (The TGCU ESD system will shut down the TGCU if neither SRU is running and the TGCU is not in "startup" mode.)
i.
Cancels the "slow transfer over-ride" switch in the DCS, A2-HS15464, for the tailgas valves.
j.
Initiates purging of the Acid Gas Burner, A2-BA1531, and the Reactor Furnace, A2-BA1530, with nitrogen by opening block valve A2-KV15377 for 5 minutes.
When the amine acid gas flow to the Train 1 SRU is blocked, the pressure control system on the stripper in the upstream ARU should automatically divert acid gas to the flare as required. When the SWS gas flow to the Train 1 SRU is blocked, the pressure control system on the stripper in the upstream SWS should also automatically divert SWS gas to the flare as required. 9.5.8.3
Non-ESD Shutdowns and Alarms In addition to the devices listed in Section 9.5.10.1 that activate the SRU1 ESD system, there are several interlocks of significance that either generate an alarm or shut down an individual piece of equipment. These devices/interlocks and their effects are described in this section. a.
SWS Gas Scrubber High-High Liquid Level, A2-LT15325A/B/C These devices prevent liquids in the SWS Gas Scrubber from flowing into the hot combustion chamber of the Reactor Furnace and causing an explosion by closing the SWS gas shutdown valve. They are set to actuate if the liquid level reaches 1,490 mm above the bottom seam of the vessel. Note that there are three independent transmitters and 2oo3 voting logic is used for the S/D. Unlike the level transmitters on the Acid Gas Scrubber, this interlock does not activate the SRU1 ESD system. Instead, it closes only the SWS gas shutdown valve, A2-HV15331, to stop the flow of SWS gas. This valve does not re-open automatically when the level drops down and the shutdown
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SULFUR BLOCK resets. The plant operators must use A2-HIC15331 on the local control panel to open A2-HV15331 to reintroduce SWS gas into the SRU in a controlled fashion. b.
Process Air Blower Operation while in "Startup" Mode During normal operation, activating the SRU1 ESD system will shut down the Process Air Blower and close the suction, discharge, and blow-off valves on the blower. However, if the Train 1 SRU is firing on fuel gas through its Warmup Bypass Valves, the air blower will remain running (with its valves open) if the "flame failure" S/D (see Section 9.5.10.1.f) is tripped or one of the fuel gas pressures is not satisfied (see Sections 9.5.8.3.c and 9.5.8.3.d) All other shutdown devices (see Section 9.5.8.2) go to their shutdown positions. By leaving the air blower running when a fuel gas flame is lost, fewer blower restarts are necessary while re-lighting the burner, resulting in less "wear and tear" on the large motors driving these blowers.
c.
Acid Gas Burner Fuel Gas Supply Low-Low Pressure, A2-PT15354 During warmup while the Train 1 SRU is firing on fuel gas, loss of the fuel gas supply would cause the fuel gas pressure to drop. This device will shut off the fuel gas to the Acid Gas Burner before flame instability creates the potential for an explosion. The shutdown setpoint is 0.35 kg/cm2(g). Note that if the Train 1 SRU is firing on acid gas, the transmitter only activates the Train 1 SRU Fuel gas Burner Shutdown system (pilot fuel gas and main fuel gas), so the Train 1 SRU will continue running on acid gas. If, however, the Train 1 SRU is firing only fuel gas (as indicated by its acid gas firing selector switch, A2-HS15315, being set to "DISABLED"), the SRU1 ESD system is activated and the low-low pressure is reported to the "first out" alarm logic. Example logic to accomplish this is shown below:
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d.
Acid Gas Burner Fuel Gas High-High Burner Pressure, A2-PT15361 During warmup while the Train 1 SRU is firing on fuel gas, malfunction of the fuel gas pressure control could cause excessive firing of the warmup burner in the Acid Gas Burner. This device will prevent this unsafe condition by shutting off the fuel gas to the Acid Gas Burner. The shutdown setpoint is 3.5 kg/cm2(g). Note that if the Train 1 SRU is firing on acid gas, the transmitter only activates the Train 1 SRU Fuel gas Burner Shutdown system (pilot fuel gas and main fuel gas), so the SRU will continue running on acid gas. If, however, the Train 1 SRU is firing only fuel gas (as indicated by its acid gas firing selector switch, A2-HS15315, being set to "DISABLED"), the SRU1 ESD system is activated and the high-high pressure is reported to the "first out" alarm logic, as shown by the example logic for the previous item.
e.
Complete Flowpath Interlock (see Logic Flow Diagrams for the limit switch tag numbers) In order for the Train 1 SRU to operate without over-pressuring its drain seals, there must be a complete flowpath from the SRU to the TTO. The ESD logic can determine whether such a complete flowpath exists by examining the status of the limit switches on the process gas valves. There are basically three different paths that the Train 1 SRU can take to reach the TTO:
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SULFUR BLOCK (1)
Both of its Warmup Bypass Valves, A2-HV15441 and A2-HV15454, are fully open to the TTO.
(2)
Its manual tailgas block valve, A2-HV15455, and its Tailgas Valve to the TTO, A2-HV15457, are both fully open to send the tailgas directly to the TTO.
(3)
Its manual tailgas block valve and its Tailgas Valve to the TGCU, A2-HV15462, are both fully open and the TGCU Complete Flowpath Interlock is satisfied, allowing the tailgas to flow through the TGCU and then to the TTO.
If the "open" limit switches do not indicate that at least one of these flowpaths is valid, the "complete flowpath interlock" alarm is activated. However, the SRU1 ESD system is not activated by this interlock. Because this interlock depends on a number of valve limit switches to determine whether a complete flowpath exists, there is always the potential for spurious "trips" even though all of the valves are actually in the proper positions. Since the SRUs are already protected against over-pressure (see Section 9.5.10.1.g), this interlock will alarm in the DCS (A2-QA15458) but is not included in the ESD. To prevent releasing excessive amounts of hazardous gases to the atmosphere from the TTO and/or possibly damaging the Thermal Oxidizer, the interlocks for the Train 1 SRU require that at least one of its Warmup Bypass Valves be closed before opening A2-HV15320 or A2-HV15331 and admitting amine acid gas or SWS gas, respectively, to the Train 1 SRU. Therefore, its Tailgas Valve to the TTO, A2-HV15457, must be open before closing its Warmup Bypass Valves when switching from fuel gas firing to acid gas firing. When the TGCU is already on-line processing tailgas from one of the SRUs, switching the tailgas from the other SRU into the TGCU requires gradually diverting its tailgas from the TTO to the TGCU. For the Train 1 SRU, this requires "throttling" both tailgas valves, A2-HV15457 and A2-HV15462, at the same time to make the switch without upsetting the TGCU. When throttling the tailgas valves in this manner, the limit switches on the valves will be indicating that neither of the tailgas valves is fully open, so the Complete Flowpath Interlock Issued 30 August 2011
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SULFUR BLOCK logic will not be satisfied for the Train 1 SRU. For this reason, there is a "slow transfer over-ride" switch in the DCS, A2-HS15464. When this switch is toggled to "OVER-RIDE", the limit switches on the two tailgas valves are ignored by the Complete Flowpath Interlock logic until the DCS operator finishes routing the Train 1 SRU tailgas into the TGCU to deactivate the over-ride. During this time, the DCS operator is responsible for ensuring that there is always a complete flowpath for the Train 1 SRU.
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9.6
Process Principles and Operating Techniques The more important considerations involved in startup, operation, shutdown, maintenance, and emergency procedures for the Sulfur Recovery Units are discussed in the remaining sections of this portion of the operating guidelines. The operator should also be thoroughly acquainted with the equipment and the "Process Description" section in these guidelines before attempting to operate the plant in accordance with the operating techniques that follow. If the function of each portion of the plant equipment is understood, the sequence of steps outlined in the "procedures" sections will be more easily understood. In addition, the following general discussion of principles and techniques will clarify the reasons for some of the procedures.
9.6.1
Equipment Damage The refractory installed in the Reactor Furnaces can be damaged by too rapid heating or cooling. The Initial Cure and Normal Warmup schedules for the refractory should be provided by the refractory vendor. These schedules should be adhered to quite closely. After the initial startup, the sulfur plants will contain some sulfur throughout the system, and especially in the catalyst beds. Sulfur fires will ignite at temperatures as low as 150°C if sufficient oxygen is available. For this reason, it is very important to minimize the time periods when air (or combustion gas containing oxygen) is routed through the catalyst beds. Localized temperatures in excess of 150°C can exist in a catalyst bed even though the temperatures measured around the Reactor are less than 150°C. Because of this, sulfur ignition sometimes occurs in the catalyst beds when it is not anticipated by temperatures that are readily available for observation. Under ordinary circumstances, the only time when oxygen-bearing gases will be flowing through a Reactor is during the transition when switching from firing fuel gas for warmup to firing acid gas. During this time, observe the Reactor temperatures frequently. If the temperatures are rising more than 5°C to 10°C in a 30 minute period after the temperatures have reached 200°C, then there is possibly a fire present. The high temperature shutdown on the outlet of the first catalyst bed in each SRU will protect that SRU against excessive temperatures in its piping; however, localized excessive temperatures can occur in the catalyst beds prior to being indicated in the Reactor outlet lines. Steps should be taken to prevent the temperatures rising high enough to activate the shutdown
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SULFUR BLOCK as it will require some time to cool down the hot spot before proceeding with startup. Do not use water to quickly cool a Reactor after a fire. Not only will this damage the catalyst, the rapid cooling may cause structural damage to the Reactor. The acidic water that forms may cause corrosion damage to the Reactor or other equipment. Nitrogen is available in each SRU for use in cooling a hot catalyst bed. Explosive mixtures of air (oxygen) and gases in the equipment are a potential danger. During an automatic shutdown all air, oxygen, fuel gas, and acid gas flows are shut off simultaneously. Any malfunction of these devices could leak an explosive mixture into the unit. For this reason, the PLC requires purging of the Reactor Furnace before attempting pilot ignition, and requires re-purging the furnace if the burner does not light but fuel gas was admitted.
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CAUTION NEVER "HYDROBLAST" THE TUBES (OR ANY OTHER STEEL SURFACES) IN THE SULFUR PLANT EQUIPMENT. NOT ONLY DOES THIS REMOVE THE PROTECTIVE SULFIDE FILM THAT FORMS ON CARBON STEEL AND PREVENTS CORROSION, THE WATER WILL REACT WITH THE SULFUR COMPOUNDS PRESENT IN THE EQUIPMENT TO FORM A VARIETY OF ACIDS (SULFUROUS, POLYTHIONIC, ETC.) THAT RAPIDLY CORRODE THE STEEL. THERE HAVE BEEN NUMEROUS INSTANCES OF SULFUR PLANT BOILERS BEING BLASTED DURING A TURNAROUND TO CLEAN THEM UP, THEN HAVING THE TUBES BEGIN LEAKING AS SOON AS THE BOILER IS RETURNED TO SERVICE. IF THE BOILER TUBES HAVE BECOME PLUGGED, THE BEST WAY TO CLEAR THE TUBES IS TO MECHANICALLY "ROD" THEM. IT IS OFTEN HELPFUL TO APPLY HEAT TO THE TUBES BEFORE "RODDING", AS THIS WILL MELT ANY SULFUR THAT MAY BE PART OF WHAT HAS PLUGGED THE TUBES. ONE WAY TO DO THIS IS TO DRAIN THE WATER FROM THE BOILER AND PUT STEAM ON THE SHELL, THEN DRAIN THE CONDENSATE PERIODICALLY TO KEEP LIVE STEAM ON THE TUBES.
9.6.2
Cold Catalyst Bed Startup Each sulfur plant is designed to be started up without first warming the Reactor catalyst. In the cold bed startup procedure, warmup gases are not routed through the Reactor catalyst beds. Fuel gas is burned with excess air on the warmup burner tips of the Acid Gas Burner mounted on each Reactor Furnace. The hot combustion products flow through the Reactor Furnace, through the Waste Heat Boiler tubes and the first condensing pass tubes of the Sulfur Condenser, and then to the warmup bypass line that is upstream of the first catalyst bed. This warms the furnace refractory lining and the process heat exchange surfaces up to normal operating temperatures.
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SULFUR BLOCK The combustion gases are routed to the atmosphere via the Thermal Oxidizer. Therefore, normal operating procedures require that the Thermal Oxidizer also be warming up according to its refractory warmup schedule (or already be on-line) during the period when the SRU(s) is(are) being brought up to operating temperatures. Do not admit acid gas to an SRU until the Thermal Oxidizer is at operating temperature and ready to accept SRU tailgas. The cold bed startup procedure includes the following steps: A.
Open the Warmup Bypass Valves, and close the Tailgas Valve to the Thermal Oxidizer and the Tailgas Valve to the TGCU. Startup cannot be attempted unless this flow path is open.
B.
Ignite the warmup burner in the Acid Gas Burner and fire on fuel gas with excess air, adjusting air and fuel gas rates to follow the appropriate warmup schedule.
C.
Once the Waste Heat Boiler and Sulfur Condenser start to make steam, their back-pressure controllers should be placed in service. The other tube passes in the Sulfur Condenser and the tube passes in the reactor feed heaters will come up to temperature as these boilers begin producing steam.
D.
When the furnace and all process heat exchangers are warmed up to normal operating temperatures and the Thermal Oxidizer is ready to accept SRU tailgas, reduce the fuel gas and air flow rates. Open the Tailgas Valve to the Thermal Oxidizer, then close the Warmup Bypass Valves. Add amine acid gas and reduce fuel gas in equal increments until the fuel gas is shut off.
E.
Gradually admit the full amine acid gas flow rate. Adjust the air flow to the proper air:amine acid gas ratio. Follow the procedures in these guidelines for introducing SWS gas into the SRU. Gradually admit the full SWS gas flow rate and readjust the air:acid gas ratio if necessary.
There are several advantages to using the cold bed startup procedure. First, the catalyst beds are not exposed to warmup gases containing free oxygen. This reduces the chance of fires in the catalyst bed during warmup, which can cause overheating damage to both equipment and catalyst.
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SULFUR BLOCK Second, the catalyst beds are not exposed to warmup gases that contain free carbon (soot). This reduces the chance of contaminating and plugging the beds with soot. Third, the cold bed startup procedure reduces catalyst sulfation and, therefore, keeps the catalyst active longer. Deactivation has been shown to be caused primarily by sulfate contamination of the catalyst surface. Sulfation occurs most readily at conditions encountered during a startup procedure which uses combusted fuel gas for catalyst heating. An additional benefit of having the warmup bypass line is that a sulfur plant can be kept on hot stand-by, firing on fuel gas, without exposing the catalyst beds to overheating, carbon deposition, or sulfation damage. The hot fuel gas combustion products will keep all process heat exchange surfaces at normal operating temperatures. Since most corrosion damage in sulfur plants occurs when the plants are allowed to cool down and stand cold, using the warmup bypass can greatly extend the service life of sulfur plants which require considerable stand-by time.
9.6.3
Sulfur Solidification Sulfur melts at 119°C. All surfaces in the SRUs must be maintained above this temperature during normal sulfur production operating periods. However, temperatures around the Sulfur Surge Tanks and the Sulfur Storage Tank should be kept below 158°C since sulfur undergoes a phase change at this temperature that can result in a tremendous increase in viscosity, which could overload any of the sulfur pumps. Maintaining the steam coil pressure in the Sulfur Surge Tank and the Sulfur Storage Tank at 5.0 kg/cm2(g) or less will ensure that the sulfur does not get too hot. All of the piping and valves in liquid sulfur service are steam-jacketed, as are the valves in sulfur vapor service and the vent stacks on the Sulfur Surge Tanks. The steam traps serving these heating systems should be checked regularly to verify proper operation. The simplest method to do this is to verify that sulfur will melt on the steam trap inlet; if the condensate there is hot enough to melt sulfur, then the steam in the jackets will be hot enough, too. It is also important to periodically sweep the non-condensibles out of the jackets and coils by giving their vent valves a good "blow". This will prevent the accumulation of non-condensibles that could create localized "cold" spots where sulfur can freeze.
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SULFUR BLOCK 9.6.4
Ammonia Salt Formation Hydrogen sulfide reacts with ammonia at low temperature to form ammonium hydrosulfide: NH3 + H2S
NH4HS
If the temperature is low enough, this ammonium hydrosulfide will precipitate as a solid salt. The temperature at which the solid phase will form is a function of the NH3 and H2S concentrations and the gas pressure, but generally ranges from 15°C to 40°C for most acid gas streams. It is recommended that all surfaces in contact with NH3-H2S be maintained 20-25°C above the solid formation temperature, so all of the equipment, piping, and instruments in the SRUs that is exposed to SWS gas are electric traced, steam traced or steam jacketed to keep them above 65°C.
CAUTION
TO PREVENT PLUGGING OF EQUIPMENT, PIPING, OR INSTRUMENTS WITH AMMONIA SALTS, THE TRACING OR STEAM JACKETING IN CERTAIN SECTIONS OF THE SRUS MUST BE LEFT IN SERVICE YEAR ROUND. THESE ARE ANY PIPING, EQUIPMENT AND INSTRUMENTATION IN SWS GAS SERVICE.
Essentially all of the ammonia in the SWS gas will be destroyed in the Reactor Furnace during normal operation. If, however, amine acid gas flow is interrupted (due to upsets in the ARU, etc.) and the SRUs are processing only SWS gas, the ammonia may not be completely destroyed and salts could begin to form in the downstream equipment (particularly the Sulfur Condensers). Loss of amine acid gas flow can also cause excessively high furnace temperatures, poor sulfur recovery, and poor operation or equipment damage in the TGCU or the Thermal Oxidizer downstream. For this reason, the operator must closely observe the SRUs if their amine acid gas flow is interrupted, and be ready to activate the SRU ESD systems if necessary to prevent equipment damage.
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SULFUR BLOCK 9.6.5
Catalyst Fouling The catalyst beds in the Reactors may be severely fouled by carry-over of hydrocarbon liquids or vapors from the ARU and/or Sour Water Stripper Units into the SRUs. This will cause permanent damage to the catalyst and is to be avoided if at all possible, even if shutting down the SRUs for periods is required. The catalyst may also be fouled by passing fuel gas combustion products through the beds when insufficient air to burn all of the fuel gas is being supplied to the Acid Gas Burner. This causes soot (carbon) formation which coats the catalyst and causes loss of activity. The catalyst beds in this plant will be warmed with fuel gas combustion products only during the initial startup. Excess air will be used during this warmup period, so the chances of fouling the catalyst in this manner are remote. The catalyst may also temporarily lose activity due to molten sulfur condensing on the beds. This can be corrected by raising the Reactor inlet temperatures by approximately 15-20°C for a few hours, then readjusting to the normal operating range. The catalyst activity will be completely restored in this manner by re-vaporizing the deposited sulfur. The reactor feed temperatures can be raised by appropriate adjustment of the temperature controllers on the gas outlet lines from the reheat exchangers.
9.6.6
Operation of SRUs in Parallel Train 1 SRU and Train 2 SRU are designed to operate in parallel with each other to provide maximum acid gas processing capacity. The SRUs are connected at their inlets, with the amine acid gas and SWS gas feedstocks split to flow through the units in parallel. Due to the relatively low pressure drops through the SRUs (normally 0.5-0.7 bar(g) at full rates, when the pressure drop of the associated TGCU is included), operating changes in one unit can significantly impact the other units because of the flow hydraulics. The acid gas flow controls for Train 1 SRU and Train 2 SRU are designed to allow automatic operation of the parallel units in a fashion that maximizes processing capacity and maximizes sulfur recovery efficiency. There are two basic schemes for operating SRUs in parallel: "base-load" operation of all-but-one SRU, or "cascade" operation of all SRUs. Each scheme has advantages and disadvantages relative to the other, depending on the operating characteristics of the particular feed units and
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SULFUR BLOCK SRUs, current operating conditions, and other factors. As a result, the choice of which operating mode to use is best determined based on field experience with the specific units. 9.6.6.1
"Base-Load" Operation on All-But-One SRU One operating mode is to "base-load" all but one SRU, and let the remaining SRU take the "swing." That is, the flow controllers are used to feed a fixed quantity of amine acid gas and/or SWS gas to one SRU, while a pressure controller is used to control the feed valves to the remaining SRU (either directly or via setpoint adjustment of the flow controllers). This mode allows one SRU to operate at steady feed rates, but requires that the remaining SRU take all of the variation in the flow of the amine acid gas and/or SWS gas feed to the sulfur facilities. The main advantage of this operating mode is that the "base-load" SRU has very steady feed gas rates, which in turn allows its air:acid gas ratio control scheme to keep the plant trimmed very close to optimum H2S:SO2 ratio under most circumstances. This means that the sulfur recovery efficiency of the "base-load" SRU is generally very high. The primary disadvantage of this operating mode is that the "swing" SRU can see very large fluctuations in its amine acid gas and/or SWS gas feed rates, since this unit has to take all of the flow variation. Consequently, the sulfur recovery efficiency can be considerably lower for this SRU than for the "base-load" unit because the air:acid gas ratio control scheme on the "swing" unit is unable to keep the plant as close to optimum H2S:SO2 ratio, resulting in wider and more frequent deviations from the optimum ratio. The impact of this disadvantage can be minimized if the total amount of acid gas to be processed is less than the maximum capacity of the units. By setting the "base-load" SRU to process its full capacity, a smaller quantity of acid gas will be processed in the "swing" SRU. This means that a larger portion of the total acid gas is processed in the SRU operating at the higher recovery. Depending on the quantity of SWS gas to be processed, it may be possible to send all of the SWS gas to one of the SRUs and process only amine acid gas in the remaining SRU. In this case, the SRU
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SULFUR BLOCK processing the SWS gas would be operated as the "base-load" unit for amine acid gas. This should give steadier operating conditions for this SRU, allowing better sulfur recovery efficiency and more reliable ammonia destruction in the SRU. And, since the "swing" SRU is processing only amine acid gas, its sulfur recovery efficiency will be higher than for a "swing" SRU processing both amine acid gas and SWS gas. The net result may be higher overall sulfur recovery efficiency for the SRUs than if SWS gas was processed in both the units (although this may not always be the case). 9.6.6.2
"Cascade" Operation of All SRUs The other operating mode is to place both the SRUs in "cascade" operation. Rather than feeding a fixed flow rate to one SRU and forcing the remaining SRU to take all of the "swing", the acid gas can be split in relative proportions between the SRUs. As the amount of available acid gas changes, the feed rates to both the SRUs will be adjusted proportionally. This mode spreads the variations in the flow of amine acid gas and/or SWS gas feed between the SRUs so that no unit is experiencing as much change as when operated as a "swing" unit. However, none of the units is operating on steady flow rates, as both the units must absorb the fluctuations in flow from the feed units. The primary advantage of this operating mode is that no SRU is experiencing large variations in feed flow rates, so there is less variation in sulfur recovery efficiency compared to operating as a "swing" SRU. This operating mode is generally also more reliable when the amount of SWS gas to be processed is high enough that both the SRUs must process SWS gas. The main disadvantage of this operating mode is that none of the units is processing at steady feed rates, so neither SRU can maintain its sulfur recovery efficiency as high as it can when operating as a "base-load" SRU. If the feed units are producing acid gas at reasonably steady rates, however, the magnitude of this loss in sulfur recovery efficiency from operating with both the SRUs in "cascade" mode can be relatively minor. The overall sulfur recovery efficiency for the SRUs as a whole will depend on how much acid gas is to be processed, the relative amounts of amine acid gas and SWS gas to be processed, relative catalyst activities within
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SULFUR BLOCK the reactors of the plants, and many other factors. As a result, the choice of which operating mode to use will often depend on the particular circumstances at any given time. As operating experience is gained with the units, past experience will probably serve as the best tool for choosing the operating mode in different situations.
9.6.7
Process air Blower Operation The Process air Blower is actually a multi-stage, low-head, centrifugal compressor. Although this air blower is less complicated to operate than conventional centrifugal compressors (like those used in fuel gas service, for instance), the blower does require some special attention when operating at low flow rates. These cases are discussed in the sections below.
9.6.7.1
Preventing "Surge" in the Process air Blower When centrifugal compressors are operated at low flow rates, they may enter a range of flow instability known as "surge." The startup air flow rate to an SRU is primarily controlled by throttling a valve in the blower suction. This method of flow control is preferred because suction throttling reduces the inlet air density and maintains a higher volumetric flow rate through the blower when the mass flow rate is lower. Because of this effect, the blower should be able to operate down to a lower flow rate before going into surge. Operating experience will establish what the stable operating range is for this blower. The primary indication of blower surge is erratic air flow rate. The first sign of this is usually audible – the check valve in the blower discharge line begins to "clatter." The air pressure gauge on the inlet to the Acid Gas Burner will usually fluctuate rapidly, and the burner flame can often be observed to "puff" back and forth, when the blower is in surge. If the surge is severe enough, it will cause high vibration levels on the blower. If the blower is in surge for an extended period, the blower casing will overheat due to re-circulation of hot air between stages of the machine. Regardless of the symptoms, the result of allowing a blower to operate in surge for long periods of time is physical damage to the blower, either from high vibration or from high temperature. For this reason, do not allow an air blower to remain in surge.
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SULFUR BLOCK To prevent the blower from surging at low flow rates, the discharge piping on each blower has a "blow-off" valve installed. The action of the blow-off valve is controlled by relays in the DCS. When the air flow is low, the PLC will open the blow-off valve and allow some of the air from the blower to vent to the atmosphere, increasing the air flow through the blower to keep it above the surge line. A silencer has been installed in the vent line to reduce the noise level around the blower when the blow-off is used. If the blower is surging, then adjust its blow-off valve to open more until the blower stops surging. It does no harm to open the blow-off more than necessary, although it does waste power by forcing the blower to compress more air than necessary. Adjusting the amount that the blow-off opens is simply a matter of making the appropriate configuration change in the DCS. 9.6.7.2
"Swapping" Process Air Blowers During Operation While a sulfur plant is running, it is often necessary to "swap" air blowers to bring the off-line blower on-line so that the other blower can be shut down. This can usually be accomplished with only a slight "bobble" to the process by starting and stopping the blowers in the proper manner. The procedure given below is one technique for swapping blowers. Since each SRU must remain on-ratio at all times for optimum sulfur recovery, it is important that the air flow to an SRU not be disturbed while swapping blowers. If the air flow fluctuates, the best that can happen is a minor disturbance in air:acid gas ratio and a small drop in sulfur recovery. At worst, the Acid Gas Burner may lose its flame, the SRU will shut down on "flame failure", and the acid gases will be diverted to the flare (a reportable emission episode). The "bias" controllers in the DCS together with the bias and flow control relays in the DCS, are designed to make swapping blowers relatively simple and avoid these problems. One of the complicated aspects associated with swapping blowers is the impact that starting the off-line blower can have on air flow. Each air blower has its own suction valve. Since the DCS will be sending the same control signals to the valves on both blowers, there is a potential to suddenly double the air flow when the off-line blower is first started. This would not only disturb the process, it could possibly blow out the flame in the burner.
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SULFUR BLOCK The bias relays in the DCS allow the DCS operator to slowly ramp up the flow from the off-line blower while ramping down the flow from the on-line blower. Although we have attempted to automate this concurrent ramping operation on a couple of past projects, we have not found this to be very satisfactory. The way that the blower controls need to be ramped will depend on the current plant throughput and whether or not the blower suction valve is still in control of the air flow from the blower. This is classic "fuzzy logic", something that is easy for a human to do but very difficult for a computer. The procedure below describes how to switch an SRU from the "A" blower to the "B" blower. That is, the "A" blower is running to the SRU and the "B" blower is not currently running. The procedure to switch from the "B" blower to the "A" blower in the SRU is similar. Make sure the SRU is operating stably before proceeding. A.
In the DCS, confirm that the “A” blower hand controller is currently set to 100% output so the blower relay is multiplying the signal it receives from the process air flow controller by 1.0 (i.e., no change). (If the setting is not already 100%, slowly increase it to 100% before proceeding, allowing time for the controls to respond.)
B.
Set the “B” blower hand controller in the DCS to 0% output. This means that its relay will be multiplying the signal it receives from the process air flow controller by 0.0, so all of the flow relays for the valves on the “B” blower will be receiving 0% as their inputs. After transformation by the suction, discharge, and vent relays in the DCS, this means that the positioners on the suction valve, discharge valve, and vent valve will be receiving control signals of 33%, 0%, and 100%, respectively.
C.
Switch the process air flow controller to "manual". This ensures that the input to the "bias" relays does not change during the blower swap procedure, so that the DCS operator can see the impact on air flow while adjusting the relays.
D.
On the off-line blower (B), confirm that: (1)
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E.
(2)
Its discharge valve is closed.
(3)
Its blow-off valve is closed.
Start the off-line blower as follows: (1)
Press the local push-button to give the blower a "permit to start" and energize the solenoid valves on its suction and vent valves for 30 seconds.
(2)
Start the blower using its local start/stop control station.
(3)
Once the blower is running, the solenoid valve on its discharge valve is also energized.
The blower suction valve will open 33%, its vent valve will open, and its discharge valve will remain closed. The valves will all return to being closed if the blower is not started before the "permit to start" times out. Since the discharge valve will still be fully closed when the blower starts, there will be no change in the air flow to the SRU even though air will be flowing through the blower. All of the air will be flowing out of the blow-off valve and venting atmosphere. F.
In the DCS, begin to increase the output from the “B” blower hand controller. This will begin to increase the multiplier in the “B” relay from 0.0, and the output to the discharge valve will begin to increase as the output to the vent valve begins to decrease.
G.
Continue to increase the output from the “B” blower hand controller until the “B” blower develops enough discharge pressure to open its check valve and the air flow to the SRU begins to increase. Depending on current operating conditions in the SRU, this may happen as soon as the discharge valve begins to open, or it may not happen until the suction valve begins to open more. Once the discharge check valve on the “B” blower opens, the air flow to the SRU will begin to increase as the “B” blower starts to contribute to the air flow.
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SULFUR BLOCK H.
Begin to decrease the output from the “A” blower hand controller. This will begin to reduce the multiplier in “A” relay from 1.0 and begin to reduce the flow from the “A” blower. Depending on current operating conditions in the SRU, this may be due to throttling the suction valve more, or may be due to closing of the discharge valve.
I.
Continue to increase the output from the “B” blower hand controller and reduce the output from the “A” blower hand controller as necessary to control the air flow, until the “B” blower hand controller has 100% output and the “A” blower hand controller has 0% output. This will increase the air flow from the “B” blower and reduce the air flow from the “A” blower until all the flow to the SRU is from the “B” blower and the “A” blower is just venting air to the atmosphere.
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J.
Switch the air flow controller back to "automatic".
K.
Shut down the “A” blower using the local start/stop control station.
L.
The blower swap is now complete. Before leaving the area, visually confirm that: (1)
The off-line blower is stopped.
(2)
The suction, discharge, and v valves on the off-line blower are closed.
(3)
The on-line blower is running smoothly.
(4)
The process has returned to steady operation.
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SULFUR BLOCK 9.6.8
Reactor Furnace Temperature Each Reactor Furnace is designed to destroy the ammonia contained in the SWS gas feed by maintaining a high-temperature, reducing atmosphere in the front zone of the furnace. In order to control the temperature in the front zone of the furnace, a portion of the amine acid gas bypasses the Acid Gas Burner and flows to side injection ports on the Reactor Furnace, where the bypass gas mixes with the burner combustion products as they enter the second zone of the furnace. If less of the amine acid gas is routed to a burner, a greater portion of the H2S fed to that burner is actually combusted, raising the flame temperature and increasing the temperature in the front zone of that furnace. If more amine acid gas is routed to a burner, a smaller fraction of the H2S entering that burner is combusted, lowering the temperature in the front zone of that furnace. The amount of amine acid gas that is fed to the burner in the SRU is controlled using the flow ratio controller in the DCS to adjust bypass gas control valve to regulate the amine acid gas flowing to the side injection ports on its furnace (the bypass gas flow rate). In theory, the optical pyrometer mounted on the side of the furnace should measure the temperature inside the first zone of the Reactor Furnace and make appropriate adjustments to the bypass gas flow by changing the ratio setting on the flow ratio controller to control the desired temperature. In practice, however, the temperatures measured by optical pyrometers on similar furnaces have often given erratic responses to process changes. It is suspected that the cool bypass gas entering the side injection ports is influencing the temperature measurement, either due to a cooling effect on the refractory as the gas flows through the openings in the lining, or due to back-mixing caused by eddies arising from the "jet" effect of the combustion products leaving the Acid Gas Burner. If the temperature response of the pyrometers does prove to be unreliable, then the bypass gas ratio can be used for control purposes instead. The graph below shows the bypass gas ratio as a function of the ratio of SWS gas flow to amine acid gas flow. The bypass gas ratio is the amine acid gas bypassing the burner as indicated in the DCS versus the total amine acid gas as indicated in the DCS. Combustion of the ammonia in the SWS gas is very exothermic, so less of the amine acid gas must be bypassed to maintain the same front zone temperature as the ratio of SWS gas to amine acid gas increases.
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SULFUR BLOCK 0.215
0.214
0.213
Bypass Gas Ratio, Nm3/Nm3
0.212
0.211
0.210
Design Point (Normal Operation)
0.209
0.208
0.207
0.206
0.205 0.00
0.01
0.02
0.03
0.04
0.05
SWS Gas:Amine Acid Gas Ratio, Nm3/Nm3
The setpoint for the flow ratio controller can be set by the operator using the graph above. When operating in this mode, the temperature indicated on the optical pyrometer can be monitored to determine if changes to the setpoint on the flow ratio controller are necessary. If the temperature reading is lower than normal, raise the setpoint on the flow ratio controller to bypass more amine acid gas around the burner and raise the temperature. If the temperature reading is higher than normal, lower the setpoint on the flow ratio controller to bypass less amine acid gas around the burner and bring the temperature down. If field experience shows that the temperature measurement of the optical pyrometers on these SRUs will give acceptable control. Placing the flow ratio controller in "cascade" will allow the temperature controller to adjust its ratio setpoint, so that the amount of bypass gas is controlled appropriately with the flow ratio controller. Whether the bypass gas ratio is controlled directly or is set by the action of the temperature controller adjusting the bypass gas ratio, the following considerations apply to the bypass gas flow rate:
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SULFUR BLOCK (7)
The total bypass acid gas flow rate should never be allowed to exceed 67% (i.e., ⅔) of the total amine acid gas flow rate, as this will ensure that at least ⅓ of the total acid gas feed is always flowing to the burner regardless of the SWS gas flow rate. If less that ⅓ of the total H2S is fed to the burner, all of the oxygen in the process air fed to the burner may not be consumed. If this happens, free oxygen may enter the downstream catalyst beds and catch them on fire, leading to catalyst (and possibly equipment) damage.
(8)
65% is the recommended maximum bypass acid gas ratio to allow a safety margin for flow measurement errors, slow control response, plant upsets, etc.
(9)
It is always desirable to minimize the bypass acid gas ratio, as sending more of the amine acid gas feed to the burner means less chance of contaminating the downstream catalyst beds with hydrocarbons or carbon. Even the best-run amine systems will always pick up small amounts of hydrocarbon, which can subsequently contaminate the catalyst beds. Hydrocarbon fouling is the most common cause of poor catalyst life in refinery sulfur plants.
(10) The pressure drop through the Acid Gas Burner is the driving force that allows the bypass gas control valve to bypass part of the amine acid gas around the burner and into middle of the furnace instead. When the SRU is operating at low flow rates, there may not be enough pressure drop through the burner to give good control of the bypass acid gas. In such cases, the flow ratio controller will "pinch" the control valve in the acid gas line to the burner, increasing the pressure drop available for the bypass gas control valve. The DCS relay is designed to limit the output to the control valve in the acid gas line to the burner so that this valve is never completely closed. There should always be at least ⅓ of the amine acid gas flowing to the burner to be sure that the front zone of the Reactor Furnace does not begin to operate in an oxidizing atmosphere. (11) When an SRU is not processing SWS gas, it is not necessary to bypass any amine acid gas around its burner. When operating in this mode, place the flow ratio controller in "manual" and set its output to 0% to fully close the bypass gas control valve and send all the amine acid gas to the burner. With all of the amine acid gas
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SULFUR BLOCK flowing through the burner, it is less likely that hydrocarbons in the acid gas will leave the furnace un-combusted, so there is less chance of fouling the downstream catalyst beds.
WARNING
IT IS POSSIBLE FOR THE SIDE INJECTION PORT NOZZLES ON A REACTOR FURNACE TO OVERHEAT IF THERE IS NO BYPASS ACID GAS FLOWING THROUGH THE NOZZLES. ALTHOUGH THE HOT FURNACE GASES SHOULD NOT "BACK" INTO THE NOZZLES, THE INTENSE RADIANT HEAT FROM THE HOT FURNACE INTERIOR MAY CAUSE OVERHEATING OF THE NOZZLES. TO PREVENT ANY SUCH OVERHEATING, THE NITROGEN PURGE FOR THE INJECTION PORTS SHOULD BE PLACED IN SERVICE WHENEVER THERE IS NO BYPASS ACID GAS FLOW.
9.6.9
Ammonia Destruction Considerations It is generally accepted within the industry that sulfur plants processing ammonia-bearing streams (sour water stripper off-gas, for instance) must be designed to destroy essentially all of the ammonia, probably down to PPM levels, to avoid plugging with ammonia salts in the downstream equipment. For this reason, many sulfur plant designers impose upper limits on the ratio of SWS gas to amine acid gas to ensure successful operation of their SRUs. We do not believe this is necessary, however, if the reactor furnace is designed for ammonia destruction in a reducing atmosphere like the furnace in this SRU is. Years ago, ammonia was destroyed in one section of a reactor furnace by literally burning it in the presence of excess air. A notable number of undesirable side effects result when the ammonia is destroyed in this oxidizing atmosphere, as a significant amount of sulfur trioxide (SO3) is formed in this oxidizing step since the ammonia-bearing feed stream also contains sulfur compounds. This SO3 can cause significant problems throughout the process. First, it readily reacts with any free ammonia
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SULFUR BLOCK throughout the process to form heat-stable salts that deposit and accumulate. (Frequently, small amounts of ammonia enter the process in the amine acid gas stream to participate in this salt accumulation problem.) Second, the SO3 can react with the Claus catalyst surface to form sulfate salts that deactivate the catalyst. Third, the SO3 can condense on and corrode the cooler surfaces in the unit very rapidly during upset periods. Fourth, the SO3 absorbs in the sulfur product and causes it to be corrosive. As these problems were diagnosed and studied, Amoco and others discovered and demonstrated that the ammonia could be successfully destroyed in a Claus SRU by thermal decomposition in a reducing atmosphere. This process change essentially eliminated the formation of SO3 in the unit. Amoco found that large quantities of ammonia could be destroyed in a reducing atmosphere at elevated temperatures, and obtained patents covering this mode of operation in 1973. As Amoco licensees, our SRUs are designed for reducing-atmosphere ammonia destruction in a two-zone reactor furnace, with careful attention to controlling the front zone temperature at or above 1370°C to ensure near complete ammonia destruction. Surprisingly, though, we have found that our clients do not always operate our SRUs in strict accordance with the published operating procedures regarding such matters as minimum furnace temperature, feedstock ratios, etc. In fact, some of our clients have operated their SRUs on just sour water stripper off-gas for days at a time because of operating problems in the amine unit. Although there was undoubtedly ammonia escaping from the furnace when operated in this manner, there has never been any plugging with salts during this time. This has led us to conclude that avoiding SO3 formation, not complete ammonia destruction, is the critical element in the reliability of our reducing-mode SRUs. If you examine the melting points of the various salts that can result from ammonia and the sulfur compounds that might be found in a sulfur plant, only ammonium sulfate, (NH4)2SO4, has a melting point that is higher than the freezing point of sulfur. Since all of the surfaces in a sulfur plant must be maintained above the sulfur freezing point, none of the other salts can precipitate under normal operating temperatures. Thus, as long as the furnace is operated in a reducing atmosphere so that there is no SO3 to combine with water and the
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SULFUR BLOCK residual ammonia to form ammonium sulfate, salt precipitation should not occur in the SRU. Since these SRUs are followed by an amine-based tailgas cleanup unit, though, there will be cooler pieces of equipment downstream of the SRU. However, the first cool section is the quench water system in the TGCU, which will easily scrub the ammonia from the gas streams since ammonia dissolves readily in water. Because this serves to raise the pH of the quench water and counteract the drop in pH as H2S, CO2, and trace quantities of SO2 dissolve in the water, this ammonia is actually beneficial to the process. Depending on the amount of ammonia in the gas, some may escape from a quench tower and dissolve in the downstream amine solution, but periodically purging a small amount of water from the stripper reflux system will prevent the ammonia from concentrating enough to cause salt problems.
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SULFUR BLOCK 9.6.10
Sulfur Recovery Efficiency The sulfur recovery efficiency of an SRU depends on a number of factors. These sulfur plants are designed to achieve an average sulfur recovery of at least 94-96%, but should be capable of recoveries somewhat higher than this. Operator attention to the following aspects of sulfur plant operation will ensure consistently good recovery levels in these SRUs.
9.6.10.1
H2S:SO2 Ratio Maximum sulfur recovery is obtained when the H2S to SO2 ratio in the process gas upstream of the first catalyst bed is exactly 2:1. It is virtually impossible to maintain this exact ratio, but efforts should be made to control near 0% air demand on the air demand analyzer. For instance, the changing air temperature and relative humidity between day and night will cause some variation in the air flow rate, resulting in variations in percent air demand (a function of the H2S:SO2 ratio). The air demand analyzer will continuously analyze the process gas and calculate the percent air demand, allowing the air demand controller to automatically trim the air:acid gas ratio to stay close to a 2:1 H2S:SO2 ratio. If the analyzer is out of service or needs to be checked, the procedures in Section 9.10 of these guidelines can be used to manually sample the process gas and determine the H2S:SO2 ratio, so that the appropriate change can be made to the air:acid gas ratio.
9.6.10.2
Reactor Feed Temperatures The optimum feed temperature to a Claus reactor is a complex function of several factors, which often have conflicting effects on overall sulfur recovery. Some general guidelines used by sulfur plant designers are:
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(1)
Catalytic conversion temperatures.
is
(2)
Hydrolysis (conversion) of organic sulfur compounds (such as COS and CS2, which are formed by side reactions in the Reactor Furnace) back into H2S is favored by higher operating temperatures.
Sulfur Recovery
favored
by
lower
operating
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SULFUR BLOCK (3)
Liquid sulfur will be adsorbed in the catalyst pores (rendering the catalyst temporarily inactive) if the reactor operating temperature is too close to the sulfur dewpoint.
These factors were carefully considered when these SRUs were designed and the temperatures shown on the process flow diagram were chosen, but provisions have been included to control and/or change these temperatures. If desired, the optimum reactor feed temperatures can be determined for the actual operating conditions by making changes and observing whether the amount of sulfur in the tailgas goes up or down. The H2S and SO2 concentrations in the SRU tailgas indicated by the air demand analyzer for the SRU in question will give a direct indication of whether the sulfur recovery has improved (i.e., a lower total concentration for the two) or suffered (i.e., a higher total concentration for the two) when a change is made. The sulfur recovery is affected by the catalyst bed feed temperatures. Maximum sulfur recovery is usually obtained when the catalyst bed inlet temperatures are controlled at the lowest level that will allow the reaction to continue. The feed temperatures must be sufficiently high to prevent catalyst deactivation due to condensation and deposition of liquid sulfur on the catalyst. The catalyst bed feed temperatures should be controlled at 230°C or higher during startup periods, and during other periods of upset or unusual operating conditions. Calculations indicate that catalyst bed feed temperatures may be reduced to 200-210°C or slightly lower during periods of stable operation without causing problems, particularly in the second and third catalyst beds. However, lowering the feed temperature to the first catalyst bed may not increase recovery, due to lower hydrolysis of organic sulfur compounds in this catalyst bed. Calculations indicate that the optimum sulfur recovery for these SRUs is obtained then the first catalyst bed is operated at high temperature, due to the higher conversion of the organic sulfur compounds to H2S, which is subsequently recovered in the downstream catalyst beds. As shown on the Process Flow Diagram, the feed temperature to the first catalyst bed will normally be around 225-235°C. Operating experience will show whether lower reactor outlet temperatures still
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SULFUR BLOCK give satisfactory performance with the catalyst used in this catalyst bed.
9.6.11
Operation at Low Flow Rates Generally speaking, most sulfur plants can operate down to about 20-25% of design throughput without much loss in recovery efficiency and without requiring much operator attention. This is often referred to as the turndown range or turndown ratio of the plant. Turndown to 20-25% of design rate corresponds to a turndown ratio of 5:1 to 4:1. When an SRU must operate at rates lower than 20-25% of design, there are several operating problems that often occur. These problems, and ways to solve them, are discussed below.
9.6.11.1
Loss of Sulfur Recovery Efficiency The H2S:SO2 ratio in the process gas is the single factor that most affects sulfur recovery. This ratio is a function of the air:acid gas flow ratio. At low flow rates, the flow meters on the amine acid gas, SWS gas, and process air become less accurate, due to the low differential pressures the flow transmitters must measure. This loss of accuracy in measuring the flows to the SRU reduces the effectiveness of the feed-forward part of the air ratio control loop, requiring the feed-back part of the loop (the Air Demand Analyzer) to make bigger corrections to try to keep the H2S:SO2 ratio at 2:1. The result is a loss in recovery because the H2S:SO2 ratio oscillates more widely from the optimum 2:1 ratio. This poor sulfur recovery performance due to flow meter limitations can be corrected by adjusting the flow meters for the lower rates. Depending on the particular circumstances, this can be accomplished in a number of ways: (4)
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If the SRU must operate at low flow rates permanently, or for long periods of time, installing new orifice plates with smaller bores may be an attractive solution. This will increase the differential pressures measured by the meters to put the flow transmitters back into good operating ranges. The disadvantages of this technique are that a plant shutdown is required to make the change, and that the plant cannot operate at high flow rates again without changing orifice plates.
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SULFUR BLOCK
9.6.11.2
(5)
If the SRU must operate at low flow rates temporarily, re-calibrating the flow transmitters to span lower differential pressure ranges may be a better method since this change can be made while the plant is running. In fact, with "smart" transmitters and the required I/O modules in the DCS, this change can be made from the control room.
(6)
If the SRU must operate at variable flow rates, using dual flow transmitters calibrated for low and high differentials can provide accurate flow measurement over a much wider range. With proper programming in the DCS, the dual transmitters allow "seamless" metering of the flow.
Deactivation of Catalyst Beds by Sulfur "Fog" As a sulfur condenser is operated at lower and lower rates, it reaches a point where the bulk gas cooling rate caused by radiation and conduction heat transfer exceeds the dewpoint reduction rate caused by sulfur condensation on the tube walls. Instead of condensing along the walls of the tubes, sulfur begins to condense into tiny droplets out in the gas. Due to the low flow rates, there is not enough turbulence in the gas to make the droplets coalesce along the tube walls. The droplets come out of the tubes as a "fog" that cannot be removed in the downstream separator section, and are carried over into the reactor feed heaters. The feed heaters cannot vaporize all of the carry-over liquid sulfur, probably because the small surface area of the droplets (relative to their volume) causes slow mass transfer of vaporized sulfur away from the droplets that impedes heat transfer. This causes the liquid sulfur droplets to enter the reactor catalyst beds. The liquid sulfur is then adsorbed into the pores of the catalyst where it blocks the active sites, rendering the catalyst inactive. The catalyst activity can be restored by raising the reactor feed temperature and vaporizing the liquid sulfur out of the pores, but this can be very hard to do when the condensers are carrying over liquid sulfur. The symptom of sulfur carry-over into the catalyst beds is a gradual decline in the temperature rises across the beds. Since the Claus reaction is exothermic (heat releasing), the catalyst bed T is a direct indication of the amount of reaction occurring. As the liquid sulfur
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SULFUR BLOCK deactivates the catalyst, there will a gradual decrease in the reactor bed temperatures, starting at the top and moving downward. Experience has shown that when the condenser passes begin to fog, the liquid sulfur will accumulate in the outlet channels of the heating passes in this style of sulfur plant. Due to the arrangement of these "package" sulfur plants, the heating pass outlet channels are low spots in the flow paths from the condenser outlets to the reactor inlets. It is believed that as the gas flowing out of the heating pass tubes turns 90° to exit through the channel outlet nozzles, centrifugal force causes the sulfur droplets to impinge upon the endplates of the channels with enough force to make the small droplets coalesce into droplets too large to leave with the gas. Over a period of time, sulfur will accumulate to the point where it begins to cause fluctuations in the operating pressure of the affected SRU. The pressure drop will build up enough to "lift" some of the sulfur into the downstream catalyst bed, at which point the pressure drop will immediately become much lower. These SRUs have been designed to take advantage of this phenomenon and drain the liquid sulfur out of the reheat passes before it builds up enough to cause pressure drop problems and be carried into the Reactor. Each heating pass outlet channel has a steam-jacketed sulfur drain valve on it. The drain valves are connected together in a steam-jacketed line that is connected to the cooling pass outlet line. At low flow rates, the pressure drop through an SRU is very low, so the static head of the accumulated liquid sulfur is enough to cause the sulfur to drain into the cooling pass outlet line, where it can flow into the first condensing pass and then drain into the Sulfur Collection Header. If sulfur carry-over is suspected (due to a gradual decline in Reactor bed temperatures or because of SRU pressure fluctuations), these drain valves can be used to drain sulfur from the heating passes by opening them periodically to allow the sulfur to drain. Open each drain valve, one at a time, for one or two minutes, then close the valve. Do this every 4 to 8 hours, using the Reactor bed temperatures as an indication of whether to use the drains more or less frequently. Do not leave the drain valves open. Once the sulfur has drained out of the heating pass channels, hot gas from the cooling pass outlet will flow back up the drain line and disturb the
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SULFUR BLOCK operation of the downstream catalyst beds if the drain valves are left open. 9.6.11.3
Loss of Steam Pressure in Boilers The heat released in the tubes of the Waste Heat Boiler is proportional to the amount of feed gas processed. At very low flow rates, generally less than 10% of the original design, the heat loss to the surroundings can be more than this heat release, to the point where the Waste Heat Boiler is no longer producing steam. When this happens, the reheat exchangers will not be able to keep the reactor feeds as hot as desired and liquid sulfur can begin to condense on the catalyst beds and render the catalyst inactive. The heat release in the Waste Heat Boiler can be increased by burning supplemental fuel gas on the warmup ring of the Acid Gas Burner. This burner is designed to burn fuel gas without forming soot while processing acid gas. The warmup burner tips are installed in the air plenum of the burner upstream of the acid gas tip so that the fuel gas burns in an air-rich atmosphere, and the oxygen remaining after combusting the fuel gas then reacts with the acid gas. To make firing supplemental fuel gas easier, the air flow control system is designed to automatically add air for the fuel gas like it does for the acid gas. The air:acid gas ratio control system will automatically add more process air for the fuel gas when firing supplemental fuel gas. The air demand analyzer in the SRU will continue to keep the air flow at the proper rate via the air controller. Since the supplemental fuel gas requires an increase in the process air flow to the sulfur plant, burning supplemental fuel gas will also increase the mass flow rate through that plant. As a result, this mode of operation can be used to help prevent sulfur "fog" problems discussed earlier from occurring in a Sulfur Condenser. If the plant throughput is near the range at which fogging occurs, firing some supplemental fuel gas may be enough to avoid the problem.
9.6.11.4
Long Term Low-Flow Operation Should the need arise for an SRU to operate at inlet rates below 15 to 20% for extended periods of time, consideration may be given to plugging some of the condensing pass tubes in the Sulfur Condenser. This will increase the flow rates through the remaining
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SULFUR BLOCK tubes so that they are then above the "fog" formation rate and sulfur carry-over is eliminated. Soft iron plugs can be inserted into the inlet ends of the tubes for this purpose. (Do not plug the outlet ends of the tubes. Since the boiler slopes from its inlet end to its outlet end, liquid sulfur would accumulate in the tubes and could cause localized corrosion, plugging, etc.)
9.6.12
Pressure Drop Surveys A commonly encountered problem in sulfur plants (and Tailgas Cleanup Units and Thermal Oxidizers) is a flow restriction due to high pressure drop. High pressure drop is typically caused by a restriction at one point in the equipment or piping, due to: 5.
Accumulation of liquid (sulfur, etc.) in equipment or piping
6.
Partial plugging of a catalyst bed (soot, carbon, polymers, etc.)
7.
Partial plugging of a mist eliminator (sulfur, soot, catalyst, etc.)
The first step in identifying the cause of the high pressure drop is to determine which equipment pass or section of piping contains the restriction. (It is unusual to have more than one area of high pressure drop at any one time.) This is best accomplished by making a pressure survey of the process side of the SRU (and Tailgas Cleanup Unit and Thermal Oxidizer, if necessary). Due to the low operating pressure in a sulfur plant (generally 0.7 kg/cm2(g) or less) and the low pressure drop in each equipment pass (generally 0.00-0.04 bar per pass), a single pressure gauge must be used to make the pressure survey in order to get meaningful results. The gauge should be a low-pressure gauge for best results (a -1 – 0 – +1.5 kg/cm2 gauge is recommended). Beginning at the front end of the sulfur plant of interest, use the pressure tap valves on the inlet and outlet lines from each equipment pass to measure the pressure at each point in the process. Proceed toward the back end of the process until the pass with the high pressure drop is found. Note that some of the pressure tap valves may be plugged with solid sulfur. Rod-out the sample valves as necessary to obtain an accurate pressure reading.
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SULFUR BLOCK
WARNING
ALWAYS OBSERVE PROPER PROCEDURES AND PRECAUTIONS WHEN USING THE PRESSURE TAP VALVES, PARTICULARLY IF THE VALVES ARE PLUGGED AND MUST BE CLEARED. ALTHOUGH THE VALVES ARE ORIENTED TO MINIMIZE THE POSSIBILITY OF FILLING WITH MOLTEN SULFUR, HOT SULFUR MAY SUDDENLY BE EXPELLED FROM A VALVE WHEN THE PLUG IS CLEARED. RELEASE OF TOXIC GASES (H2S AND SO2, IN PARTICULAR) IS ALSO A POSSIBILITY. THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES SHOULD BE CONSULTED IF THERE IS ANY DOUBT ABOUT HOW TO WORK SAFELY WHEN H2S, SO2, OR MOLTEN SULFUR MAY BE PRESENT. When troubleshooting problems of this nature, it is very helpful to have pressure survey information taken previously when the units were operating properly. It is recommended that one or more pressure surveys be performed early in the operating life of the plants, for comparison purposes later if problems are encountered. Since the pressure drop of a sulfur plant is a function of plant throughput (pressure drop is roughly proportional to the square of the flow rate), it is even more helpful for troubleshooting purposes if the early pressure surveys are performed at different plant throughput rates. It is also important to record the gas flow rates (amine acid gas, SWS gas, process air) during each pressure survey, since pressure drop depends so strongly on plant throughput.
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SULFUR BLOCK 9.6.13
Boiler Water Treatment SAMSUNG TOTAL PETROCHEMICALS CO., LTD. IS RESPONSIBLE FOR ESTABLISHING AND MONITORING THE BOILER AND WATER CHEMICAL TREATMENT PROGRAM. Proper boiler water chemical treatment is essential to achieving long service life for the Waste Heat Boilers and Sulfur Condensers. Without good day-to-day control of the water quality, solids buildup, corrosion, and attack by the treating chemicals themselves can occur. It is Samsung Total Petrochemicals Co., Ltd.’s responsibility to see that a proper chemical treating program is initiated prior to startup and that the program is properly monitored and refined throughout the service life of the plant. There are many qualified boiler and water treatment companies that can advise the owner/operator on chemical treatment testing and controls. It is recommended that only those companies that have local technicians with extensive experience specifically in boiler water treatment be selected to assist with Samsung Total Petrochemicals Co., Ltd.’s program. The design details incorporated in the boilers in these SRUs have proven to be very reliable when combined with good operator practice regarding water treatment. However, even properly designed equipment can be severely damaged during a short period of operation if the water treatment program is inadequate or improper. The Waste Heat Boilers and the Sulfur Condensers are equipped with continuous blowdowns to remove suspended and dissolved solids from the water inside the boilers. In addition, these boilers are equipped with intermittent blowdown connections on the bottom of their shells. These intermittent blowdown valves should be used on a regular basis to give the boilers a good "blow" to prevent sludge from accumulating in the bottom of the shells. This is particularly important for the Waste Heat Boiler because sludge must not be allowed to coat the tubes. The consequence of fouling the outside of the tubes is tube failure from overheating, as the fouling will impair the heat transfer and allow the hot combustion gases to destroy the tubes. Prior to using the intermittent blowdown valves, use the level controllers in the DCS to raise the water level up to the high level alarm point. Then open the intermittent blowdown valves, one at a time, until the level drops
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SULFUR BLOCK back to the normal liquid level. Watch the boiler level in the sight glasses throughout this operation to ensure that the level is not lost (which would activate the SRU ESD and shut down that plant). Remember to reset the level controllers at the conclusion of this procedure.
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SULFUR BLOCK
9.7
Precommissioning Procedures Prior to the initial startup, there are a number of precommissioning activities that are necessary to ensure that the newly constructed plant is ready to be placed in service. The activities outlined below should serve as a guide, but there may be others required as a part of your normal plant procedures.
9.7.1
Issued 30 August 2011
Preliminary Check-out A.
Check all equipment to ensure that it is properly installed. This will probably require consulting the Manufacturer's literature as well as construction drawings.
B.
Check and lubricate all equipment in accordance with the Manufacturer's recommendations.
C.
Check the rotation of the Process Air Blowers, the Acid Gas Knock-Out Drum Pumps, and the SWS Gas Knock-Out Drum Pumps: (1)
Operate each Process Air Blower for a short period (20 seconds or less) with its discharge valve closed.
(2)
"Bump" each Acid Gas Knock-Out Drum Pump and check for proper rotation.
(3)
"Bump" each SWS Gas Knock-Out Drum Pump and check for proper rotation.
D.
Check all piping and equipment to be sure that all blinds have been removed and that no valves are vented to atmosphere.
E.
Place the Instrument Air System in service to all instruments and check the action of controllers and control valves.
F.
Turn on the steam supplies to all of the steam-jacketed sulfur vapor valves and use the vent valves on each jacket section to vent the air from the jackets. "Stroke" each valve to confirm it moves freely.
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SULFUR BLOCK 9.7.2
Issued 30 August 2011
Shutdown System Check-out G.
Fill the Waste Heat Boilers and the Sulfur Condensers with treated boiler feed water up to the high-level alarm points. As the level is rising, check the level transmitters and the high level alarms for proper operation.
H.
Use the quick-opening blowdown valves to lower the water levels in the boilers and check for proper operation of the level transmitters, the low level alarms, and the low-low level shutdowns.
I.
Fill the boilers with treated boiler feed water back up to the normal liquid levels.
J.
Physically check all shutdown activating devices to ensure that they activate the SRU ESD system.
K.
Physically check all devices activated by the SRU ESD system to ensure that they operate properly.
L.
Check all relief valves to ensure that they are installed in the proper locations and set for the correct relieving pressures.
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SULFUR BLOCK 9.7.3
Leak Testing the Process Piping and Equipment
CAUTION
THE LOW PRESSURE PROCESS PIPING (ACID GAS, SULFUR VAPOR, PROCESS AIR) AND LOW PRESSURE PROCESS EQUIPMENT IN THESE SRUS ARE NOT DESIGNED TO BE FILLED WITH WATER AFTER INSTALLATION OF REFRACTORY AND CATALYST. ONLY THE EQUIPMENT AND PIPING UPSTREAM OF AMINE ACID GAS AND SWS GAS SHUTDOWN VALVES CAN BE FILLED WITH WATER AND HYDROTESTED. USE THE FOLLOWING PROCEDURE TO LEAK-TEST THE REST OF THE SRUS. The process piping and equipment in each SRU can be checked for leaks by using a Process Air Blower to pressurize the process side of the equipment and piping to about 0.6-0.7 kg/cm2(g), then checking flanges, etc. for leaks (usually by applying masking tape or "Snoop" to the flanges, and by listening for other leaks). In order to develop this pressure, the blower can be operated with the tailgas block valves and the warmup bypass valves in the SRU closed, and the blow-off valve on the blower "pinched". This procedure requires some special preparations to operate the blower in this manner, as detailed below. The Complete Flowpath Interlock must be temporarily disabled in order to operate the SRU in this manner. The Leak Test switch on each local SRU control panel is used to position the process gas valves as described above and also directs the PLC to bypass most of the unit shutdowns. This means that "jumpers" on the limits switches and "forces" in the PLC are not necessary to perform this test. It also means that it is not necessary to have water in the boilers (Waste Heat Boiler and Sulfur Condenser) during the test since the low-low water level S/Ds are also bypassed. This same procedure can be used to leak test each SRU before restarting it following maintenance. Whenever plant maintenance requires opening one or more of the flanged connections in an SRU, it is good practice to leak test that SRU before returning it to service. This allows detecting any
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SULFUR BLOCK leaking connections that may have resulted from the maintenance operations before acid gas is reintroduced into that unit. Although the SRU is pressurized with air to perform the leak test, there is no air flow through the units during the testing procedure so there is very little jeopardy of having sulfur fires in the catalyst beds. Note that the SRU warmup bypass line is not leak tested during this procedure. This line can be checked for leaks using the nitrogen purge on the piping as described in a later section of these guidelines. To perform leak testing in the SRU, proceed as follows: M.
Switch the process air flow hand switch in the DCS to "local" to give control of the valves on the air blower to the air flow controller (HIC) on the local SRU control panel.
N.
Confirm that the Reactor Cool-Down switch on the local SRU control panel is set to "NORMAL".
O.
Confirm that the manual block valve in the SRU Tailgas line is open.
P.
Switch the Startup/Run selector switch on the local SRU control panel to "STARTUP". The PLC and DCS should perform the following actions: (1)
The two Warmup Bypass Valves are opened.
(2)
The nitrogen purge valve between the warmup bypass valves is closed.
(3)
The Tailgas Valve to the Thermal Oxidizer is closed.
(4)
The Tailgas Valve to the TGCU is closed.
Confirm that the "WARMUP OPEN" light on the panel is illuminated, and that the "TTO OPEN" and the "TGCU OPEN" lights on the panel are extinguished.
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SULFUR BLOCK Q.
Turn the Leak Test key switch on the local SRU control panel to "TEST". The PLC should perform the following actions: (1)
The two Warmup Bypass Valves are closed.
(2)
The nitrogen purge valve is opened.
(3)
All of the ESDs for that SRU are bypassed, except for the high-high furnace pressure S/D and the manual S/D switches.
Confirm that the "WARMUP OPEN" light on the local SRU control panel is now extinguished. R.
Set the air flow controller on the local SRU control panel to 0% output and confirm that the suction, discharge, and blow-off valves on the air blowers are fully closed.
S.
Start a Process Air Blower: (1)
Press the local "permit to start" push-button for the selected blower.
(2)
Start the blower using its local start/stop control station.
The blower suction valve will open 33%, its vent valve will open, and its discharge valve will remain closed when the "permit to start" push-button is pressed. Once the blower is started and comes up to speed, a flow of air will be established out of the blow-off valve and its silencer. T.
Use the local air flow controller as needed to open the discharge valve on the blower and send air to the SRU to begin pressurizing it. Although the blower discharge valve will begin to open as the output from the controller is increased, air will not flow through the sulfur plant once pressure builds because the warmup bypass valves and the tailgas valves are all closed.
At this point, two operators will be necessary to control and monitor the Process Air Blower. One operator should be stationed at the local SRU control panel, and one stationed near the blower area.
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SULFUR BLOCK
CAUTION
DO NOT LET THE AIR BLOWER GO INTO SURGE. THE OPERATOR STATIONED NEAR THE BLOWER SHOULD LOOK AND LISTEN FOR INDICATIONS OF SURGE. IF SURGE IS DETECTED, REDUCE THE OUTPUT ON THE AIR FLOW CONTROLLER TO OPEN THE BLOW-OFF VALVE MORE AND INCREASE THE AIR FLOW ENOUGH TO BRING THE BLOWER OUT OF SURGE. IT MAY NOT BE POSSIBLE TO RAISE THE DISCHARGE PRESSURE ALL THE WAY TO 0.6-0.7 KG/CM2(G) WITHOUT CAUSING THE BLOWER TO SURGE. U.
Slowly increase the output from air flow controller to "pinch" the blow-off valve on the air blower until the discharge pressure from the blower reaches 0.6-0.7 kg/cm2(g) as measured by the pressure gauge on the process air line to the burner. Due to the volume inside the SRU, it will take several minutes for the pressure to build up in the SRU.
V.
Once the desired discharge pressure has been achieved, and the blower is operating stably, check all of the equipment and piping connections for visible or audible signs of leakage. Continue to monitor the air blower to be sure it is operating stably. NOTE:
Do not allow the pressure to reach the high-high pressure S/D, since this shutdown is still active and will activate the SRU ESD system if this happens.
W.
After the leak test has been completed, press the ESD push-button on the local SRU control panel to activate the SRU ESD system and shut down the air blower.
X.
Turn the Leak Test switch on the local SRU control panel to "NORMAL". The PLC should perform the following actions:
Issued 30 August 2011
(1)
The two Warmup Bypass Valves are opened.
(2)
The nitrogen purge valve is closed.
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SULFUR BLOCK (3)
All of the ESDs for the SRU are enabled again.
Confirm that the "WARMUP OPEN" light on the local SRU control panel is now illuminated. Y.
Issued 30 August 2011
Confirm the following: (1)
The air blower is shut down, and its suction, discharge, and blow-off valves are closed.
(2)
The two Warmup Bypass Valves are both open.
(3)
The Tailgas Valve to the Thermal Oxidizer and the Tailgas Valve to the TGCU are both closed.
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SULFUR BLOCK 9.7.4
Purging the Inlet Knock-Out Drums Since inert nitrogen gas is available in the SRU area, it can be used to purge the Acid Gas Knock-Out Drum and the SWS Gas Knock-Out Drum prior to removing the blinds in their inlet lines. One procedure for doing so is as follows.
WARNING
UNTIL THE AIR IS PURGED FROM THE KNOCK-OUT DRUMS, THERE MAY BE FLAMMABLE GAS MIXTURES PRESENT IN THE VESSELS AND THEIR PIPING. ENSURE THAT ALL IGNITION SOURCES, INTERNAL AND EXTERNAL TO THE VESSELS, HAVE BEEN REMOVED BEFORE PROCEEDING.
Issued 30 August 2011
A.
Verify that the blinds are in place in the inlet amine acid gas line and the inlet SWS gas line. Do not attempt this procedure if these lines are not blinded from their respective acid gas sources.
B.
The sulfur plant downstream of the drums does not need to be purged with nitrogen. Verify that the amine acid gas and SWS gas flow controllers on the local SRU panel are set to 0% output and that the inlet amine acid gas valve and the inlet SWS gas valve are closed.
C.
Open the suction valve and close the discharge valve on each Acid Gas Knock-Out Drum Pump.
D.
Open all of the vent and drain valves on the level and pressure instruments on the Acid Gas Knock-Out Drum and each Acid Gas Knock-Out Drum Pump, and the vent and drain valves on each Acid Gas Knock-Out Drum Pump.
E.
Remove the blind from the drain valve on the pump suction line and use a hose or other means to temporarily connect nitrogen to the valve. Commence the flow of nitrogen into the Acid Gas Knock-Out Drum and each Acid Gas Knock-Out Drum Pump, so that nitrogen is flowing out of all of the open valves. Be sure to include the acid gas inlet line from the Amine Regeneration Unit.
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SULFUR BLOCK F.
Allow the nitrogen to continue flowing long enough to reduce the oxygen concentration in the vessel and piping to less than 1%. Use a portable oxygen analyzer to determine the oxygen concentration.
G.
When the oxygen concentration is below 1%, begin closing the vent and drain valves. Close the valves on each Acid Gas Knock-Out Drum Pump first, then the valves on the Acid Gas Knock-Out Drum level instruments. Leave the sample connection valve open on the outlet line from the Acid Gas Knock-Out Drum.
H.
Close the valve where the nitrogen hose is connected to stop the flow of nitrogen, then close the sample connection valve.
I.
Repeat Steps C through H for the SWS Gas Knock-Out Drum and the SWS Gas Knock-Out Drum Pump. The sample connection valve on the outlet line from the SWS Knock-Out Drum should be the last valve closed, after stopping the flow of nitrogen.
Leave each system blocked-in like this until ready to bring acid gas into the SRU.
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SULFUR BLOCK 9.7.5
Commissioning Fuel Gas and Instrument Air to the Process The fuel gas and instrument air supplies to the process side of an SRU must be made ready for use prior to starting up the SRU using the procedures in Section 9.8 of these guidelines. This requires blowing down each section of piping to ensure that there are no liquids and/or construction debris in the headers and supply lines. The procedure below can be used to make sure that these gas utility systems are ready for service. A.
Select local manual control for the main fuel gas control valve by switching the fuel gas hand switch in the DCS to "local".
B.
Set the fuel gas controller on the local SRU control panel to 0% output.
C.
Confirm that the following fuel gas and instrument air valves are closed: (7)
The manual block valve in the main fuel gas supply line.
(8)
The two automated block valves and the flow control valve downstream of the manual block valve in the main fuel gas line to the Acid Gas Burner.
(9)
The upstream manual block valve, the two automated block valves, and the downstream manual block valve in the fuel gas supply line to the pilot.
(10) The manual block valve(s), and the automated block valve in the air supply line to the pilot. (11) The manual block valve in the instrument air supply line to the Air Demand Analyzer. (12) The block valves in the instrument air supplies to the level transmitters, on the Sulfur Surge Tank.
Issued 30 August 2011
D.
Confirm that all of the manual vent/drain valves in the main fuel gas, pilot fuel gas, and pilot air piping are closed.
E.
If the orifice plate has already been installed in the fuel gas flow meter remove it for now.
F.
Disconnect the fuel gas and instrument air from the burner systems by performing the following steps:
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SULFUR BLOCK
G.
H.
Issued 30 August 2011
(1)
Unbolt the flanged connection at the burner in the main fuel gas supply line.
(2)
Disconnect the fuel gas supply tubing where it connects to the pilot.
(3)
Disconnect the instrument air supply tubing where it connects to the pilot.
(4)
Cover the open ends of these connections on the burner and pilot to prevent debris from entering when the upstream piping is blown down.
Remove the following pressure regulators, then cover the downstream piping to prevent debris from entering when the upstream piping is blown down: (1)
The main fuel gas supply regulator.
(2)
The pilot instrument air supply regulator.
(3)
The pilot fuel gas supply regulator.
"Force" the PLC to open the following valves: (1)
The automated block valves in the main fuel gas supply line.
(2)
The automated block valves in the fuel gas supply line to the pilot.
(3)
The automated block valve in the instrument air supply line to the pilot.
I.
Confirm that these automated valves have moved to the proper positions.
J.
"Crack" the manual block valve in the main fuel gas supply line and allow fuel gas to blow through the piping until it is clear. Then close the gate valve, reinstall the main fuel gas pressure regulator, and reopen the block valve.
K.
Using the pressure gauge and the vent valve downstream of the main fuel gas pressure regulator, adjust the main fuel gas regulator to its specified setpoint.
L.
Use the main fuel gas flow controller on the local control panel to fully open the fuel gas flow control valve in the main fuel gas line,
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SULFUR BLOCK then use the downstream vent valve to blow out this section of piping. Close the vent valve when the piping is clear.
Issued 30 August 2011
M.
"Crack" the manual block valve downstream of the fuel gas flow control valve and allow fuel gas to blow through the piping until it is clear. Then close the manual block valve and the control valve.
N.
"Crack" the upstream manual block valve in the fuel gas supply line to the pilot and allow fuel gas to blow through the piping until it is clear. Then close the ball valve, reinstall the pilot fuel gas pressure regulator and reopen the block valve.
O.
Using the pressure gauge and the vent valve downstream of the pilot fuel gas pressure regulator, adjust the pilot fuel gas regulator to its specified setpoint.
P.
"Crack" the manual block valve downstream of pilot fuel gas automated block valves and allow fuel gas to blow through the piping until it is clear. Then close the manual block valve.
Q.
"Crack" the upstream manual block valve in the instrument air supply line to blow air through the piping until it is clear. Then close the block valve, reinstall pressure regulator the instrument air pressure regulator and reopen the block valves.
R.
Using the pressure gauge and the vent valve downstream of the instrument air pressure regulator, adjust the pilot instrument air regulator to its specified setpoint.
S.
"Crack" the manual block valve downstream of automated instrument air block valve and allow instrument air to blow through the piping until it is clear. Then close the manual block valve.
T.
Disconnect the air supply line at the Air Demand Analyzer, cover the open end of the downstream piping, and "crack" the manual block valve to blow air through the piping until it is clear. Then close the manual block valve, reconnect the piping, and reopen the block valve.
U.
Disconnect the upstream fitting in the air supply to purge the rotameter for the bubbler-type level transmitter on the Sulfur Surge Tank, then open the block valve in the air supply line briefly to blow any liquids or debris from the purge line. Reconnect the FI, disconnect the fitting where the purge enters the bubbler tube, and
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SULFUR BLOCK cover the opening. Open the block valve briefly to blow any liquids or debris from the purge line, then reconnect the purge to the bubbler tube. Reopen the block valve and adjust the FI to a small air flow (0.8-1.6 Nm3/Hr). Place the other level transmitters in service in the same manner.
Issued 30 August 2011
V.
Remove the "forces" from the PLC and confirm that all of the automated block valves close and all of the automated vent valves open.
W.
Close the manual block valve in the main fuel gas supply line and the manual block valve in the instrument air line supply until the SRU is ready for startup.
X.
Reconnect the fuel gas and instrument air to the burner systems by performing the following steps: (1)
Bolt the flanged connection at the burner in the main fuel gas supply line back together.
(2)
Reinstall the fuel gas supply tubing where it connects to the pilot.
(3)
Reinstall the instrument air supply tubing where it connects to the pilot.
(4)
Reinstall the orifice plate in the fuel gas flow meter.
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SULFUR BLOCK 9.7.6
Commissioning Nitrogen to the Process The nitrogen supplies to the process side of each SRU must be made ready for use prior to starting up the SRUs using the procedures in Section 9.8 of this manual. This requires blowing down each section of piping to ensure that there are no liquids and/or construction debris in the headers and supply lines. The procedure below can be used to make sure that this gas utility system is ready for service. A.
Issued 30 August 2011
Confirm that the following nitrogen valves are closed: (1)
The manual block valves in the N2 purge line to the bypass acid gas injection nozzles on the Reactor Furnace.
(2)
The ball valves in the purge lines to the burner instruments.
(3)
The block valves in the purge lines to the optical pyrometer.
(4)
The gate valves in the nitrogen supply lines located near the Reactor and the nitrogen supply line located near the Acid Gas Burner.
(5)
The ball valves in the purge lines to the SWS gas flow transmitter and pressure gauge.
(6)
The gate valve in the nitrogen supply line to the Air Demand Analyzer.
(7)
The gate valve upstream and the ball valve downstream of the rotometer in the purge line on the SRU warmup bypass line.
B.
Confirm that the H.P. nitrogen and L.P. nitrogen supply headers have been placed in service, with the pressure regulator(s) set at the values specified on the P&IDs and safety relief valves in service, and that the main supply header piping has been blown down and drained.
C.
Open the gate valve in each of the three nitrogen supply lines located near the Reactor and the nitrogen supply line near the Acid Gas Burner until each line is clear.
D.
Remove pressure regulator in the purge line for the optical pyrometer viewport and nozzle, cover the open end of the downstream piping, open the gate valve, and "crack" the ball valve in the supply line to blow nitrogen through the piping until it is clear. Then close the gate valve and the ball valve and reinstall the regulator.
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SULFUR BLOCK E.
Disconnect the purge tubing from the viewports on the optical pyrometer and cover the opening.
F.
Open the gate valve and the ball valve in the nitrogen supply. Using the pressure gauge, adjust the regulator to its specified setpoint. Allow nitrogen to blow through the tubing until it is clear. Reinstall the purge tubing to the pyrometer. Leave the gate valve and the ball valve in the supply line open.
G.
Remove the plug and use the drain valve at the end of the supply line to the purges for the burner instruments to blow out this section of piping until it is clear, then close the drain valve and reinstall the plug.
H.
Each of the low pressure purges for the burner instruments and for the bypass acid gas nozzles has a rotameter (FI) near where it connects to the process. Disconnect the upstream fitting at each FI and cover the opening, then open its upstream ball valve briefly to blow any liquids or debris from the purge line. Reconnect each FI, disconnect the fitting where each purge enters the process and cover the opening, open its upstream ball valve, then open its downstream valve briefly to blow any liquids or debris from the purge line. Then reconnect each purge to the process and open its downstream valve to place it in service.
I.
The SWS gas flow transmitter has low pressure purges for both of its sensing lines, each with a rotameter near where it connects to the sensing line. Disconnect the upstream fitting at each FI and cover the opening, then open its upstream ball valve briefly to blow any liquids or debris from the purge line. Reconnect each FI, disconnect the fitting where each purge connects to the sensing line and cover the opening, open its upstream ball valve, then open its downstream ball valve briefly to blow any liquids or debris from the purge line. Then reconnect each purge to the sensing line and open its downstream ball valve to place it in service. NOTE: The two rotameters must be adjusted to the same flow rate so that the pressure drop of the purge gas in the sensing lines does not affect the reading of the flow transmitter. One way to do this is to confirm that the equalizing valve on the flow transmitter manifold is closed, set the rotameter on the upstream sensing line to a small flow rate
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SULFUR BLOCK (~0.8-1.6 Nm3/Hr), and then adjust the flow rate of the other rotameter until the flow meter reads zero.
Issued 30 August 2011
J.
The SWS gas pressure gauge also has a low pressure purge for its sensing line with a rotameter near where it connects to the sensing line. Disconnect the upstream fitting at the FI and cover the opening, then open its upstream ball valve briefly to blow any liquids or debris from the purge line. Reconnect the FI, disconnect the fitting where the purge connects to the sensing line and cover the opening, open its upstream ball valve, then open its downstream ball valve briefly to blow any liquids or debris from the purge line. Then reconnect the purge to the sensing line and open its downstream ball valve to place it in service.
K.
Disconnect the nitrogen supply line at the Air Demand Analyzer, cover the open end of the downstream piping, and "crack" the gate valve to blow nitrogen through the piping until it is clear. Then close the gate valve, reconnect the piping, and reopen the gate valve.
L.
If necessary, "force" the PLC to close the two Warmup Bypass Valves and open the N2 purge valve. Disconnect the upstream fitting at the rotometer (FI) and cover the opening, then open its upstream gate valve briefly to blow any liquids or debris from the purge line. Reconnect the FI, then disconnect the fitting where the purge enters the process and cover the opening. Open the upstream gate valve, open the downstream manual block valve briefly to blow any liquids or debris from the purge line, then reconnect the purge to the process.
M.
Open the manual block valve downstream of the FI and allow the nitrogen to pressurize the piping between the two Warmup Bypass Valves. Check all of the piping connections for visible or audible signs of leakage (by applying masking tape or "Snoop" to the flanges, listening for other leaks, etc.). When this leak checking complete, if the PLC was "forced" in the previous step, remove the "force" and confirm that the Warmup Bypass Valves open and the purge valve closes. Leave the manual block valve downstream of the FI open.
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SULFUR BLOCK 9.7.7
Commissioning the Sulfur Surge Tank Heating and Ventilation The heating and ventilation systems for each Sulfur Surge Tank can be placed in service at any time prior to the beginning of sulfur production from the associated SRU. It is advantageous to place these systems in service prior to startup of the SRU so that any problems can be corrected without impacting the schedule for commissioning the SRU. To place the heating and ventilation systems in service, proceed as follows:
Issued 30 August 2011
A.
Confirm that the steam supply valves to the steam coils in the Sulfur Surge Tank are all closed, and that the steam trap stations on each of the coils are all blocked in.
B.
Open the vent valves on each of the steam coils.
C.
Establish steam flow into each of the coils by opening the steam supply valves to each coil.
D.
Allow air (and any liquids or debris) to purge from the vent valves. Close each vent valve as it begins to blow steam.
E.
Open the upstream block valve of the steam trap on each coil and use the bleeder on each trap to drain water (and any other liquids) from each coil. Close the bleeder on each trap once hot condensate begins flowing through the trap.
F.
Open the test valve on each trap and confirm that each trap is operating properly. Then close the test valve and open the downstream block valve on each trap to place the traps in service to the condensate header.
G.
Repeat Steps A through F to commission the heating systems on each of the four sulfur rundown lines from the Sulfur Condenser and their associated Sulfur Drain Seal Assemblies. Open all of the vent valves on the steam jackets long enough to vent the air from the jackets.
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SULFUR BLOCK
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H.
Repeat Steps A through F to commission the heating systems on the air sweep vent stack, the Sulfur Surge Tank Vent Ejector, A2-EE1530 (A2-EE1540), the ejector suction line, and the ejector discharge line. Open all of the vent valves on the steam jackets long enough to vent the air from the jackets. In particular, use the vent line on the air sweep vent stack to vent the air from its steam jacket.
I.
Make sure that the breather vents at each end of the Sulfur Surge Tank are unobstructed and that the air sweep vent stack has begun to draft air into the tank through the breather vents.
J.
Check that the suction valve on the Sulfur Surge Tank Vent Ejector is closed and the discharge valve is open.
K.
Confirm that the globe valve in the motive steam line to the Sulfur Surge Tank Vent Ejector is closed, then open the upstream manual block valve in the line.
L.
Slowly open the globe valve to establish motive steam flow to the ejector. Verify that the steam is flowing at the proper rate (about 500 kg/H) on the steam flow meter in the DCS.
M.
Open the ejector suction valve. The ejector should now begin to overcome the natural-draft driving force of the air sweep vent and route the ventilation air from the pit to the Thermal Oxidizer.
N.
Confirm that all steam traps are functioning properly and that steam is flowing to the ejector before directing your attention away from the Sulfur Surge Tank.
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SULFUR BLOCK 9.7.8
Pre-filling the Sulfur Drain Seal Assemblies The Sulfur Drain Seal Assemblies, A2-ME1530A-D (A2-ME1540A-D), must be filled with molten sulfur in order to seal the pressurized process gases inside the SRU. The initial sulfur production when the SRU is first started up can be used to accomplish this as described in Section 9.8.2 of these guidelines. It is often convenient, however, to pre-fill the seals with sulfur prior to starting up the SRU. The blind flange on the top of each assembly can be removed to allow pouring sulfur into the drain seal to fill it. Pre-filling of the seals can be accomplished at any time after the steam heating for the sulfur rundown lines and Drain Seal Assemblies has been placed in service as described in the preceding section. Both molten sulfur and solid sulfur prills have been used for this purpose. If sulfur prills are used, proceed slowly enough so that the steam jackets on the seals can melt the sulfur. Continue to add sulfur to each seal until molten sulfur pours from its spill-over spout into its collection basin. Then bolt the blind flange back on the top of each seal assembly. If the drain seals are pre-filled in this fashion, the block valves in the sulfur rundown lines can be left open during the initial plant startup. Otherwise, these block valves must be closed when acid gas is first introduced to prevent hazardous process gases from escaping from the SRU. Section 9.8.2 of this manual describes how to use the sulfur produced during startup to fill the drain seals if they are not pre-filled.
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SULFUR BLOCK
9.8
Startup Procedures The procedure used to start up an SRU depends on whether the Reactor catalyst contains sulfur, and whether the refractory in the Reactor Furnace is up to operating temperature. This first section describes the procedure for the initial startup of a new plant. Subsequent startups will require a different procedure, and are discussed later (Sections 9.8.5 and 9.8.6 of this manual).
9.8.1
Initial Firing / Refractory Cure-out Only during the initial startup of an SRU can the warmup gases be routed through the entire sulfur plant. After a sulfur plant has been operated to produce sulfur, residual sulfur will always be present in the catalyst beds. If warmup gases containing free oxygen are routed through the catalyst beds during subsequent warmup periods, this residual sulfur will ignite, resulting in excessive temperatures which can cause equipment and/or catalyst damage. It should be noted that the auto-ignition temperature of sulfur on catalyst beds can be as low as 150°C when sufficient oxygen is present. During the initial startup, the Reactor Furnace and downstream equipment will be warmed up to operating conditions following the refractory vendor's cure-out schedule for the Reactor Furnace.
CAUTION IT IS CRITICAL THAT THE WARMUP PROCEDURES BE FOLLOWED VERY CLOSELY. THE REFRACTORY MATERIAL MUST BE HEATED SLOWLY TO ALLOW THE CONTAINED WATER TO VAPORIZE AND ESCAPE FROM THE REFRACTORY LINING, WITHOUT EXERTING EXCESSIVE INTERNAL PRESSURE AND CAUSING LINING DAMAGE.
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SULFUR BLOCK 9.8.1.1
Initial Preparations A.
Check that all devices in the SRU ESD have been satisfied, except for the following: (1)
Neither blower running.
(2)
Flame failure.
The PLC logic provides bypasses for these two conditions so that the system can be started up.
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B.
Confirm that the manual block valve in the SRU tailgas line is open.
C.
Confirm that the amine acid gas flow on/off switch, is set to "on" so that this flow will be included in the air:acid gas ratio control system.
D.
Select local manual control for the control valves on the Process Air Blower by switching process air hand switch (HS) in the DCS to "local".
E.
Place the air flow controller in "cascade".
F.
Place the air demand controller in "manual" and set its output to 50%.
G.
Confirm that the manual signal bias control for the blower to be used is set to 100% so that the control signals to the blower valves are not modified.
H.
Select local manual control for the fuel gas flow control valve, by switching the main fuel gas hand switch (HS) in the DCS to "local".
I.
Place the fuel gas flow controller in "automatic".
J.
Confirm that the fuel gas flow on/off switch is set to "on" so that this flow will be included in the air:acid gas ratio control system.
K.
Place the Reactor Furnace front zone temperature controller in the DCS in "automatic".
L.
Place the bypass acid gas flow ratio controller in "manual" and set its output to 0% so that control valve the bypass acid gas control valve will be fully closed.
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SULFUR BLOCK M.
Confirm that both boilers (Waste Heat Boiler and Sulfur Condenser) are filled with water up to their normal liquid levels.
N.
Verify that the four block valves in the sulfur rundown lines from the Sulfur Condenser are closed (unless the Sulfur Drain Seal Assemblies have been pre-filled with sulfur as described in Section 9.7.8 of this manual).
O.
During the early part of refractory cure-out, the startup thermocouple assembly furnished with the optical pyrometer, will be used to measure the furnace temperature, using their furnished hand-held digital display units. (Optical pyrometers are unreliable at temperatures below 200°C.) The thermocouple will be used until the third "hold" point (about 500°C) in the warmup schedule is reached. Loosen the wing nut on the hinged pyrometer fixture and swing the pyrometer out of the way. Unscrew the viewport len and remove it (be careful with the rubber o-ring gasket). Store the viewport lens in a safe place. Screw the thermocouple adapter housing onto the pyrometer mounting plate (with the o-ring in place). Open the pyrometer block valve, slide the thermocouple into the furnace, and tighten the packing gland on the end of the adapter housing.
P.
Confirm that the Acid Gas Firing switch on the local SRU control panel is set to "DISABLED".
Q.
Confirm that the Leak Test switch on the local SRU control panel is set to "NORMAL".
R.
Confirm that the Reactor Cool-Down switch on the local SRU control panel is set to "NORMAL".
S.
Set the manual amine acid gas control (HIC) on the local SRU control panel to 0% output. Visually confirm that the amine acid gas inlet valve is closed.
T.
Set the manual SWS gas control (HIC) on the local SRU control panel to 0% output. Visually confirm that the SWS gas inlet valve is closed.
U.
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Set the manual fuel gas control (HIC) on the local SRU control
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SULFUR BLOCK panel to 0% output. Visually confirm that the main fuel gas valve and the two automated shutdown valves are closed.
9.8.1.2
V.
Set the manual air control on the local SRU control panel to 0% output.
W.
Verify that the acid gas control valve in the amine acid gas line to the burner is fully open.
X.
Verify that the bypass acid gas control valve in the bypass acid gas line is fully closed.
Y.
Verify that the pilot burner mounting nozzle is being purged with nitrogen as indicated by its rotameter.
Igniting the Pilot Burner A.
Switch the Startup/Run selector switch on the local SRU control panel to "STARTUP". The PLC should perform the following actions: (1)
The two Warmup Bypass Valves are opened. The "WARMUP OPEN" status light on the local SRU control panel will flash until these valves have moved to the proper position, then remain steadily illuminated.
(2)
The nitrogen purge valve is closed.
(3)
The Tailgas Valve to the TTO is closed. The "TTO OPEN" status light will flash until this valve has moved to the proper position, then will be extinguished.
(4)
The Tailgas Valve to the TGCU is closed. The " TGCU OPEN" status light will flash until this valve has moved to the proper position, then will be extinguished.
NOTE:
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If a status light limit switches confirmed that position. If this
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continues to flash, it means that the on the associated valve(s) never the valve(s) moved to the proper occurs, the startup sequence will not
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SULFUR BLOCK be allowed to proceed until the problem is corrected and the valve(s) move to the proper position. Note that the valve may have actually moved to the proper position, but a faulty limit switch may not be detecting that the valve is in the proper position. Confirm that these valves have moved to the proper positions. Confirm that the "WARMUP OPEN" light on the panel is illuminated, and that the "TTO OPEN" and the "TGCU OPEN" lights on the panel are extinguished. B.
Verify that the local start/stop controls for the Process Air Blowers have their selector switches turned to the "STOP" position.
C.
Verify that the suction, discharge, and blow-off valves on both blowers are all closed.
D.
Start a Process Air Blower: (1)
Press the local push-button to give a “permit to start” for the desired blower. This will energize the solenoid valves on the blower suction and vent valves. The blower suction valve will open 33% and the blow-off valve will open 100%, but the discharge valve will remain closed. These valves will close again if the blower is not started within 30 seconds when the "permit to start" times out.
(2)
Start the blower using the local start/stop control station for that blower. When the blower starts, the solenoid valve on the blower discharge valve is also energized, but the valve will remain closed because the local process air flow controller (HIC) is set to 0% output.
Once the blower is started and comes up to speed, a flow of air will be established out of the blow-off valve and its silencer. Starting the blower with its suction throttling valve "pinched" allows the blower to start in an unloaded condition, which imposes less of a load on the blower and its motor.
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SULFUR BLOCK E.
Confirm that the air blower is running, then press the "ESD RESET" push-buttonon the local SRU control panel to reset the SRU ESD and extinguish the "RESET REQUIRED" light. This will illuminate the "PURGE REQUIRED" light.
F.
Verify that the "LIMITS SATISFIED" light is glowing steadily (not flashing) on the local SRU control panel. NOTE:
If the "LIMITS SATISFIED" light is flashing, this means that either a limit switch or a pressure transmitter is not satisfied. The limit switches on the amine acid gas valve, the SWS gas valve and the main fuel gas valves must all indicate that their respective valves are closed. The low-low pressure setpoint on the fuel gas supply and the high-high pressure setpoint on the fuel gas to the burner must both be satisfied. For safety reasons, the PLC will not allow the light-off sequence to proceed until all these conditions are satisfied. Once the problem with the valves, their limit switches, or the pressure transmitters has been corrected, the "LIMITS SATISFIED" light will stop flashing and glow steadily, and the light-off sequence can proceed.
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G.
Adjust the output of the air flow control (HIC) on the local SRU panel to open the blower control valves and allow a large air flow, 80% or more on the flow indicator on the local SRU control panel, to purge the entire system for about 5 minutes. The "PURGE REQUIRED" light will be extinguished and the "PURGE COMPLETE" light will be illuminated after about 30 seconds, but continue to purge the system for a full 5 minutes prior to this first time ignition attempt.
H.
Open the following manual block valves: (1)
The manual block valve(s) in the main fuel gas supply line.
(2)
The manual block valve(s) in the fuel gas supply line to the burner.
(3)
The manual block valve(s) in the fuel gas supply to the pilot.
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SULFUR BLOCK
I.
(4)
The manual block valve(s) in the instrument air supply to the pilot.
(5)
The manual block valve(s) in the instrument air supply to the pilot.
Adjust the output of the air flow control (HIC) on the local SRU panel to reduce the air flow to 10-20%. This will extinguish the "PURGE COMPLETE" light and illuminate the "PERMIT TO IGNITE" light and the PLC will "enable" the ignition circuit. NOTE:
Once the "PERMIT TO IGNITE" light is illuminated, an ignition safety interlock timer starts. If an ignition attempt is not made within 5 minutes, the SRU ESD system will be activated to shut down the sulfur plant. This prevents a potentially unsafe condition from persisting, where a leaking fuel gas valve could cause an explosive mixture to form in the Reactor Furnace, since the air flow is low at this point in the startup procedure. If either flame scanner detects a flame before the "IGNITION" push-button is pressed, this will activate the SRU ESD system and the "flame scanner malfunction" alarm in the DCS. This will stop the air blower and extinguish the flame (unless of course, a flame scanner is giving a false indication). A flame prior to ignition usually indicates a leaking fuel gas or acid gas valve. If this occurs, check these valves before proceeding with startup, as a leaking valve can allow an explosive mixture to form in the Reactor Furnace without warning.
J.
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Press the "IGNITION" push-button on the local SRU control panel to initiate an ignition attempt. The PLC will do the following: (1)
The nitrogen purge valve for the pilot burner is closed.
(2)
The pilot air automated block valve is opened.
(3)
The pilot gas automated vent valve is closed and the automated block valves are opened.
(4)
The ignition system is energized to begin sparking the
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SULFUR BLOCK ignitor inside the pilot. (5) K.
The air and fuel gas pressure regulators for the pilot may require some adjustment when first put in service before the pilot will light. However, once set properly, the pilot should ignite readily on subsequent startups. Refer to Section 9.11 of these guidelines for a suggested procedure to adjust these regulators.
L.
If neither flame scanner detects a flame after 15 seconds of sparking the ignitor, the ignition try is aborted, the SRU Burner Shutdown system is activated, and the PLC causes the sequence to return to Step G.
M.
When either flame scanner detects a flame from the pilot burner, the appropriate "MAIN FLAME ON" light(s) are illuminated. The pilot air and fuel gas valves will remain open after the ignition trial, and the PLC will perform the following activities:
N.
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The "PILOT ON" light is illuminated.
(1)
The "LIMITS SATISFIED" and "PERMIT TO IGNITE" lights are extinguished.
(2)
The "PILOT ON" light remains illuminated.
(3)
The ignition system is de-energized.
(4)
The startup bypass in the PLC for the "flame failure" S/D is disabled.
(5)
The "MAIN FUEL START" push-button on the local SRU control panel is enabled.
(6)
The "RUN" position on the Startup/Run selector switch on the local SRU control panel is enabled.
After the pilot is lit, use the air flow control (HIC) on the local SRU panel to increase the air flow rate to about 50% of scale, or as high a rate as can be maintained without blowing the pilot out. When curing refractory, it is best to keep the air flow as high as possible to help distribute the heat more evenly and to heat the downstream equipment more quickly.
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SULFUR BLOCK 9.8.1.3
Routing Warmup Gases Through the Entire SRU At this point, the warmup gases from the Acid Gas Burner are only flowing through the Reactor Furnace, the Waste Heat Boiler, and the first pass of the Sulfur Condenser. The Warmup Bypass Valves divert the gases from the first pass outlet of the Sulfur Condenser to the Thermal Oxidizer (the normal "startup" mode). For the initial firing of the SRU, the warmup gases are to be routed through the entire SRU as follows to cure-out the refractory in Reactor and to heat up all of the unit. A.
Switch the Startup/Run selector switch on the local SRU control panel to "RUN". The PLC will perform the following actions: (1)
The Tailgas Valve to the TTO is opened. The "TTO OPEN" status light will flash until this valve has moved to the proper position, then remain steadily illuminated.
(2)
After the limit switches prove this valve open, the two Warmup Bypass Valves are closed. The "WARMUP OPEN" status light will flash until these valves have moved to the proper position, then will be extinguished.
(3)
After the limit switches prove that at least one of these valves is closed, the nitrogen purge valve to the Warmup Bypass Line is opened.
NOTE:
If a valve status light continues to flash, it means that the limit switches on the associated valve(s) never confirmed that the valve(s) moved to the proper position. If this occurs, the startup sequence cannot proceed until the problem is corrected and the valve(s) move to the proper position.
Confirm that these valves have moved to the proper positions. Confirm that the "WARMUP OPEN" light on the panel is extinguished, the "TTO OPEN" light on the panel is illuminated, and the "TGCU OPEN" light on the panel remains extinguished.
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SULFUR BLOCK
9.8.1.4
B.
Open the vent valves on each of the two boilers to vent air from the steam sections.
C.
Confirm that the BFW level controllers and control valves to the Waste Heat Boiler and Sulfur Condenser are in service and functioning properly.
D.
The heat input from the pilot should be sufficient to reach the first "hold" point in the refractory warmup schedule, 100-150°C. If the temperature is too high, increase the air flow rate. If the temperature is too low, decrease the air flow rate.
Igniting the Main Warmup Burner When the firing rate needs to be increased to raise the furnace temperature, the main warmup burner can be placed in service. The control valve in the main fuel gas line will be used to control the fuel gas flow rate. A.
Confirm that the flow control valve in the main fuel gas line is fully closed.
B.
Confirm that the manual block valve(s) in the main fuel gas line to the burner is (are) open.
C.
If the air flow rate is not at 50% of scale, use the air flow control (HIC) on the local SRU panel to set the air flow at about 50% of scale.
D.
Press the "MAIN FUEL START" push-button on the local SRU control panel to commission the main fuel gas. The PLC performs the following actions:
E.
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(1)
The nitrogen purge valve for the main warmup burner is closed.
(2)
The main fuel gas automated vent valve is closed.
(3)
The main fuel gas automated block valves are opened.
(4)
The "MAIN FUEL ON" light on the local control panel is illuminated.
Adjust the output of the main fuel gas flow control (HIC) on the local SRU control panel to slowly open the control valve to commence fuel gas flow to the warmup burner ring. Adjust the
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SULFUR BLOCK fuel gas flow rate until a stable flame can be maintained. Note that the fuel gas flow rate will be indicated on the local panel and in the DCS. 9.8.1.5
Refractory Cure-out and Warmup With the main fuel gas ring on the Acid Gas Burner in service, its firing rate can now be adjusted to control the refractory cure-out of the Reactor Furnace. A.
Adjust the fuel gas flow rate with the main fuel gas flow control (HIC) on the local control panel as necessary to cause the furnace temperature to follow the refractory cure-out schedule for the initial cure supplied by the refractory vendor. It is often helpful to maintain a log of the air flow, the fuel gas flow, and the furnace temperature during the cure-out for future reference.
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B.
Frequently confirm that the proper water levels are maintained in the Waste Heat Boiler and the Sulfur Condenser. Confirm that the level control systems are functioning properly.
C.
As the steam pressure starts to build in the Waste Heat Boiler, put the Waste Heat Boiler Steam pressure controller in the DCS in "automatic" with a setpoint of 48.5 kg/cm2(g).
D.
Place the three temperature controllers for the Reactor feeds in "manual" and set their outputs to 100% to fully open the valves in the condensate outlet lines from the reheat exchangers. This will ensure that the feeds are as hot as possible for curing the refractory in the three chambers of the Reactor.
E.
As the steam pressure starts to build in the Sulfur Condenser, put the Sulfur Condenser steam pressure controller in the DCS in "automatic" with a setpoint of 4.2 kg/cm2(g).
F.
Once the third "hold" point in the cure-out schedule has been reached (about 500°C), the optical pyrometer can be placed in service. After the furnace temperature has stabilized, loosen the packing gland on the thermocouple adapter housing and slide the thermocouple out until the "keeper" stops it. Close the pyrometer block valve then unscrew the adapter housing and
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SULFUR BLOCK store it in a safe place. CAUTION:
THE THERMOCOUPLES WILL BE VERY HOT. HANDLE THEM CAREFULLY TO AVOID BURNS AND TO AVOID DAMAGING THE THERMOCOUPLES.
Screw the viewport lens back onto the pyrometer mounting plate (with the o-ring in place), swing the pyrometer back into place, tighten the wing nut, and open the pyrometer block valve. Open the block valve in the pyrometer purge system to begin purging the viewport lens and nozzle with nitrogen. Verify that the purge to the pyrometer viewport is operating properly. The furnace temperature will now be indicated over the full range of the pyrometer on the local digital indicators mounted near the pyrometer. The controller in the DCS will also indicate the furnace temperature. G.
Commission all steam heating systems on the sulfur rundown lines, sulfur drain seals, sulfur surge tank, sulfur pumps, and valve jackets if these are not already in service. Check all steam traps for proper operation, and use the vent valves to sweep non-condensibles out of the steam spaces.
H.
As the equipment and piping heat up, inspect all of the equipment and piping for the effects of thermal expansion.
I.
As the steam pressures build in the boilers, the vent valves on the steam spaces may be closed.
At the conclusion of this procedure, the SRU is ready to process acid gas. However, if the acid gas feed from the Amine Regeneration Unit is not yet available, the SRU can run indefinitely in this mode until the other systems are ready. Monitor the Reactor Furnace temperature and make adjustments to the fuel gas flow as needed to control this temperature around 1200°C.
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SULFUR BLOCK 9.8.2
Amine Acid Gas Flow At the end of the refractory cure-out schedule, the SRU is firing on fuel gas and is ready to accept acid gas. The switch to acid gas firing is accomplished by gradually swapping acid gas for fuel gas. A.
Issued 30 August 2011
Before commencing acid gas flow, confirm that the following conditions are all true: (1)
The feed temperatures to all three chambers of the Reactor are 205°C or higher.
(2)
The steam pressure in the Sulfur Condenser is 4.2 kg/cm2(g) or higher.
(3)
The Thermal Oxidizer is ready to accept SRU tailgas.
(4)
All vent and drain valves on the Acid Gas Knock-Out Drum, its piping, and the Acid Gas Knock-Out Drum Pump are closed and plugged.
(5)
Any blinds installed in the amine acid gas line have been removed.
(6)
The block valves are lined up to place an Acid Gas Knock-Out Drum Pump in service, the selector switch on that pump is set to "AUTO", and the pump level control transmitter is in service.
B.
Confirm that the bypass acid gas flow ratio controller in the DCS is still in "manual" with its output set to 0%. This ensures that the bypass acid gas control valve will remain closed so that all of the amine acid gas will flow to the Acid Gas Burner.
C.
Adjust the process air flow rate to 50% of scale on the local indicator using the air flow control (HIC) on the local SRU panel. Reduce the fuel gas flow rate to 50% of scale on the local indicator using the main fuel gas flow control (HIC) on the local panel.
D.
Because of the procedure used for this initial firing, the Warmup Bypass Valves are already closed and the Tailgas Valve to the Thermal Oxidizer is already opened. Thus, the flowpath through the SRU is already set correctly for introducing acid gas.
E.
Switch the Acid Gas Firing selector switch on the local SRU control panel to "ENABLED".
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SULFUR BLOCK F.
Slowly increase the output from the amine acid gas flow control (HIC) on the local SRU control panel to begin opening the amine acid gas inlet valve until the acid gas flow rate is approximately 10% on the indicator on the local SRU control panel.
G.
As soon as the acid gas flow rate reaches 10%, use the main fuel gas flow control (HIC) to reduce the fuel gas flow rate from 50% to 40% on the local indicator.
H.
Continue to add amine acid gas in 10% increments and reduce the fuel gas in 10% increments until the fuel gas control valve is completely closed.
I.
Press the “FUEL GAS OFF” push-button on the local SRU control panel. The PLC performs the following actions to "double block and bleed" the main fuel gas: (1)
The main fuel gas automated block valves are closed.
(2)
The main fuel gas automated vent valve is opened.
(3)
The nitrogen purge valve for the main burner is opened.
(4)
The “FUEL GAS ON” light is extinguished.
Verify that the that the fuel gas valves have moved to their proper positions and that the main fuel gas burner ring is being purged with nitrogen as indicated by the associated rotometer. J.
Press the "PILOT OFF" push-button on the local SRU control panel. The PLC performs the following actions to block the pilot air and "double block and bleed" the pilot fuel gas:
Issued 30 August 2011
(1)
The aitmated block valve in the air supply to the pilot is closed.
(2)
The pilot fuel gas automated block valves are closed.
(3)
The pilot fuel gas automated vent valve is opened.
(4)
The automated nitrogen purge valve for the pilot burner is opened.
(5)
The "PILOT ON" light is extinguished.
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SULFUR BLOCK Verify that the air and fuel gas valves have moved to their proper positions and that the pilot burner is being purged with nitrogen as indicated by the associated rotameter. K.
Continue to slowly increase the output from the amine acid gas flow control (HIC) to 100% so that the amine acid gas inlet valve is fully open.
L.
If the amine acid gas flow rate (in percent) displayed on the local control panel is significantly different from the air flow rate (in percent) displayed on the local control panel, use the air flow control (HIC) on the local SRU panel to adjust the air flow until the percentages are about the same. This should put the air:acid gas ratio reasonably close to where it should be.
M.
Close the following manual block valves:
N.
(1)
The two manual block valve(s) in the main fuel gas line.
(2)
The manual block valve(s) in the fuel gas to the pilot.
(3)
The manual block valve(s) in the instrument air to the pilot.
Loosen the packing gland on the pilot and retract or extract the pilot assembly: (1)
(2)
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If the pilot is just to be retracted: (a)
Retract it until it reaches the limit of the retraction bar.
(b)
Tighten the packing gland on the pilot.
(c)
Verify that the pilot burner is still being purged with nitrogen as indicated by the associated rotameter.
If the pilot is to be completely extracted: (a)
Retract it until the retaining chain is taut.
(b)
Close the block valve to isolate the pilot from the furnace.
(c)
Close the block valve in the nitrogen purge to the pilot burner.
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SULFUR BLOCK (d)
Disconnect the chain and remove the pilot assembly and store it in a safe place. CAUTION: THE PILOT ASSEMBLY WILL BE VERY HOT. HANDLE IT CAREFULLY TO AVOID BURNS AND TO AVOID DAMAGING IT.
(3) O.
Verify that the pilot burner mounting nozzle is still being purged with nitrogen as indicated by the associated rotometer.
Place the air:acid gas ratio control loop in service as follows: (1)
Confirm that the air demand controller in the DCS is in "manual" and its output is set at 50%.
(2)
Confirm that the process air flow controller in the DCS is in "cascade".
(3)
Confirm that the output of the process air flow controller is tracking the output of the manual air control on the local SRU control panel.
(4)
Confirm that the setpoint of the process air flow controller is tracking its current reading.
(5)
Confirm that the "coarse" setting of the air:acid gas manual ratio set (HIC) is being back-calculated so that the remote setpoint it supplies to the process air flow controller matches the current "local" air flow setpoint on the controller.
(6)
Switch the process air hand switch (HS) from "local" to "remote".
The DCS process air flow controller now has control of the control valves on the Process Air Blower, so that the process air flow rate will be ratio-controlled automatically with the amine acid gas flow rate. The output from the manual ratio set (HIC) will remain fixed at its last value. P.
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Observe the temperatures in the catalyst beds and in the Reactor outlet lines. These temperatures should begin to rise as the Claus reaction is initiated. Watch the steam pressures and water levels in the boilers to confirm that the control systems are functioning Sulfur Recovery
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SULFUR BLOCK properly. Q.
If the Sulfur Drain Seals were not pre-filled with liquid sulfur to seal them prior to startup, the block valves in the rundown lines will all be closed at this time. After operating on acid gas for about 30 minutes, open the block valve on the first condenser pass drain line. Sufficient sulfur should have been produced by then to seal this drain seal. If the drain seal does not seal within 30 seconds, close the valve and try it again every 30 minutes or so until it seals.
R.
After the first drain seals, open the block valve to the second drain seal at approximately one hour intervals until it seals. Repeat this with the third and fourth drain seals.
WARNING
MAKE SURE EACH DRAIN SEAL HAS SEALED BEFORE LEAVING ITS BLOCK VALVE OPEN. IF THE BLOCK VALVE TO AN UNSEALED DRAIN SEAL REMAINS OPEN, PROCESS GAS CONTAINING POISONOUS H2S AND SO2 WILL ENTER THE SULFUR SURGE TANK AND BE RELEASED TO THE SURROUNDING AREA. S.
After operating for a few hours on acid gas, the process temperatures can be lowered somewhat from the levels established during startup. (1)
Confirm that the Waste Heat Boiler steam pressure controller is set at 48.5 kg/cm2(g) and is controlling.
(2)
The three reactor feed temperature controllers are in "manual" at this time. Confirm that their setpoints are tracking their current readings then switch the controllers to "automatic". Slowly reduce the temperature setpoints to their normal values.
(3)
Adjust the setpoint of the Sulfur Condenser steam pressure controller to 1.75 kg/cm2(g). This will cause the steam back-pressure control valve on the Sulfur Condenser to remain wide open under normal
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SULFUR BLOCK circumstances, allowing the steam pressure to remain as low as possible by "floating" on the LP steam header. Keeping the steam pressure as low as possible in the Sulfur Condenser allows it to remove the maximum amount of sulfur from the process streams and reduces the load on the downstream TGCU. Giving the Sulfur Condenser steam pressure controller a setpoint of 1.75 kg/cm2(g) will ensure that the water in the Sulfur Condenser shell stays safely above the freezing temperature of sulfur by causing the steam pressure control valve to maintain back-pressure in the shell of the Sulfur Condenser if the pressure in the steam header should drop below this value for any reason. T.
If the air demand analyzer is not in service and operating properly after the SRU has been on-stream for 24 hours, manually analyze a sample of the process gas leaving the fourth pass of the Sulfur Condenser to determine the H2S:SO2 ratio, using one of the laboratory procedures in Section 9.10 of this manual. As discussed earlier, maximum sulfur recovery is obtained when the H2S:SO2 ratio is 2:1. If the H2S:SO2 ratio is higher than 2:1, the SRU is running with less than optimum air (i.e., "air deficient"). Increase the setting on the air:acid gas manual ratio set (HIC) to raise the air:acid gas ratio and reduce the H2S:SO2 ratio in the process gas. If the H2S:SO2 ratio is lower than 2:1, the SRU is running with more than optimum air (i.e., "excess air"). Reduce the setting on the air:acid gas manual ratio set (HIC) to lower the air:acid gas ratio and increase the H2S:SO2 ratio in the process gas.
U.
If the air demand analyzer is in service, adjust the air:acid gas ratio as necessary with the air:acid gas manual ratio set (HIC) to bring the air demand displayed on the air demand controller "on-scale" (between -10.0% and +10.0%). If the air demand is high (0.0% to +10.0%), the air:acid gas ratio is too high (i.e., "excess air"). Reduce the setting on the air:acid gas manual ratio set (HIC) to lower the air:acid gas ratio and reduce the air demand. If the air demand is low (-10.0% to 0.0%), the air:acid gas ratio is too low (i.e., "air deficient"). Increase the setting on the air:acid gas
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SULFUR BLOCK manual ratio set (HIC) to raise the air:acid gas ratio and increase the air demand. Once the air demand is "on-scale", switch the air demand controller to "automatic" and adjust its setpoint to 0.0% air demand. the air demand controller will now adjust the ratio setting from the air:acid gas manual ratio set (HIC) via relays to keep a 2:1 H2S:SO2 ratio in the tailgas leaving the SRU. V.
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The sulfur plant is now on-stream, firing on amine acid gas. Before bringing in SWS gas or directing your attention away from the SRU, be sure that: (1)
All controllers are functioning properly.
(2)
Sulfur is draining freely from each rundown line.
(3)
All steam heating systems are in service and the steam traps are functioning properly.
(4)
The Warmup Bypass Valves are fully closed.
(5)
The Thermal Oxidizer is functioning properly.
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SULFUR BLOCK 9.8.3
SWS Gas Flow Once the SRU is operating stably on amine acid gas, the SWS gas stream can be introduced into the SRU. Do not attempt to bring in the SWS gas if the SRU is not running smoothly on amine acid gas, as this will make it that much harder to stabilize the unit. Instead, focus your attention on stabilizing the operation of the SRU first (usually by correcting a problem in the upstream Amine Regeneration Unit), and then use the procedure below to establish SWS gas flow into the SRU. Before commencing SWS gas flow, it will be necessary to raise and control the temperature in the front combustion zone of the Reactor Furnace to prepare it for ammonia destruction. A.
Issued 30 August 2011
Before beginning, confirm that the following conditions are all true: (1)
SWS gas flow on/off switch in the DCS is set to "on" so that this flow will be included in the air:acid gas ratio control system.
(2)
All vent and drain valves on the SWS Gas Knock-Out Drum, its piping, and the SWS Gas Knock-Out Drum Pump are closed and plugged.
(3)
Any blinds installed in the inlet SWS gas line have been removed.
(4)
The block valves are lined up to place a SWS Gas Knock-Out Drum Pump in service, the H-O-A selector switch on that pump is set to "AUTO", and the pump level control transmitter is in service.
B.
At this time, the bypass amine acid gas flow ratio controller in the DCS is in "manual" with its output set to 0%. As a result, the bypass acid gas control valve is closed, forcing all of the amine acid gas to flow to the Acid Gas Burner.
C.
Confirm that the Reactor Furnace front zone temperature controller is in "automatic".
D.
Confirm that the setpoint of the bypass acid gas flow ratio controller is tracking its current reading (which should be zero), then switch it to "automatic".
E.
Slowly raise the ratio setpoint on the bypass acid gas flow ratio controller to begin opening the bypass acid gas control valve and
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SULFUR BLOCK bypassing some of the amine acid gas to the side injection ports on the furnace. This should begin to raise the temperature in the front zone of the furnace. F.
Continue to raise the ratio setpoint on the bypass acid gas flow ratio controller until the temperature indicated on the front zone temperature controller is approximately 1200°C. NOTE:
The 1370°C temperature for ammonia destruction discussed in earlier sections is a calculated temperature. The temperature indicated by an optical pyrometer is usually 100-200°C lower than the calculated temperature for a given set of conditions, so a normal operating temperature of 1200°C is suggested for the front zone of the furnace. Operating experience will dictate the minimum indicated temperature at which SWS gas can be admitted to the furnace.
G.
It may become necessary for the bypass acid gas flow ratio controller to "pinch" flow control valve on the amine acid gas to the acid gas burner in order to obtain enough bypass acid gas flow through the bypass acid gas control valve. After the bypass acid gas flow ratio controller is controlling the bypass acid gas flow and the furnace temperature is up to about 1200°C, the furnace is ready to accept SWS gas.
Issued 30 August 2011
H.
Slowly increase the output from the SWS gas flow control (HIC) on the local SRU control panel to begin opening the SWS gas inlet valve using the flow indicator on the local SRU control panel to monitor the SWS gas flow rate.
I.
As SWS gas begins flowing to the Acid Gas Burner, the air:acid gas ratio control system will begin sending additional process air to the burner to combust the SWS gas. Increase the SWS gas flow slowly to allow time for the ratio control system to adjust to the increasing SWS gas flow.
J.
Continue to slowly increase the output from the SWS gas flow control (HIC) to 100% so that the SWS gas inlet valve is fully open.
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SULFUR BLOCK K.
Monitor the bypass acid gas flow ratio controller to verify that it maintains control of the bypass acid gas flow and that the front zone temperature in the Reactor Furnace remains about 1200°C.
L.
Observe the air demand controller and adjust the air:acid gas ratio with the air:acid gas manual ratio set (HIC) if necessary to help keep the air demand "on-scale". If the air demand is high (0.0% to +10.0%), reduce the output from the air:acid gas manual ratio set (HIC) to lower the ratio and reduce the air demand. If the air demand is low (-10.0% to 0.0%), increase the output from the air:acid gas manual ratio set (HIC) to raise the ratio and increase the air demand.
M.
N.
Issued 30 August 2011
If the optical pyrometer on the Reactor Furnace is giving reliable indication of the front zone temperature in the furnace the temperature cascade control can be placed in service as follows: (1)
Confirm that the remote ratio setpoint that the front zone temperature controller is supplying to the bypass ratio controller matches the current setting on the ratio controller.
(2)
Confirm that the front zone temperature controller is in "automatic" and its setpoint is tracking its current reading.
(3)
Switch the bypass acid gas flow ratio controller to "cascade" so that the temperature controller can now adjust the ratio setpoint on the ratio controller.
(4)
If necessary, slowly adjust the setpoint of the front zone temperature controller to its normal setpoint of 1200°C.
(5)
Verify that the bypass acid gas flow ratio controller is adjusting the bypass gas flow rate as needed to control the desired temperature setting on the front zone temperature controller.
The sulfur plant is now fully on-stream, firing on both amine acid gas and SWS gas. Before switching the SRU tailgas to the TGCU or directing your attention away from the SRU, be sure that: (1)
All controllers are functioning properly.
(2)
Sulfur is draining freely from each rundown line.
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SULFUR BLOCK
9.8.4
(3)
All steam heating systems are in service and the steam traps are functioning properly.
(4)
The Thermal Oxidizer is functioning properly.
Routing SRU Tailgas to the TGCU Before switching the SRU tailgas from the Thermal Oxidizer to the TGCU Tailgas Cleanup Unit, be sure all of the following conditions are true: (1)
The SRU is operating stably on amine acid gas, or on amine acid gas and SWS gas.
(2)
The air demand indicated on the air demand controller is +2.0% or lower.
If the air demand is higher than this, the SRU tailgas contains excessive amounts of SO2 and could cause overheating of the TGCU Reactor in the TGCU. (3)
The TGCU has been warmed up to operating temperature and is ready to accept SRU tailgas.
If any of these conditions are not true, do not attempt to bring SRU tailgas into the TGCU. In particular, do not attempt switching tailgas to the TGCU when the sulfur plant is upset. The result will be two upset units to deal with. Instead, focus your attention on stabilizing the operation of the SRU first (usually by correcting a problem in the upstream Amine Regeneration Unit and/or Sour Water Stripper Unit). Then use the operating procedures for the TGCU in Section 11 of these guidelines to switch the SRU tailgas from flowing to the Thermal Oxidizer to flowing into the TGCU. Once the sulfur plant tailgas is flowing to the TGCU, be sure of the following before directing your attention away from the SRU:
Issued 30 August 2011
(1)
The Tailgas Valve to the TTO and the TGCU Warmup/Bypass Valve are fully closed.
(2)
This is necessary to prevent leakage of SRU tailgas to the TTO that would cause high SO2 emissions and the resulting permit violation.
(3)
All controllers are functioning properly.
(4)
Sulfur is draining freely from each rundown line.
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SULFUR BLOCK
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(5)
All steam heating systems are in service and the steam traps are functioning properly.
(6)
The TGCU and the Thermal Oxidizer are functioning properly.
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SULFUR BLOCK 9.8.5
Normal Startup - Cold System The procedure for startup of an SRU after it has been shut down long enough to get cold (less than about 750°C in the Reactor Furnace) will be very similar to the procedure for the initial startup, Sections 9.8.1 through 9.8.4 of this manual. However, the steps to be performed are written in this section to serve as a "check list" that can be easily followed on subsequent startups. Refer to the previous sections for the reasons and details pertaining to the different steps performed.
NOTE
THIS PROCEDURE USES THE WARMUP BYPASS VALVES TO ROUTE THE FUEL GAS COMBUSTION PRODUCTS DIRECTLY TO THE THERMAL OXIDIZER WHILE WARMING UP THE SRU. (THIS PREVENTS OXYGEN-BEARING GASES FROM REACHING THE REACTOR BEDS AND CAUSING SULFUR FIRES IN THE CATALYST.) IT IS NORMAL TO PRODUCE A SMALL SO2 PLUME FROM THE THERMAL OXIDIZER WHEN USING THE WARMUP BYPASS LINE AS THE OXYGEN IN THE COMBUSTION GAS REACTS WITH THE SULFUR COATING THE WALLS OF THE PIPING AND EQUIPMENT TO FORM SO2. HOWEVER, IF A LARGE AMOUNT OF SO2 IS BEING RELEASED FROM THE STACK, THIS MAY BE AN INDICATION THAT SULFUR HAS ACCUMULATED INSIDE THE SRU FOR SOME REASON. TO PREVENT DAMAGE TO THE EQUIPMENT, SHUT DOWN THE SRU AND VERIFY THAT THE FIRST PASS OF THE SULFUR CONDENSER IS NOT FILLED WITH SULFUR BEFORE CONTINUING.
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SULFUR BLOCK Prior to commencing SRU startup:
9.8.5.1
(1)
Check for the completion of all maintenance work (connecting lines, removing blinds, etc.) if such work was performed.
(2)
If any of the flanged connections in the SRU were opened for maintenance or other purposes while the SRU was off-line, it is good practice to leak test the SRU before returning it to service. Refer to Section 9.7.3 of this manual for a suggested procedure to accomplish this.
(3)
Place all steam heating systems in service. Check all steam traps for proper operation, and use the vent valves to sweep non-condensibles out of the steam spaces.
(4)
Physically check all shutdown activating devices to ensure that they activate the SRU ESD system.
(5)
Check all devices activated by the SRU ESD system to ensure that they operate properly.
(6)
Confirm that both boilers (Waste Heat Boiler and Sulfur Condenser) are filled with water up to their normal liquid levels.
(7)
If the furnace temperature is less than 250°C, insert the startup thermocouple assembly furnished with the optical pyrometer by swinging the pyrometer out of the way, removing the viewport, and attaching the thermocouple adapter to the mounting plate.
Initial Preparations A.
Issued 30 August 2011
Check that all devices in the SRU ESD have been satisfied, except for the following: (1)
Neither blower running.
(2)
Flame failure.
B.
Confirm that the manual block valve in the SRU tailgas line is open.
C.
Confirm that the amine acid gas flow on/off switch is set to "on".
D.
Select local manual control for the control valves on the Process Air Blower by switching the process air hand switch (HS) in the DCS to "local".
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SULFUR BLOCK E.
Place the process air flow controller in "cascade".
F.
Place the air demand controller in "manual" and set its output to 50%.
G.
Confirm that the manual signal bias control for the blower to be used is set to 100%.
H.
Select local manual control for the fuel gas flow control valve by switching the main fuel gas hand switch (HS) in the DCS to "local".
I.
Place the fuel gas flow controller in "automatic".
J.
Confirm that the fuel gas flow on/off switch is set to "on".
K.
Place the Reactor Furnace front zone temperature controller in "automatic".
L.
Place the bypass acid gas flow controller in "manual" and set its output to 0%.
M.
Confirm that Acid Gas Firing switch on the local SRU control panel is set to "DISABLED".
N.
Confirm that Leak Test key switch on the local SRU control panel is set to "NORMAL".
O.
Confirm that Reactor Cool-Down key switch on the local SRU control panel is set to "NORMAL".
P.
Set the amine acid gas flow control (HIC) and the SWS gas flow control (HIC) on the local SRU control panel to 0% output. Visually confirm that the amine acid gas inlet valve and the SWS gas inlet valve are closed. If either of these valves is not closed, H2S will be routed directly to the Thermal Oxidizer when the Warmup Bypass Valves are opened. This could cause overheating of the Thermal Oxidizer.
Q.
Set the manual fuel gas control on the local SRU control panel to 0% output. Visually confirm that the main fuel gas valve and the two shutdown valves are closed.
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SULFUR BLOCK
9.8.5.2
R.
Set the air flow control (HIC) on the local SRU panel to 0% output.
S.
Verify that the acid gas control valve in the amine acid gas line to the burner is fully open.
T.
Verify that the bypass acid gas control valve in the bypass acid gas line is fully closed.
U.
Loosen the packing gland on the pilot mounting nozzle. If the pilot was extracted previously, insert the pilot assembly, connect its retaining chain, and open the block valve. Slide the pilot all the way in then tighten the packing gland. Open the block valve in the purge nitrogen to the pilot and confirm that the pilot and the pilot mounting nozzle are both being purged with nitrogen.
Igniting the Pilot Burner A.
Switch the Startup/Run selector switch on the local SRU control panel to "STARTUP". The PLC will open the two Warmup Bypass Valves and close the Tailgas Valve to the TTO and the Tailgas Valve to the TGCU. Verify that the "WARMUP OPEN" light on the panel is now illuminated and the "TTO OPEN" and "TGCU OPEN" lights on the panel are extinguished. NOTE:
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If a status light continues to flash, it means that the limit switches on the associated valve(s) never confirmed that the valve(s) moved to the proper position. If this occurs, the startup sequence will not be allowed to proceed until the problem is corrected and the valve(s) move to the proper position.
B.
Verify that the local start/stop controls for the Process Air Blowers have their selector switches turned to the "STOP" position.
C.
Verify that the suction, discharge, and blow-off valves on both blowers are all closed.
D.
Start a Process Air Blower:
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SULFUR BLOCK (1)
Press the local push-button to give a “permit to start” for the desired blower.
(2)
Start the blower using the local start/stop control station for that blower.
E.
Confirm that the air blower is running, then press the "ESD RESET" push-button on the local SRU control panel to reset the SRU ESD and extinguish the "RESET REQUIRED" light. This will illuminate the "PURGE REQUIRED" light.
F.
Verify that the "LIMITS SATISFIED" light is glowing steadily (not flashing) on the local SRU control panel. NOTE:
If the "LIMITS SATISFIED" light is flashing, this means that either a limit switch or a pressure transmitter is not satisfied. The limit switches on the amine acid gas, SWS gas, and fuel gas valves must all indicate that their respective valves are closed, and the two pressure transmitters on the main fuel gas must be satisfied. For safety reasons, the BMS will not allow the light-off sequence to proceed until all these conditions are satisfied. Once the problem with the valves, their limit switches, or the pressure transmitters has been corrected, the "LIMITS SATISFIED" light will stop flashing and glow steadily, and the light-off sequence can proceed.
G.
Issued 30 August 2011
Open the following manual block valves: (1)
The manual block valve(s) in the main fuel gas supply line.
(2)
The manual block valve(s) in the fuel gas supply line to the burner.
(3)
The manual block valve(s) in the fuel gas supply to the pilot.
(4)
The manual block valve(s) in the instrument air supply to the pilot.
(5)
The manual block valve(s) in the instrument air supply to the pilot.
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SULFUR BLOCK H.
Adjust the output of the air flow control (HIC) on the local SRU panel to open the blower control valves and allow a large air flow, 80% or more the flow indicator, to purge the furnace for 30 seconds and extinguish the "PURGE REQUIRED" light. The "PURGE COMPLETE" light will then be illuminated.
I.
Adjust the output of the air flow control (HIC) on the local SRU panel to reduce the air flow to 10-20%, extinguishing the "PURGE COMPLETE" light and illuminating the "PERMIT TO IGNITE" light. NOTE:
J.
Press the "IGNITION" push-button to initiate an ignition attempt.
K.
If neither flame scanner detects a flame after 15 seconds of sparking the ignitor, the ignition try is aborted, the SRU Burner Shutdown system is activated, and the PLC causes the sequence to return to Step G.
L.
When either flame scanner detects a flame from the pilot burner, the pilot air and fuel gas valves remain open, the "PILOT ON" light remains illuminated, and the PLC enables the "FUEL GAS ON" push-button and the "RUN" position on the Startup/Run selector switch.
M.
After the pilot is lit, use the air flow control (HIC) on the local SRU panel to increase the air flow rate to about 50% of scale, or as high a rate as can be maintained without blowing the pilot out.
N.
Open the vent valves on each of the two boilers to vent air from the steam sections.
O.
The heat input from the pilot will be sufficient during the early part of the refractory warmup schedule. If the temperature is rising too quickly, increase the air flow rate. If the temperature is rising too slowly, decrease the air flow rate. NOTE:
Issued 30 August 2011
Remember that the ignition safety timer will shut down the SRU if an ignition attempt is not made within 5 minutes of receiving the "PERMIT TO IGNITE".
The refractory warmup schedule for normal warmup, (supplied by the refractory vendor), should be used for normal startup with a cold system.
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SULFUR BLOCK 9.8.5.3
Igniting the Main Warmup Burner / Refractory Warmup When the firing rate needs to be increased to raise the furnace temperature, the main warmup burner should be placed in service. A.
Confirm that in the main fuel gas line is fully closed.
B.
Confirm that the manual block valve(s) in the main fuel gas line to the burner is open.
C.
If the air flow rate is not at 50% of scale, use the air flow control (HIC) on the local SRU panel to set the air flow at about 50% of scale.
D.
Press the "FUEL GAS ON" push-button on the local SRU control panel to open the main fuel gas block valves and illuminate the “FUEL GAS ON” light.
E.
Adjust the output of the main fuel gas flow control (HIC) on the local control panel to slowly open the control valve to commence fuel gas flow to the warmup burner ring. Adjust the fuel gas flow rate until a stable flame can be maintained.
F.
Adjust the fuel gas flow rate with the main fuel gas flow control (HIC) as necessary to cause the furnace temperature to follow the refractory warmup schedule for normal warmup.
G.
Frequently confirm that the proper water levels are maintained in the Waste Heat Boiler and the Sulfur Condenser. Confirm that the level control systems are functioning properly.
H.
As the steam pressure starts to build in the Waste Heat Boiler, put the Waste Heat Boiler Steam pressure controller in the DCS in "automatic" with a setpoint of 48.5 kg/cm2(g).
I.
Place the three temperature controllers for the Reactor feeds, in "manual" and set their outputs to 100%. This will fully open the valves in the condensate outlet lines from the reheat exchangers and ensure that the Reactor feeds are as hot as possible when the switch to acid gas firing is made.
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SULFUR BLOCK J.
As the steam pressure starts to build in the Sulfur Condenser, put the Sulfur Condenser steam pressure controller in the DCS in "automatic" with a setpoint of 4.2 kg/cm2(g).
K.
During the early part of warmup, monitor the furnace temperature using the startup thermocouple assembly and the hand-held digital display unit. The thermocouple will be used until the first "hold" point (about 250°C) in the warmup schedule is reached. Once the first "hold" point in the warmup schedule has been reached, the optical pyrometer can be placed in service. After the furnace temperature has stabilized, slide the thermocouple out until the "keepers" stop them, close the pyrometer block valve, then unscrew the adapter housing and store them in a safe place. CAUTION:
THE THERMOCOUPLES WILL BE VERY HOT. HANDLE THEM CAREFULLY TO AVOID BURNS AND TO AVOID DAMAGING THE THERMOCOUPLES.
Replace the viewport lens on the pyrometer mounting plate (with the o-ring in place) and put the pyrometer back in service so that the furnace temperature is indicated on the local indicator and the controller in the DCS. Confirm that the purge system for the pyrometer viewport lens is operating. L.
Confirm that all steam heating systems on the sulfur rundown lines, sulfur drain seals, sulfur collection header, sulfur pump, and valve jackets are in service. Check all steam traps for proper operation, and use the vent valves to sweep non-condensibles out of the steam spaces.
M.
As the steam pressures build in the boilers, the vent valves on the steam spaces may be closed.
At the conclusion of this procedure, the SRU is ready to process acid gas. However, the SRU can run indefinitely in this mode until the other systems are ready. Monitor the Reactor Furnace temperature on the furnace temperature controller and make adjustments to the fuel gas flow as needed to control this temperature around 1200°C.
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SULFUR BLOCK 9.8.5.4
Amine Acid Gas Flow At the end of the refractory warmup schedule, the SRU is firing on fuel gas (using the warmup bypass line to divert the combustion products to the Thermal Oxidizer) and is ready to accept acid gas. The switch to acid gas firing is accomplished by routing the combustion products through SRU, then rapidly swapping acid gas for fuel gas. A.
Issued 30 August 2011
Before commencing acid gas flow, confirm that the following conditions are all true: (1)
The steam pressure in the Waste Heat Boiler is 48.5 kg/cm2(g) or higher.
(2)
The steam pressure 4.2 kg/cm2(g) or higher.
(3)
The Thermal Oxidizer is ready to accept SRU tailgas.
(4)
All vent and drain valves on the Acid Gas Knock-Out Drum, its piping, and the Acid Gas Knock-Out Drum Pump are closed and plugged.
(5)
The block valves are lined up to place an Acid Gas Knock-Out Drum Pump in service, the H-O-A selector switch on that pump is set to "AUTO", and the pump level control transmitter is in service.
in
the
Sulfur
Condenser
is
B.
Confirm that the bypass acid gas flow ratio controller in the DCS is still in "manual" with its output set to 0%.
C.
Verify that the bypass acid gas control valve is fully closed.
D.
Verify that the acid gas control valve in the amine acid gas line to the Acid Gas Burner is fully open.
E.
Adjust the process air flow rate to 50% of scale on the local indicator using the air flow control (HIC) on the local SRU panel. Reduce the fuel gas flow rate to 50% of scale on the local indicator using the main fuel gas flow control (HIC) on the local panel.
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SULFUR BLOCK
WARNING
AS SOON AS THE TAILGAS VALVE IS OPENED IN THE NEXT STEP, OXYGEN-BEARING GASES WILL BEGIN FLOWING THROUGH THE CATALYST BEDS. IF THE CATALYST IS HOTTER THAN THE AUTO-IGNITION TEMPERATURE OF SULFUR ON CLAUS CATALYST (150°C), THE SULFUR CONTAINED IN THE CATALYST WILL BEGIN TO BURN. FOR THIS REASON, IT IS IMPORTANT THAT THE SWITCH FROM FIRING FUEL GAS TO FIRING ACID GAS BE MADE AS QUICKLY AS POSSIBLE. IF ANY DELAYS IN INTRODUCING ACID GAS ARE ENCOUNTERED, IMMEDIATELY SWITCH THE STARTUP/RUN SELECTOR SWITCH BACK TO "STARTUP" TO OPEN THE WARMUP BYPASS VALVES AND CLOSE THE TAILGAS VALVE SO THAT THE CATALYST BEDS DO NOT CONTINUE TO BURN. F.
Switch the Startup/Run selector switch on the local SRU control panel to "RUN" to route the combustion gases through the SRU. The PLC will open the Tailgas Valve to the Thermal Oxidizer then close the Warmup Bypass Valves. The "TTO OPEN" light will be illuminated, then the "WARMUP OPEN" light will be extinguished as the valves move to their new positions. NOTE:
If a valve status light continues to flash, it means that the limit switches on the associated valve(s) never confirmed that the valve(s) moved to the proper position. If this occurs, the startup sequence cannot proceed until the problem is corrected and the valve(s) move to the proper position. Should this occur, switch the Startup/Run selector switch back to "STARTUP" so that the catalyst beds do not continue to burn.
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SULFUR BLOCK G.
Switch the Acid Gas Firing selector switch on the local SRU control panel to "ENABLED".
H.
Increase the output from the amine acid gas flow control (HIC) on the local SRU control panel to begin opening the amine acid gas inlet valve until the acid gas flow rate is approximately 10% on the local indicator.
I.
As soon as the acid gas flow rate reaches 10%, use the main fuel gas flow control (HIC) to reduce the fuel gas flow rate from 50% to 40% on the local indicator.
J.
Continue to add amine acid gas in 10% increments and reduce the fuel gas in 10% increments until the fuel gas control valve is completely closed.
K.
Press the “FUEL GAS OFF” push-button to "double block and bleed" the main fuel gas and the "PILOT OFF" push-button to "double block and bleed" the pilot fuel gas. Verify that the “fuel gas on” and the "PILOT ON" lights are both extinguished, and that the warmup burner and pilot burner are being purged with nitrogen.
L.
Continue to slowly increase the output from the amine acid gas flow control (HIC) to 100% so that the amine acid gas inlet valve is fully open.
M.
If the amine acid gas flow rate (in percent) displayed on the local control panel is significantly different from the air flow rate (in percent) displayed on the local control panel, use the air flow control (HIC) on the local SRU panel to adjust the air flow until the percentages are about the same.
N.
Close the following manual block valves:
O.
Issued 30 August 2011
(1)
The two manual block valve(s) in the main fuel gas line.
(2)
The manual block valve(s) in the fuel gas to the pilot.
(3)
The manual block valve(s) and manual block valve(s) in the instrument air to the pilot.
Loosen the packing gland on the pilot and retract or extract the pilot assembly:
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SULFUR BLOCK (1)
(2)
If the pilot is just to be retracted: (a)
Retract it until it reaches the limit of the retraction bar.
(b)
Tighten the packing gland on the pilot.
(c)
Verify that the pilot burner is still being purged with nitrogen.
If the pilot is to be completely extracted: (a)
Retract it until the retaining chain is taut.
(b)
Close the block valve to isolate the pilot from the furnace.
(c)
Close the block valve in the nitrogen purge to the pilot burner.
(d)
Disconnect the chain and remove the pilot assembly and store it in a safe place. CAUTION: THE PILOT ASSEMBLY WILL BE VERY HOT. HANDLE IT CAREFULLY TO AVOID BURNS AND TO AVOID DAMAGING IT.
(3) P.
Issued 30 August 2011
Verify that the pilot burner mounting nozzle is still being purged with nitrogen.
Place the air:acid gas ratio control loop in service as follows: (1)
Confirm that the air demand controller in the DCS is in "manual" and its output is set at 50%.
(2)
Confirm that the process air flow controller in the DCS is in "cascade", its output is tracking the output of the air flow control (HIC) on the local SRU control panel, and its setpoint is tracking its current reading.
(3)
Confirm that the "coarse" setting on the air:acid gas manual ratio set (HIC) is being back-calculated so that the remote setpoint it supplies to the air flow controller matches the current "local" setpoint on the controller.
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SULFUR BLOCK (4)
Q.
Switch the process air hand switch (HS) from "local" to "remote" to give the process air flow controller in the DCS control of the Process Air Blower, so that the process air flow rate will be ratio-controlled automatically. The output from the air:acid gas manual ratio set (HIC) will remain fixed at its last value.
Adjust the air:acid gas ratio as necessary with the air:acid gas manual ratio set (HIC) to bring the air demand displayed on the air demand controller "on-scale" (between -10.0% and +10.0%). If the air demand is high (0.0% to +10.0%), the air:acid gas ratio is too high (i.e., "excess air"). Reduce the setting on the air:acid gas manual ratio set (HIC) to lower the air:acid gas ratio and reduce the air demand. If the air demand is low (-10.0% to 0.0%), the air:acid gas ratio is too low (i.e., "air deficient"). Increase the setting on the air:acid gas manual ratio set (HIC) to raise the air:acid gas ratio and increase the air demand. Once the air demand is "on-scale", switch the air demand controller to "automatic" and adjust its setpoint to 0.0% air demand.
Issued 30 August 2011
R.
Observe the temperatures in the catalyst beds and in the Reactor outlet lines. These temperatures should begin to rise as the Claus reaction is initiated. Watch the steam pressures and water levels in the boilers to confirm that the control systems are functioning properly.
S.
After operating for a few hours on acid gas, the process temperatures can be lowered somewhat from the levels established during startup. (1)
Confirm that the Waste Heat Boiler steam pressure controller is set at 48.5 kg/cm2(g) and is controlling.
(2)
Confirm that the three temperature controllers for the Reactor feeds, are tracking their current readings then switch the controllers to "automatic". Slowly reduce the temperature setpoints to their normal values.
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SULFUR BLOCK (3)
T.
Issued 30 August 2011
Adjust the setpoint of the Sulfur Condenser steam pressure controller, the Sulfur Condenser steam pressure controller, to 1.75 kg/cm2(g).
The sulfur plant is now on-stream, firing on amine acid gas. Before bringing in SWS gas or directing your attention away from the SRU, be sure that: (1)
All controllers are functioning properly.
(2)
Sulfur is draining freely from each rundown line.
(3)
All steam heating systems are in service and the steam traps are functioning properly.
(4)
The Warmup Bypass Valves are fully closed.
(5)
The Thermal Oxidizer is functioning properly.
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SULFUR BLOCK 9.8.5.5
SWS Gas Flow Once the SRU is operating stably on amine acid gas, the SWS gas stream can be introduced into the SRU. Do not attempt to bring in the SWS gas if the SRU is not running smoothly on amine acid gas, as this will make it that much harder to stabilize the unit. Instead, focus your attention on stabilizing the operation of the SRU first (usually by correcting a problem in the upstream Amine Regeneration Units), and then use the procedure below to establish SWS gas flow into the SRU. A.
Check that all vent and drain valves on the SWS Gas Knock-Out Drum, its piping, and the SWS Gas Knock-Out Drum Pump are closed and plugged.
B.
Line up the block valves to place a SWS Gas Knock-Out Drum Pump in service, set the H-O-A selector switch on that pump to "AUTO", and verify that the pump level control transmitter is in service.
C.
Confirm that the SWS gas flow on/off switch in the DCS is set to "on".
D.
Confirm that the Reactor Furnace front zone temperature controller is in "automatic".
E.
Confirm that the setpoint of the bypass acid gas flow ratio controller is tracking the current reading (which should be zero), then switch it to "automatic".
F.
Slowly raise the ratio setpoint on the bypass acid gas flow ratio controller to begin opening the bypass acid gas control valve and bypassing some of the amine acid gas to the side injection ports on the furnace.
G.
Continue to raise the ratio setpoint on the bypass acid gas flow ratio controller until the front zone temperature indicated on the front zone temperature controller is approximately 1200°C. After the bypass acid gas flow ratio controller is controlling the bypass acid gas flow and the furnace temperature is up to about 1200°C, the furnace is ready to accept SWS gas.
Issued 30 August 2011
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SULFUR BLOCK H.
Slowly increase the output from the SWS gas flow control (HIC) on the local SRU control panel to begin opening the SWS gas inlet valve.
I.
As SWS gas begins flowing to the Acid Gas Burner, the air:acid gas ratio control system will begin sending additional process air to the burner to combust the SWS gas. Increase the SWS gas flow slowly to allow time for the ratio control system to adjust to the increasing SWS gas flow.
J.
Continue to slowly increase the output from the SWS gas flow control (HIC) to 100% so that the SWS gas inlet valve is fully open.
K.
Monitor the bypass acid gas flow ratio controller to verify that it maintains control of the bypass acid gas flow and that the front zone temperature in the Reactor Furnace remains about 1200°C.
L.
Observe the air demand controller and adjust the air:acid gas ratio with the air:acid gas manual ratio set (HIC) if necessary to help keep the air demand "on-scale". If the air demand is high (0.0% to +10.0%), reduce the setting on the air:acid gas manual ratio set (HIC) to lower the ratio and reduce the air demand. If the air demand is low (-10.0% to 0.0%), increase the setting on the air:acid gas manual ratio set (HIC) to raise the ratio and increase the air demand.
M.
Issued 30 August 2011
If the optical pyrometeris giving reliable indication of the front zone temperature in the furnace, place the temperature cascade control in service as follows: (1)
Confirm that the remote ratio setpoint that the temperature controller is supplying to the bypass acid gas flow ratio controller matches the current setting on the ratio controller.
(2)
Confirm that the temperature controller is in "automatic" and its setpoint is tracking its current reading.
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SULFUR BLOCK
N.
9.8.5.6
(3)
Switch the bypass acid gas flow ratio controller to "cascade". If necessary, slowly adjust the setpoint of the temperature controller to its normal setpoint of 1200°C.
(4)
Verify that the controllers are adjusting the bypass gas flow rate as needed to control the desired temperature in the front zone of the Reactor Furnace.
The sulfur plant is now fully on-stream, firing on both amine acid gas and SWS gas. Before switching the SRU tailgas to the TGCU or directing your attention away from the SRU, be sure that: (1)
All controllers are functioning properly.
(2)
Sulfur is draining freely from each rundown line.
(3)
All steam heating systems are in service and functioning properly.
(4)
The Thermal Oxidizer is functioning properly.
Routing SRU Tailgas to the TGCU Before switching the SRU tailgas from the Thermal Oxidizer to the TGCU Tailgas Cleanup Unit, be sure all of the following conditions are true: (1)
The SRU is operating stably on amine acid gas, or on amine acid gas and SWS gas.
(2)
The air demand indicated on the air demand controller is +2.0% or lower.
(3)
The TGCU has been warmed up to operating temperature and is ready to accept SRU tailgas.
If any of these conditions are not true, do not attempt to bring SRU tailgas into the TGCU. In particular, do not attempt switching tailgas to the TGCU when the sulfur plant is upset. The result will be two upset units to deal with. Instead, focus your attention on stabilizing the operation of the SRU first (usually by correcting a problem in the upstream Amine Regeneration Unit and/or Sour Water Stripper Unit), and then use the operating procedures for the TGCU in the TGCU Section of these guidelines to switch the SRU tailgas from flowing to the Thermal Oxidizer to flowing into the TGCU.
Issued 30 August 2011
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SULFUR BLOCK Once the sulfur plant tailgas is flowing to the TGCU, be sure of the following before directing your attention away from the SRU:
9.8.6
(1)
The Tailgas Valve to the Thermal Oxidizer and the TGCU Warmup/Bypass Valve are fully closed.
(2)
All controllers are functioning properly.
(3)
Sulfur is draining freely from each rundown line.
(4)
All steam heating systems are in service and the steam traps are functioning properly.
(5)
The TGCU and the Thermal Oxidizer are functioning properly.
Normal Startup - Hot System When an SRU shutdown occurs due to some minor malfunction which can be corrected quickly, it is desirable to restart the plant in a minimum amount of time. The following procedure should be followed to accomplish a rapid restart of the SRU when it is already hot (750°C or higher in the Reactor Furnace). Refer to the previous sections for the reasons and details pertaining to the different steps performed.
9.8.6.1
Initial Preparations A.
Issued 30 August 2011
Check that all SRU ESD devices have been satisfied, except for the following: (1)
Neither blower running.
(2)
Flame failure.
B.
Confirm that the amine acid gas flow on/off switch is set to "on".
C.
Select local manual control for the control valves on the Process Air Blower by switching the process air hand switch (HS) in the DCS to "local".
D.
Place the process air flow controller in "cascade".
E.
Place the air demand controller in "manual" and set its output to 50%.
F.
Confirm that the manual signal bias control for the blower to be used is set to 100%.
G.
Select local manual control for the fuel gas flow control valve by Sulfur Recovery
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SULFUR BLOCK switching the main fuel gas hand switch (HS) in the DCS to "local". H.
Place the fuel gas flow controller in "automatic".
I.
Confirm that the fuel gas flow on/off switch is set to "on".
J.
Place the Reactor Furnace front zone temperature controller in "automatic".
K.
Place the bypass acid gas flow controller in "manual" and set its output to 0%.
L.
Confirm that Acid Gas Firing switch on the local SRU control panel is set to "DISABLED".
M.
Confirm that Leak Test switch on the local SRU control panel is set to "NORMAL".
N.
Confirm that Reactor Cool-Down switch on the back of the local SRU control panel is set to "NORMAL".
O.
Set the amine acid gas flow control (HIC) and the SWS gas flow control (HIC) on the local SRU control panel to 0% output. Visually confirm that the amine acid gas inlet valve and the SWS gas inlet valve are closed.
P.
Set the manual fuel gas control on the local SRU control panel to 0% output. Visually confirm that the main fuel gas valve and the two shutdown valves are closed.
Issued 30 August 2011
Q.
Set the air flow control (HIC) on the local SRU panel to 0% output.
R.
Verify that the acid gas control valve in the amine acid gas line to the burner is fully open.
S.
Verify that the bypass acid gas control valve in the bypass acid gas line is fully closed.
T.
Loosen the packing gland on the pilot mounting nozzle. If the pilot was extracted previously, insert the pilot assembly, connect its retaining chain, and open the block valve. Slide the pilot all the way in then tighten the packing gland. Open the
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SULFUR BLOCK block valve in the purge nitrogen and confirm that the pilot burner and pilot mounting nozzle are both being purged with nitrogen. 9.8.6.2
Igniting the Pilot Burner A.
Switch the Startup/Run selector switch on the local SRU control panel to "STARTUP". The PLC will open the two Warmup Bypass Valves and close the Tailgas Valve to the TTO and the Tailgas Valve to the TGCU. Verify that the "WARMUP OPEN" light on the panel is now illuminated and the "TTO OPEN" and "TGCU OPEN" lights on the panel are extinguished. NOTE:
B.
Verify that the local start/stop controls for the Process Air Blowers have their selector switches turned to the "STOP" position.
C.
Verify that the suction, discharge, and blow-off valves on both blowers are all closed.
D.
Start a Process Air Blower:
E.
Issued 30 August 2011
If a status light continues to flash, it means that the limit switches on the associated valve(s) never confirmed that the valve(s) moved to the proper position. If this occurs, the startup sequence will not be allowed to proceed until the problem is corrected and the valve(s) move to the proper position.
(1)
Press the local push-button to give a “permit to start” for the desired blower.
(2)
Start the blower using the local start/stop control station for that blower.
Confirm that the air blower is running, then press the "ESD RESET" push-button on the local SRU control panel to reset the SRU ESD and extinguish the "RESET REQUIRED" light. This will illuminate the "PURGE REQUIRED" light.
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SULFUR BLOCK F.
Verify that the "LIMITS SATISFIED" light is glowing steadily (not flashing) on the local SRU control panel. NOTE:
If the "LIMITS SATISFIED" light is flashing, this means that either a limit switch or a pressure transmitter is not satisfied. The limit switches on the amine acid gas, SWS gas, and fuel gas valves must all indicate that their respective valves are closed, and the two pressure transmitters on the main fuel gas must be satisfied. For safety reasons, the BMS will not allow the light-off sequence to proceed until all these conditions are satisfied. Once the problem with the valves, their limit switches, or the pressure transmitters has been corrected, the "LIMITS SATISFIED" light will stop flashing and glow steadily, and the light-off sequence can proceed.
G.
Issued 30 August 2011
Open the following manual block valves: (1)
The manual block valve(s) in the main fuel gas supply line.
(2)
The manual block valve(s) in the fuel gas supply line to the burner.
(3)
The manual block valve(s) in the fuel gas supply to the pilot.
(4)
The manual block valve(s) in the instrument air supply to the pilot.
H.
Adjust the output of the air flow control (HIC) on the local SRU panel to open the blower control valves and allow a large air flow, 80% or more to purge the furnace for 30 seconds and extinguish the "PURGE REQUIRED" light. The "PURGE COMPLETE" light will then be illuminated.
I.
Adjust the output of the air flow control (HIC) on the local SRU panel to reduce the air flow to 10-20%, extinguishing the "PURGE COMPLETE" light and illuminating the "PERMIT TO IGNITE" light.
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SULFUR BLOCK NOTE:
Issued 30 August 2011
Remember that the ignition safety timer will shut down the SRU if an ignition attempt is not made within 5 minutes of receiving the "PERMIT TO IGNITE".
J.
Press the "IGNITION" push-button to initiate an ignition attempt.
K.
If neither flame scanner detects a flame after 15 seconds of sparking the ignitor, the ignition try is aborted, the SRU Burner Shutdown system is activated, and the PLC causes the sequence to return to Step H.
L.
When either flame scanner detects a flame from the pilot burner, the pilot air and fuel gas valves remain open, the "PILOT ON" light remains illuminated, and the PLC enables the "MAIN FUEL START" push-button and the "RUN" position on the Startup/Run selector switch.
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SULFUR BLOCK 9.8.6.3
Amine Acid Gas Flow Since the SRU is already hot, there is no need to place the main fuel gas and the warmup burner ring in service. The acid gas can be ignited with the pilot burner flame. All that is required is to route the combustion products through the SRU, then bring in the acid gas and shut off the pilot.
WARNING
AS SOON AS THE TAILGAS VALVE IS OPENED IN THE NEXT STEP, OXYGEN-BEARING GASES WILL BEGIN FLOWING THROUGH THE CATALYST BEDS. IF THE CATALYST IS HOTTER THAN THE AUTO-IGNITION TEMPERATURE OF SULFUR ON CLAUS CATALYST (150°C), THE SULFUR CONTAINED IN THE CATALYST WILL BEGIN TO BURN. FOR THIS REASON, IT IS IMPORTANT THAT ACID GAS FIRING COMMENCE AS QUICKLY AS POSSIBLE. IF ANY DELAYS IN INTRODUCING ACID GAS ARE ENCOUNTERED, IMMEDIATELY SWITCH THE STARTUP/RUN SELECTOR SWITCH BACK TO "STARTUP" TO OPEN THE WARMUP BYPASS VALVES AND CLOSE THE TAILGAS VALVE SO THAT THE CATALYST BEDS DO NOT CONTINUE TO BURN. A.
Switch the Startup/Run selector switch on the local SRU control panel to "RUN" to route the combustion gases through the SRU. The PLC will open the Tailgas Valve to the Thermal Oxidizer then close the Warmup Bypass Valves. The "TTO OPEN" light will be illuminated, then the "WARMUP OPEN" light will be extinguished as the valves move to their new positions. NOTE:
Issued 30 August 2011
If a valve status light continues to flash, it means that the limit switches on the associated valve(s) never confirmed that the valve(s) moved to the proper position. If this occurs, the startup sequence cannot
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SULFUR BLOCK proceed until the problem is corrected and the valve(s) move to the proper position. Should this occur, switch the Startup/Run selector switch back to "STARTUP" so that the catalyst beds do not continue to burn. B.
As soon as the "WARMUP OPEN" light is extinguished, switch the Acid Gas Firing selector switch on the local SRU control panel to "ENABLED".
C.
Immediately increase the output from the amine acid gas flow control (HIC) on the local SRU control panel to begin opening the amine acid gas inlet valve. Establish an amine acid gas flow rate of approximately 10% and observe if ignition of the acid gas is accomplished. If not, reduce the amine acid gas flow control (HIC) to 0% output to shut off the amine acid gas, open the manual block valve(s) in the main fuel gas supply to the burner, press the "FUEL GAS ON" push-button to open the main fuel gas valves, and use the main fuel gas flow control (HIC) to ignite the fuel gas warmup ring just long enough to ignite the acid gas burner. After establishing an acid gas flame, shut off the main fuel gas by pressing the “FUEL GAS OFF” push-button.
Issued 30 August 2011
D.
Increase the air flow on by 10% using the air flow control (HIC) on the local SRU panel, then increase the amine acid gas flow by 10%. Continue to make incremental increases in air and amine acid gas flow, keeping about a 1:1 ratio of air to amine acid gas (as measured by the percentages displayed on the local indicators), until the amine acid gas inlet valve is fully open.
E.
Press the "PILOT STOP" push-button to "double block and bleed" the pilot fuel gas. Verify that the “FUEL GAS ON” and the "PILOT ON" lights are both extinguished, and that the warmup burner and pilot burner are being purged with nitrogen.
F.
Close the following manual block valves: (1)
The two manual block valve(s) in the main fuel gas line.
(2)
The manual block valve(s) in the fuel gas to the pilot.
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SULFUR BLOCK (3) G.
The manual block valve(s) and manual block valve(s) in the instrument air to the pilot.
Loosen the packing gland on the pilot and retract or extract the pilot assembly: (1)
(2)
If the pilot is just to be retracted: (a)
Retract it until it reaches the limit of the retraction bar.
(b)
Tighten the packing gland on the pilot.
(c)
Verify that the pilot burner is still being purged with nitrogen.
If the pilot is to be completely extracted: (a)
Retract it until the retaining chain is taut.
(b)
Close the block valve to isolate the pilot from the furnace.
(c)
Close the block valve in the nitrogen purge to the pilot burner.
(d)
Disconnect the chain and remove the pilot assembly and store it in a safe place. CAUTION: THE PILOT ASSEMBLY WILL BE VERY HOT. HANDLE IT CAREFULLY TO AVOID BURNS AND TO AVOID DAMAGING IT.
(3) H.
Issued 30 August 2011
Verify that the pilot burner mounting nozzle is still being purged with nitrogen.
Place the air:acid gas ratio control loop in service as follows: (1)
Confirm that the air demand controller in the DCS is in "manual" and its output is set at 50%.
(2)
Confirm that the process air flow controller in the DCS is in "cascade", its output is tracking the output of the air flow control (HIC) on the local SRU panel and its setpoint is tracking its current reading.
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SULFUR BLOCK
I.
(3)
Confirm that the "coarse" setting on the air:acid gas manual ratio set (HIC) is being back-calculated so that the remote setpoint it supplies to the air flow controller matches the current "local" setpoint on the controller.
(4)
Switch the process air hand switch (HS) from "local" to "remote" to give the process air flow controller in the DCS control of the Process Air Blower, so that the process air flow rate will be ratio-controlled automatically. The output from the air:acid gas manual ratio set (HIC) will remain fixed at its last value.
Adjust the air:acid gas ratio as necessary with the air:acid gas manual ratio set (HIC) to bring the air demand displayed on the air demand controller "on-scale" (between -10.0% and +10.0%). If the air demand is high (0.0% to +10.0%), the air:acid gas ratio is too high (i.e., "excess air"). Reduce the setting on the air:acid gas manual ratio set (HIC) to lower the air:acid gas ratio and reduce the air demand. If the air demand is low (-10.0% to 0.0%), the air:acid gas ratio is too low (i.e., "air deficient"). Increase the setting on the air:acid gas manual ratio set (HIC) to raise the air:acid gas ratio and increase the air demand. Once the air demand is "on-scale", switch the air demand controller to "automatic" and adjust its setpoint to 0.0% air demand.
Issued 30 August 2011
J.
Observe the temperatures in the catalyst beds. The first bed may show a temporary increase in temperature due to the oxygen that was flowing through the bed, but its temperatures should quickly return to normal now that acid gas flow has been established.
K.
The sulfur plant is now on-stream, firing on amine acid gas. Before bringing in SWS gas or directing your attention away from the SRU, be sure that: (1)
All controllers are functioning properly.
(2)
Sulfur is draining freely from each rundown line.
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SULFUR BLOCK
9.8.6.4
(3)
All steam heating systems are in service and the steam traps are functioning properly.
(4)
The Warmup Bypass Valves are fully closed.
(5)
The Thermal Oxidizer is functioning properly.
SWS Gas Flow Once the SRU is operating stably on amine acid gas, the SWS gas stream can be introduced into the SRU. Do not attempt to bring in the SWS gas if the SRU is not running smoothly on amine acid gas, as this will make it that much harder to stabilize the unit. Instead, focus your attention on stabilizing the operation of the SRU first (usually by correcting a problem in the upstream Amine Regeneration Units), and then use the procedure below to establish SWS gas flow into the SRU. A.
Confirm that the SWS gas flow on/off switch in the DCS is set to "on".
B.
Confirm that the bypass acid gas flow ratio controller is in "manual" and that the front zone temperature controller is in "automatic".
C.
Confirm that the setpoint of the bypass acid gas flow ratio controller is tracking its current reading (which should be zero), then switch it to "automatic".
D.
Slowly raise the ratio setpoint on the bypass acid gas flow ratio controller to begin opening the bypass acid gas control valve and bypassing some of the amine acid gas to the side injection ports on the furnace.
E.
Continue to raise the ratio setpoint on the bypass acid gas flow ratio controller until the front zone temperature indicated on the front zone temperature controller is approximately 1200°C. After the bypass acid gas flow ratio controller is controlling the bypass acid gas flow and the furnace temperature is up to about 1200°C, the furnace is ready to accept SWS gas.
F.
Issued 30 August 2011
Slowly increase the output from the SWS gas flow control (HIC) on the local SRU control panel to begin opening the SWS gas inlet valve.
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SULFUR BLOCK G.
As SWS gas begins flowing to the Acid Gas Burner, the air:acid gas ratio control system will begin sending additional process air to the burner to combust the SWS gas. Increase the SWS gas flow slowly to allow time for the air flow control system to adjust to the increasing SWS gas flow.
H.
Continue to slowly increase the output from the SWS gas flow control (HIC) to 100% so that the SWS gas inlet valve is fully open.
I.
Monitor the bypass acid gas flow ratio controller to verify that it maintains control of the bypass acid gas flow and that the front zone temperature in the Reactor Furnace remains about 1200°C.
J.
Observe the air demand controller and adjust the air:acid gas ratio with the air:acid gas manual ratio set (HIC) if necessary to help keep the air demand "on-scale". If the air demand is high (0.0% to +10.0%), reduce the setting on the air:acid gas manual ratio set (HIC) to lower the ratio and reduce the air demand. If the air demand is low (-10.0% to 0.0%), increase the setting on the air:acid gas manual ratio set (HIC) to raise the ratio and increase the air demand.
K.
Issued 30 August 2011
If the optical pyrometer is giving reliable indication of the front zone temperature in the furnace, place the temperature cascade control in service as follows: (1)
Confirm that the remote ratio setpoint that the front zone temperature controller is supplying to the bypass acid gas flow ratio controller matches the current setting on the ratio controller.
(2)
Confirm that the front zone temperature controller is in "automatic" and its setpoint is tracking its current reading.
(3)
Switch the bypass acid gas flow ratio controller to "cascade". If necessary, slowly adjust the setpoint of the front zone temperature controller to its normal setpoint of 1200°C.
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SULFUR BLOCK (4)
L.
9.8.6.5
Verify that the controllers are adjusting the bypass gas flow rate as needed to control the desired temperature in the front zone of the Reactor Furnace.
The sulfur plant is now fully on-stream, firing on both amine acid gas and SWS gas. Before switching the SRU tailgas to the TGCU or directing your attention away from the SRU, be sure that: (1)
All controllers are functioning properly.
(2)
Sulfur is draining freely from each rundown line.
(3)
All steam heating systems are in service and the steam traps are functioning properly.
(4)
The Thermal Oxidizer is functioning properly.
Routing SRU Tailgas to the TGCU Before switching the SRU tailgas from the Thermal Oxidizer to the TGCU Tailgas Cleanup Unit, be sure all of the following conditions are true: (1)
The SRU is operating stably on amine acid gas, or on amine acid gas and SWS gas.
(2)
The air demand indicated on the air demand controller is +2.0% or lower.
(3)
The TGCU has been warmed up to operating temperature and is ready to accept SRU tailgas.
If any of these conditions are not true, do not attempt to bring SRU tailgas into the TGCU. In particular, do not attempt switching tailgas to the TGCU when the sulfur plant is upset. The result will be two upset units to deal with. Instead, focus your attention on stabilizing the operation of the SRU first (usually by correcting a problem in the upstream Amine Regeneration Unit and/or Sour Water Stripper Unit), and then use the operating procedures for the TGCU in the TGCU section of these guidelines to switch the SRU tailgas from flowing to the Thermal Oxidizer to flowing into the TGCU. Once the sulfur plant tailgas is flowing to the TGCU, be sure of the following before directing your attention away from the SRU:
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SULFUR BLOCK
9.8.7
(1)
The Tailgas Valve to the Thermal Oxidizer and the TGCU Warmup/Bypass Valve are fully closed.
(2)
All controllers are functioning properly.
(3)
Sulfur is draining freely from each rundown line.
(4)
All steam heating systems are in service and the steam traps are functioning properly.
(5)
The TGCU and the Thermal Oxidizer are functioning properly.
Firing Supplemental Fuel Gas As discussed in Section 9.6.11 of these guidelines, when a sulfur condenser is operated at lower and lower rates, it reaches a point where the bulk gas cooling rate caused by radiation and conduction heat transfer exceeds the dewpoint reduction rate caused by sulfur condensation on the tube walls. Instead of condensing along the walls of the tubes, sulfur begins to condense into tiny droplets out in the gas. Due to the low flow rates, there is not enough turbulence in the gas to make the droplets coalesce along the tube walls. The droplets come out of the tubes as a "fog" that cannot be removed in the downstream separator section, and are carried over into the reactor feed heaters Another one of the symptoms of low flow operating problems is a loss in temperature rise across the catalyst beds in the Reactor. This observation is not always an accurate indication that problems are occurring, however, because the process temperatures are influenced by other operating conditions, such as poor ratio control in the SRU as an example. Instead, it is simpler to use the process air flow rate to the SRU as the main process parameter to monitor. It turns out that the process air flow rate to the SRU is actually a very good indicator of the mass flow rate through the SRU, because the process air flow rate is a function of the amount of combustible compounds in the incoming feed streams. As a result, regardless of whether or not supplemental fuel gas is being fired in the SRU, the mass flow rate through the plant is about the same per unit of air flow. So, if action is taken to keep the process air flow rate high, sulfur "fog" formation should not be a problem. The action to take if the air flow drops below this point is to begin firing supplemental fuel gas. Since burning fuel gas in the Acid Gas Burner will require more process air to combust the fuel gas, the fuel
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SULFUR BLOCK gas flow rate can be adjusted to maintain a minimum process air flow (determined from experience). As discussed in previous sections, the air:acid gas ratio control system in the SRU is designed to automatically add the proper amount of air when burning supplemental fuel gas, so initiating supplemental firing is as simple as opening the control valve in the main fuel gas line to send fuel gas to the Acid Gas Burner. It is important, however, to increase or decrease the fuel gas flow rate slowly so that the control system has time to respond. The required fuel gas flow rate can be estimated from operating experience. Once the fuel gas flow has been set using the flow control in the DCS, observe the process air flow rate on the process air flow controller in the DCS and adjust the fuel gas flow rate as needed to keep the process air flow rate at the minimum flow rate. If the process air flow is too low, raise the setpoint on the fuel gas flow controller to increase the firing rate, which will increase the process air flow rate. If the process air flow rate is higher than the minimum, reduce the setpoint on the fuel gas flow controller to reduce the firing rate and reduce the process air flow. While firing supplemental fuel gas, observe the Reactor Furnace temperature closely on the temperature controllers in the DCS. As the supplemental firing rate is increased, the furnace temperature will begin to rise and the ratio setting on the bypass acid gas ratio controller may have to be adjusted. (If the temperature control cascade for the front zone temperature is in service, the front zone temperature controller should adjust the ratio setting automatically.) Do not allow the furnace temperature to exceed 1,500°C, however, as operation at temperatures above this may cause the refractory lining to fail. Do not increase the firing rate even if it means the process air flow drops below the minimum flow rate. The unit will just have to suffer the low-flow operating problems if the feed rate drops to this point, in order to avoid damaging the Reactor Furnace. The bypass acid gas flow ratio controller, will initially be able to maintain the desired furnace temperature by reducing the bypass gas flow rate to send more of the amine acid gas to the burner, which will lower the temperature in the front zone of the Reactor Furnace. In fact, if enough supplemental fuel gas is fired at the burner, all of the amine acid gas can be routed to the burner due to the increase in furnace temperature caused by the heat release from the fuel gas combustion. However, once the Issued 30 August 2011
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SULFUR BLOCK bypass acid gas flow ratio controller has routed all of the amine gas to the burner, it will no longer be able to control the front zone temperature, and this temperature may begin to rise. If so, reduce the supplemental fuel gas flow rate as needed to keep the furnace temperature below 1,500°C (preferably, below 1370°C). 9.8.7.1
Initiating Supplemental Firing Supplemental fuel gas firing is accomplished by relighting the warmup burner in the Acid Gas Burner. The procedure below assumes that the SRU is on-line and processing acid gas.
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A.
Select local manual control for the fuel gas flow control valve by switching the main fuel gas hand switch (HS) in the DCS to "local".
B.
Place the fuel gas flow controller in "automatic".
C.
If necessary, "toggle" the fuel gas flow on/off switch in the DCS to "ON" so that the fuel gas flow will be included in the air:acid gas ratio control system.
D.
Set the manual fuel gas control on the local SRU control panel to 0% output and visually confirm that the main fuel gas valve and the two shutdown valves are closed.
E.
Open the following manual block valves: (1)
The upstream manual block valve(s) in the main fuel gas supply line.
(2)
The downstream manual block valve(s) in the main fuel gas line to the burner.
F.
Press the "FUEL GAS ON" push-button on the local SRU control panel to open the main fuel gas block valves and illuminate the “FUEL GAS ON” light.
G.
Adjust the output of the main fuel gas flow control (HIC) on the local SRU control panel to slowly open the control valve and commence fuel gas flow to the warmup burner ring. Look through the viewports on the Acid Gas Burner and adjust the fuel gas flow rate until a stable flame can be maintained on the burner tips.
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SULFUR BLOCK H.
Observe the air flow on the process air flow controller and confirm that the air:acid gas ratio control system has added the air needed to combust the fuel gas.
I.
Switch the fuel gas flow rate to automatic control as follows:
J.
(1)
Confirm that the fuel gas flow controller in the DCS is in "automatic", its output is tracking the output of the main fuel gas flow control (HIC) on the local SRU control as indicated in the DCS, and its setpoint is tracking its current reading.
(2)
Switch the main fuel gas hand switch (HS) from "local" to "remote". The DCS controller now has control of the fuel gas control valve and will be controlling a fixed fuel gas flow rate, with its setpoint equal to the last reading
If the process air flow indicated on the process air flow controller is already at the minimum flow rate or higher, do not lower the fuel gas flow. Leave the fuel gas flow controller setpoint where it is, as this is the minimum fuel gas flow for a stable flame on the warmup burner ring at the current operating conditions. Lowering the fuel gas flow could create an unstable fuel gas flame and lead to operating problems. There is no harm in firing more supplemental fuel gas than is necessary as long as the furnace temperature does not exceed the maximum operating temperature of the refractory, 1,500°C. The only disadvantages are the higher fuel gas cost and a slight reduction in the sulfur recovery. (Since water is a product of the Claus reaction, the water vapor in the fuel gas combustion products tends to inhibit the Claus reaction to a degree.)
K.
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If the process air flow indicated on the process air flow controller is less than the minimum flow rate, slowly raise the setpoint on the fuel gas flow controller to increase the supplemental fuel gas firing rate. The air:acid gas ratio control system will in turn raise the setpoint of the process air flow controller and increase the air flow rate. Adjust the fuel gas flow rate as needed to maintain the air flow at the minimum flow rate or above on the process air flow controller.
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SULFUR BLOCK L.
Monitor the furnace temperature closely and make appropriate adjustments to the ratio setting on the bypass acid gas ratio controller. If the temperature control cascade for the front zone temperature is in service, the front zone temperature controller should adjust the ratio setting automatically. If necessary, lower the fuel gas flow rate to keep the furnace temperature at 1,500°C or below. Once the output from the bypass acid gas flow ratio controller reaches 0% and the bypass acid gas control valve is fully closed, the bypass gas ratio controller will no longer be able to control the furnace temperature.
M.
Monitor the air demand on the air demand controller closely and be prepared to adjust the air:acid gas ratio as necessary with the air:acid gas manual ratio set (HIC) to help the air demand controller keep the plant "on-ratio".
N.
If the warmup burner does not light or will not maintain a stable flame: (1)
Press the “FUEL GAS OFF” push button to block-in the main fuel gas.
(2)
Verify that the main fuel gas automated block valves have closed, the main fuel gas automated vent valve has opened, and the “FUEL GAS ON” light has been extinguished.
(3)
Close the manual block valve(s) in the main fuel gas supply line.
(4)
Close the downstream manual block valve(s) in the main fuel gas line to the burner.
The most likely reason for failure of the burner to light is physical damage to the burner (plugging of the tips with scale, carbon, sulfur, or corrosion products, melting of the tips, etc.). In such cases, the nitrogen purge flow to the warmup burner will usually be low or nonexistent. Supplemental fuel gas firing (as well as warmup of the SRU during a "cold" startup) will not be possible until the SRU is shut down so that the burner can be repaired.
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SULFUR BLOCK 9.8.7.2
Discontinuing Supplemental Firing When the acid gas feed rate increases again and supplemental fuel gas firing is no longer needed to keep the process air flow above the minimum rate, the supplemental firing can be discontinued as described below.
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A.
Place the fuel gas flow controller in "manual".
B.
Slowly reduce the output from the fuel gas flow controller to 0% to close the control valve in the main fuel gas line and reduce the fuel gas flow to zero. Lower the fuel gas flow rate slowly to allow the air:acid gas ratio control system to adjust the air flow properly.
C.
Press the “FUEL GAS OFF” push-button on the local SRU control panel to "double block and bleed" the main fuel gas.
D.
Verify that the main fuel gas block valves have closed, the “FUEL GAS ON” light has been extinguished, and the warmup burner is being purged with nitrogen.
E.
Close the two manual block valve(s) in the main fuel gas line.
F.
"Toggle" the fuel gas flow on/off switch in the DCS to "OFF" so that the fuel gas flow rate will no longer be included in the air:acid gas ratio control system (in case the meter does not read exactly zero when there is no flow).
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SULFUR BLOCK
9.9
Shutdown Procedures The procedures to be used in performing a planned shutdown of a sulfur plant will vary depending on the extent and type of work to be performed in and around that SRU during the downtime period. If there are no plans for opening the SRU such that air would be allowed entry to the catalyst beds in the Reactor, few special procedures are required in performing the shutdown. In general, unless there is a suspected problem in the Reactor or the catalyst is to be replaced, there is no benefit to be gained from opening up the Reactor vessel. If the Reactor vessel does not need to be opened (or exposed to significant air entry during some other maintenance procedure), there is no need to cool the catalyst beds. This greatly simplifies and shortens the shutdown procedure. Section 9.9.1 that follows is an example of such a procedure. Also, Section 9.9.1.K (1) briefly addresses keeping a sulfur plant on hot stand-by to minimize corrosion due to water condensation in the boiler and exchanger tubes. Since each SRU has a warmup bypass line to the Thermal Oxidizer, they can be kept on hot stand-by indefinitely by firing on fuel gas and venting the combustion products to the Thermal Oxidizer. This allows maintaining the furnace refractory and heat exchanger surfaces at their normal operating temperatures, ready to accept acid gas, without exposing the catalyst beds to overheating, carbon deposition, or sulfation damage. (Refer to the description of cold catalyst bed startup in these guidelines.) If the catalyst is to be replaced, if the Reactor must be entered, or if maintenance on some other portion of the plant will allow a significant amount of air to enter the Reactor vessel, then more extensive and lengthy procedures must be followed to accomplish a satisfactory shutdown and minimize the time required for performance of the desired maintenance work. Section 9.9.2 that follows is an example of a procedure for this circumstance. One special circumstance that may exist during a shutdown is to have tube leaks in either the Waste Heat Boiler or the Sulfur Condenser. This special case is discussed in Section 9.9.3. Section 9.9.4 is a discussion of emergency shutdown situations. A guide to troubleshooting the causes of unplanned shutdowns is presented to assist in quickly identifying and correcting the problem so the SRU(s) can be put back on-line in a minimum amount of time.
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SULFUR BLOCK Each SRU is affected directly and indirectly by shutdowns and outages that occur in other systems. The more important aspects of the effects these other systems can have on the SRUs are discussed in Section 9.9.5. Typical shutdown procedures are outlined and discussed in the sections that follow for the more common cases. Your existing company procedures and common sense operational judgment should be used to modify these procedures as needed to serve the purpose of any given planned shutdown situation.
9.9.1
Planned Shutdown - No Reactor Entry When there are no plans to open up the Reactor, there is no need to cool the catalyst beds during the shutdown procedure. Even when entry to other parts of an SRU is planned, this can normally be accomplished without exposing the catalyst beds to significant amounts of air by using slip-blinds to isolate the Reactor prior to purging, etc. Under these circumstances, the shutdown procedure given in this section may be used as a guide. All of the equipment and process piping in each SRU is designed to be free-draining so that there should be very little accumulation of liquid sulfur within the unit during normal operation. For this reason, there is usually no need to perform a "sulfur strip" when shutting down an SRU, as there is generally very little residual sulfur contained in the catalyst beds and separation chambers when the sulfur plant is shut down. Experience has shown that plugging of the piping or equipment with solid sulfur during the subsequent restart is normally not a problem. If, however, there is reason to believe that there has been significant accumulation of sulfur within the unit, the "sulfur strip" procedure described in Section 9.9.2 can be performed at the conclusion of this procedure. It is generally preferable to shut down the SRU in a controlled fashion to minimize the impact on the other process units. If time does not allow performing a controlled shutdown, however, the unit can be shut down by simply activating the SRU ESD system (using either the local push-button or the DCS "toggle" switch). This will automatically block the feeds into the SRU (amine acid gas, SWS gas, fuel gas, and combustion air). To shut the SRU down in a controlled fashion, follow the procedure below. A.
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If both SRUs are to be shut-down, the Tailgas Cleanup Unit should be shut down first using one of the procedures in these guidelines.
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SULFUR BLOCK However if one SRU remains on-line, the TGCU can remain online as well. B.
Discontinue SWS gas flow to the SRU by slowly reducing the output from the manual control hand controller on the local SRU control panel to begin closing the SWS gas shutdown valve. Allow time for the air flow controller to reduce the air flow to the SRU accordingly.
C.
Continue to reduce the output from the manual controller to 0% until the SWS gas inlet valve is completely closed. The pressure control system(s) on the Sour Water Stripper(s) should begin to divert the SWS gas flow to the flare as the feed rate to the SRU is reduced.
D.
Begin to "back out" the amine acid gas flow to the SRU by slowly reducing the output from the manual control hand controller on the local SRU control panel to begin closing the amine acid gas shutdown valve. Allow time for the air flow controller to reduce the air flow to the SRU accordingly.
E.
Observe the amine acid gas flow rate the flow indicator on the local SRU control panel and continue reducing the output on the manual controller until the flow rate drops to 20-30%. The pressure control system on the stripper in the ARU should begin to divert the amine acid gas flow to the flare as the feed rate to the SRU is reduced.
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F.
Once the amine acid gas flow rate is down to 20-30%, the SRU can be shut down with minimal impact on the other process units. The simplest way to do so is to activate the SRU ESD system, using either the push-button in the DCS or the push-button on the local SRU control panel.
G.
Visually confirm that: (1)
The amine acid gas shutdown valve is closed.
(2)
The SWS gas shutdown valve is closed.
(3)
The fuel gas to the Acid Gas Burner is blocked-in and bled.
(4)
The Process air Blower is shut down and the suction, blow-off, and discharge valves are closed.
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SULFUR BLOCK (5) H.
All steam heating services are still functioning and the steam traps are operating properly.
If the TGCU was shut down in Step A, the Tailgas Valve to the TTO should have been opened and the Tailgas Valve to the TGCU should have been closed automatically. Visually confirm the positions of these valves. If this is not the case, proceed as follows: (1)
Switch the Startup/Run selector switch on the local SRU control panel to "STARTUP". The PLC will open the two Warmup Bypass Valves and close the Tailgas Valve to the TGCU. Verify that the "WARMUP OPEN" light on the panel is now illuminated and the "TGCU OPEN" light is extinguished.
(2)
Switch the Startup/Run selector switch back to "RUN". The PLC will open the Tailgas Valve to the TTO, then close the Warmup Bypass Valves. Verify that the "TTO OPEN" light on the panel is illuminated, and that the "WARMUP OPEN" and "TGCU OPEN" lights are extinguished.
I.
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If the other SRU and the TGCU are to remain online, isolate the off-line SRU from the TGCU and the Thermal Oxidizer: (6)
Switch the Startup/Run selector switch on the local SRU control panel to "STARTUP".
(7)
The PLC will open the two Warmup Bypass Valves and close the Tailgas Valve to the TGCU or the Tailgas Valve to the TTO. Verify that the "WARMUP OPEN" light on the panel is now illuminated and the "TTO OPEN" and "TGCU OPEN" lights on the panel are extinguished.
(8)
Turn the Leak Test key switch on the local SRU control panel to "TEST".
(9)
The PLC will close the two Warmup Bypass Valves and start the nitrogen purge between the valves. Verify that the "WARMUP OPEN" light on the panel is now extinguished, and that nitrogen is flowing into the piping by observing the FI.
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SULFUR BLOCK (10) If desired, close the manual block valve in the SRU tailgas line. J.
All temperatures in the sulfur plant should be monitored to confirm that no air leaks into the system (due to "drafting" from the Thermal Oxidizer, for instance) and causes sulfur fires in the catalyst beds. If possible, establish a small flow of inert gas into the SRU inlet to purge the SRU to the Thermal Oxidizer using the nitrogen connection on the air line to the Acid Gas Burner.
WARNING
STEPS MUST BE TAKEN TO ENSURE THAT THE SRU IS NOT COMPLETELY BLOCKED-IN. FOR INSTANCE, IT IS POSSIBLE TO BLOCK-IN THE SRU BY CLOSING THE BLOCK VALVES IN THE WARMUP BYPASS LINE AND IN THE TAILGAS LINES TO THE THERMAL OXIDIZER AND THE TGCU. BEFORE DOING SO, ANOTHER OPENING FROM THE SRU TO THE ATMOSPHERE MUST BE CREATED SO THAT THE SRU CANNOT BE OVER-PRESSURED. K.
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If the SRU will be down for an extended period, special precautions should be taken to prevent the boiler and exchanger tubes from cooling to the point where water can condense inside them. Most of the corrosion that occurs in sulfur plants is due to the acidic water that can form if the plant is allowed to get cold. (1)
The Waste Heat Boiler, the reheat exchangers and the Sulfur Condenser can be kept hot by firing the warmup burner in the Acid Gas Burner with fuel gas, using the Warmup Bypass Valves to divert the combustion gases to the Thermal Oxidizer. Use the procedures in these guidelines to fire the SRU in hot standby mode on fuel gas.
(2)
If this is not possible, allow the two boilers to cool enough to Then reduce the steam pressure to about 1 kg/cm2(g). de-pressure the boilers and drain the water from them. Use a temporary "jumper" to supply LP steam to the Waste Heat
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SULFUR BLOCK Boiler, open the sulfur condenser pressure control valve to "back" LP steam into Sulfur Condenser, and drain the condensate from them occasionally. (Make sure the valves are open in the condensate outlet lines from the reactor feed heaters.) This will keep the tubes in the boilers and reheat exchangers safely above the water condensation temperature (100-110°C).
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SULFUR BLOCK 9.9.2
Planned Shutdown for Reactor Entry It is always best, but not absolutely necessary, to reduce the amount of residual sulfur contained in the catalyst beds and separation chambers to a minimum before opening the sulfur plant equipment for maintenance or catalyst change-out. This minimizes the purging and cleaning required prior to vessel entry. This "sulfur strip" can be accomplished most effectively by raising temperatures throughout the plant and routing inert gas through the plant. In this procedure, where complete cooling of the plant and air purging are required, the time-controlling step will be the period of time required to cool the catalyst beds below 150°C. Also, attention should be given to the cooling of the Reactor Furnace refractory; it should be limited to 100-150°C per hour. The catalyst beds must be cooled to 150°C or below before air flow can be established to purge the plant and cool it rapidly from that temperature. If the catalyst beds are not cooled to this level before beginning the air purge, sulfur fires can occur in the beds, the sulfur separators and mist eliminators, and the other parts of the plant where elemental sulfur is present.
9.9.2.1
Cooling Gas for the Catalyst Beds There will always be enough sulfur in a used catalyst bed to burn and generate sufficient heat to damage equipment if enough air is routed to the bed to supply the oxygen required for combustion. Therefore, gases which contain essentially no oxygen must be routed through the catalyst beds until the outlet temperature from each bed is below 150°C. Otherwise, the plant would have to be blocked-in for days to obtain the necessary ambient heat loss cooling of the catalyst beds. The following gases can be considered for catalyst bed cooling: A.
Inert gases such as nitrogen, carbon dioxide, or a mixture of nitrogen and carbon dioxide like that produced by a combustion-type inert gas generator. We recommend cooling the SRU with LP nitrogen from the from the hard-piped nitrogen connection on the Process Air line to the burner. However, if sufficient nitrogen is not available from the nitrogen header in the plant or some other source, inert combustion gases may be generated by firing the warmup fuel gas burner inside the Acid Gas Burner near stoichiometric
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SULFUR BLOCK air:gas ratio (little or no excess air), or slightly below stoichiometric. There are a few disadvantages with this technique:
B.
(1)
Careful control of the air:gas ratio is required to keep it near stoichiometric. Too much air will allow free oxygen to reach the catalyst beds, causing sulfur fires. Too little air can cause the warmup burner to produce soot. However, the only real damage the soot will cause is to settle out on the first catalyst bed. If the catalyst is being replaced, this will be of no consequence.
(2)
The flame temperature when burning fuel gas with stoichiometric air is generally in excess of 1600°C. Steam or nitrogen (or some other inert gas) will probably have to be added to the Reactor Furnace to keep the furnace temperature below 1500°C as measured on the pyrometers so that there is no damage to the refractory.
Steam is a good catalyst bed cooling gas. The only negative factor is that pure steam may damage the activity of some sulfur plant catalysts. If the catalyst is being replaced, then steam is a good choice. If the catalyst is not being replaced, the catalyst manufacturer should be contacted to determine the extent of damage, if any, that would result from cooling the catalyst with steam to the 150°C temperature level. It is likely that little catalyst damage will occur unless the temperature is allowed to fall below about 110°C where water could condense. If steam is to be used for cooling, it may be necessary to take steps to maintain at least 0.7 kg/cm2(g) steam pressure on the shell sides of the Waste Heat Boiler and the Sulfur Condenser in order to prevent water condensation in the plant. Temperatures should be monitored closely and steam pressures controlled if necessary. If these two boilers cool enough to reduce the steam pressure to about 1 kg/cm2(g), de-pressure the boilers and drain the water from them. Use a temporary "jumper" to supply LP steam to the Waste Heat Boiler , open the sulfur condenser pressure control valve to "back" LP steam into Sulfur Condenser, and drain the condensate from them occasionally. (Make sure the valves are open in the condensate outlet lines from the reactor feed
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SULFUR BLOCK heaters.) This will keep the tubes in the boilers and reheat exchangers safely above the water condensation temperature (100-110°C). 9.9.2.2
"Sulfur Strip" Procedure Using Inert Gas Before cooling down the catalyst beds, the amount of residual sulfur in the SRU should be reduced as much as possible by performing a "sulfur strip" on the plant. This can be accomplished by flowing hot inert gas through the catalyst beds to vaporize any residual sulfur, which is subsequently condensed and removed in the downstream passes of the Sulfur Condenser. The preferred source of inert gas is nitrogen from the plant header. If nitrogen (or some other type of inert gas from an external source) is available in sufficient quantity, follow the procedure given in this section to use nitrogen or inert gas as the stripping media. If nitrogen or inert gas is not available in sufficient quantity, follow the procedure given in this section using either steam or inert gas generated with the Acid Gas Burner as the stripping media.
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A.
Follow the procedure given in the preceding Section 9.9.1 to "back out" the SWS gas and amine acid gas feeds to the SRU and shut it down.
B.
Visually confirm that: (1)
The amine acid gas shutdown valve is closed.
(2)
The SWS gas shutdown valve is closed.
(3)
The fuel gas to the Acid Gas Burner is blocked-in and bled.
(4)
The Process air Blower is shut down and the suction, blow-off, and discharge valves are closed.
(5)
The Tailgas Valve to the TGCU is closed.
(6)
The Tailgas Valve to the TTO is open.
(7)
The manual block valve in the SRU tailgas line is open.
(8)
All steam heating services are still functioning and the steam traps are operating properly.
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SULFUR BLOCK C.
D.
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Begin the flow of inert gas through the plant. (1)
If using nitrogen from the plant header, the nitrogen can be introduced through the hard-piped connection on the process air line near the Acid Gas Burner.
(2)
If using inert gas from another source, it can be introduced through the bleed valve on the hard-piped LP nitrogen connection near the Acid Gas Burner.
(3)
If using the warmup burner in the Acid Gas Burner to generate inert gas, take care to keep the Reactor Furnace temperature below 1500°C on the pyrometers. Admit nitrogen or LP steam (using the hard-piped LP nitrogen connection on the process air line near the burner) to the furnace as necessary to moderate the furnace temperature. Use an oxygen analyzer to measure the oxygen content of the combustion gas flowing to the first catalyst bed in the Reactor, and adjust the air:gas ratio as necessary to keep the oxygen concentration between 0.5% and 2.0%. If steam is being used to moderate the furnace temperature, make sure that there is no liquid in the steam supply before introducing it into the furnace to avoid an explosion from water entering the hot furnace.
Adjust the temperatures throughout the plant by making changes as follows: (1)
Place the steam pressure controller on the Waste Heat Boiler in "manual" and adjust its output to 100% to fully open the steam valve. This will allow steam from the HP steam header to "back" into the boiler (if using nitrogen or inert gas).
(2)
Place the temperature controllers for the Reactor feeds in "manual" and set their outputs to 100% to fully open the valves in the condensate outlet lines from the exchangers and supply maximum heating to each catalyst bed.
(3)
Lower the steam pressure in the Sulfur Condenser if possible by adjusting the setpoint of the pressure controller to 1 kg/cm2(g). This will condense as much sulfur as possible as it is "stripped" from the three catalyst
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SULFUR BLOCK beds. (It should be noted that the back-pressure from the LP steam header will probably not allow operating the Sulfur Condenser any lower than about 3.5 kg/cm2(g).) The hot inert gas flowing through the Reactor should vaporize most of the residual sulfur contained in the catalyst beds so that it can be condensed and removed in the downstream condensing passes of the Sulfur Condenser. E.
Continue to purge the sulfur plant with this inert gas stream until sulfur is no longer running from any of the Sulfur Drain Seal Assemblies. Once sulfur stops running from all of the Sulfur Drain Seal Assemblies, cool-down of the catalyst beds can commence using the procedure given in Section 9.9.2.3 that follows.
9.9.2.3
Cool-down Procedure Once the "sulfur strip" procedure is complete, cool-down of the catalyst beds can begin. The cool-down gas will normally be the same inert gas that was used for the "sulfur strip" operation. However, if inert gas is being generated using the warmup burner in the Acid Gas Burner as described in Section 9.9.2.2, it may be desirable to switch to a once-through flow of inert gas (nitrogen, for example) instead to cool the catalyst beds. A.
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Begin reducing the steam pressures in the Waste Heat Boiler and the Sulfur Condenser to 0.7-1.0 kg/cm2(g) by placing their steam pressure controllers in "manual" and adjusting the outputs to 0% to close the valves, then venting the boiler shells to atmosphere. This steam pressure will keep the tubes in the boilers safely above the water condensation temperature (100-110°C). (1)
If dry inert gas (nitrogen) is being used for the cooling gas, the steam pressures in both boilers can be allowed to fall to 0 kg/cm2(g), since there is no risk of water condensation in the tubes.
(2)
If the warmup burner in the Acid Gas Burner is being used to generate the inert gas, it may not be possible to reduce the Waste Heat Boiler steam pressure to
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SULFUR BLOCK 0.7-1.0 kg/cm2(g), since the combustion products will provide considerable heat to the boiler. B.
Confirm that the temperature controllers for the Reactor feeds, are in "manual" and set their outputs to 0% to fully close the valves in the condensate outlet lines from the exchangers and supply minimum heating to the catalyst beds.
C.
Monitor the water levels in the Waste Heat Boiler and the Sulfur Condenser and confirm that the level controls continue to function properly to maintain normal levels in the boilers throughout the cool-down procedure.
D.
Continue to route inert gas through the catalyst beds, with maximum cooling in the Sulfur Condenser and minimum heating in the reheat exchangers, until the outlet temperatures from all catalyst beds are below 150°C. If using the warmup burner in the Acid Gas Burner to generate inert gas, it may not be possible to cool the first catalyst bed below 150°C. After extinguishing the burner, one of the following intermediate steps may be necessary to cool this catalyst bed below 150°C:
E.
(1)
Route nitrogen, steam, or some other inert gas through the reactor.
(2)
Allow the reactor to cool by ambient heat loss.
When all catalyst beds are below 150°C, stop the flow of cooling gas. Switch the Startup/Run selector switch on the local SRU control panel to "STARTUP". The PLC will open the two Warmup Bypass Valves and close the Tailgas Valve to the TTO Unit. Verify that the "WARMUP OPEN" light on the panel is now illuminated and the "TTO OPEN" light is extinguished.
F.
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Start a Process Air Blower: (1)
Switch blower hand swtich in the DCS to "local".
(2)
Set air blower flow controller (HIC) on the local SRU control panel to 0% output.
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SULFUR BLOCK (3)
Press the local push-button to give a "permit to start" for the desired blower.
(4)
Start the blower using the local start/stop control station for that blower.
The next step would normally be to press the "ESD RESET" push-button. Do not press it, however. G.
Turn the Reactor Cool-Down switch on the local SRU control panel to "COOL-DOWN".
H.
Switch the Startup/Run selector switch back to "RUN". The PLC will open the Tailgas Valve to the TTO, then close the Warmup Bypass Valves. Verify that the "TTO OPEN" light on the panel is illuminated, and that the "WARMUP OPEN" and "TGCU OPEN" lights are extinguished.
I.
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Increase the output from the local air flow controller (HIC) to begin a rapid air purge of the entire sulfur plant.
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SULFUR BLOCK
CAUTION WATCH THE TEMPERATURES IN EACH CATALYST BED AND OUTLET LINE VERY CLOSELY AFTER STARTING THE AIR PURGE, UNTIL ALL ARE WELL BELOW 120°C. SULFUR FIRES CAN IGNITE IN THE PLANT AFTER STARTING THE AIR PURGE EVEN THOUGH ALL THE TEMPERATURE INDICATORS REGISTERED 150°C OR LESS. IT IS POSSIBLE, FOR INSTANCE, TO HAVE LOCALIZED "HOT" SPOTS IN A CATALYST BED THAT CAN START A SULFUR FIRE. THE AIR PURGE SHOULD BE STOPPED IMMEDIATELY UPON OBSERVING A SIGNIFICANT TEMPERATURE RISE IN ANY TEMPERATURE INSIDE THE PLANT. THE INERT GAS FLOW SHOULD THEN BE RE-ESTABLISHED UNTIL ALL AREAS ARE COOLED BACK TO THE DESIRED 150°C LEVEL, BEFORE REATTEMPTING THE AIR PURGE. J.
Continue the rapid air purge of the entire sulfur plant until all temperatures are approximately equal to the discharge air temperature from the blower.
K.
Isolate the plant from all potential contaminating gases (acid gas, fuel gas, etc.), using slip-blinds or by disconnecting the piping, before stopping the air purge.
L.
Once the plant is isolated from the feed gases, discontinue the air purge by shutting down the Process Air Blower.
M.
Turn the Reactor Cool-Down switch on the local SRU control panel back to "NORMAL".
N.
Isolate the SRU from the TGCU and the Thermal Oxidizer: (1)
Switch the Startup/Run selector switch on the local SRU control panel to "STARTUP". The PLC will open the two Warmup Bypass Valves and close the Tailgas Valve to the TTO. Verify that the
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SULFUR BLOCK "WARMUP OPEN" light on the panel is now illuminated and the "TTO OPEN" and "TGCU OPEN" lights on the panel are extinguished. (2)
Turn the Leak Test key switch on the local SRU control panel to "TEST". The PLC will close the two Warmup Bypass Valves and start the nitrogen purge between the valves. Verify that the "WARMUP OPEN" light on the panel is now extinguished, and that nitrogen is flowing into the piping by observing the FI.
(3) O.
P.
If desired, close the manual block valve in the SRU tailgas line.
Visually confirm that: (1)
The SRU is isolated from the amine acid gas source, the SWS gas source, the fuel gas header, the instrument air header, the nitrogen header, the TGCU, and the Thermal Oxidizer.
(2)
The Process Air Blowers are shut down and their suction, blow-off, and discharge valves are closed.
(3)
All steam heating services are still functioning and the steam traps are operating properly. If possible, the LP steam and condensate system should remain in service, with selected branches taken out of service as required for maintenance.
The plant can now be opened for entry. Refer to the "General Safety" section of these procedures for important considerations when performing maintenance work on this plant.
WARNING
THE OVER-PRESSURE PROTECTION FOR THE SRU IS THE SULFUR DRAIN SEALS, A2-ME1530A-D(A2-ME1540A-D), WHICH WILL RELEASE THE GAS INSIDE THE SRU IF THE
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SULFUR BLOCK PRESSURE EVER EXCEEDS 0.88 KG/CM2(G). HOWEVER, IF THE BLOCK VALVES IN THE RUNDOWN LINES TO THE SULFUR DRAIN SEALS ARE CLOSED WHILE THE SRU IS SHUT DOWN, STEPS MUST BE TAKEN TO ENSURE THAT THE SRU IS NOT COMPLETELY BLOCKED-IN BY CREATING ANOTHER OPENING FROM THE SRU TO THE ATMOSPHERE SO THAT THE SRU CANNOT BE OVER-PRESSURED. Q.
If the SRU will be down for an extended period, special precautions should be taken to prevent the boiler and exchanger tubes from cooling to the point where water can condense inside them. Most of the corrosion that occurs in sulfur plants is due to the acidic water that can form if the plant is allowed to get cold. The Waste Heat Boiler, reheat exchangers and the Sulfur Condenser can be kept hot using LP steam. De-pressure the boilers and drain the water from them. Use a temporary "jumper" to supply LP steam to the Waste Heat Boiler, open the sulfur condenser pressure control valve to "back" LP steam into Sulfur Condenser, and drain the condensate from them occasionally. (Make sure the valves are open in the condensate outlet lines from the reactor feed heaters.) This will keep all the tubes safely above the water condensation temperature (100-110°C).
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SULFUR BLOCK 9.9.3
Shutting Down When Boiler Tubes Are Leaking One special circumstance that merits discussion is shutting down the SRU when there are tube leaks in the Waste Heat Boiler or Sulfur Condenser. While the plant is running, minor tube leaks usually cause little damage because the hot process gas vaporizes the boiler feed water before it has a chance to form acid and cause rapid corrosion. When the SRU is shut down, however, several problems can develop: 1.
Liquid water may accumulate in the equipment or piping and form a variety of acids (sulfurous, polythionic, etc.) that will rapidly corrode the steel.
2.
Liquid water may reach the refractory linings in the equipment and damage the linings.
3.
Water and/or steam may reach the catalyst in the Reactor and weaken or damage it.
4.
If there is a large tube leak in the Waste Heat Boiler, water may back-flow into the hot Reactor Furnace and rapidly vaporize, possibly violently enough to damage its refractory lining or create high pressure in the SRU.
If a boiler tube leak is suspected, a shutdown procedure similar to the following may be appropriate:
Issued 30 August 2011
A.
Shut down the SRU using the procedures given in Section 9.9.1.
B.
Commence a flow of nitrogen as soon as the Acid Gas Burner is shut down to purge any steam from tube leaks to the Thermal Oxidizer.
C.
De-pressure the boiler having the suspected tube leak, taking care to reduce the pressure slowly enough to avoid over-stressing the boiler.
D.
Maintain a visible water level in the boiler. Water must remain in the boiler until it is de-pressured to prevent overheating damage to the tubes.
E.
Once the boiler is fully de-pressured, drain the water from the boiler to prevent any further leakage into the process side of the equipment.
F.
The SRU is now ready to be isolated and made safe for entry.
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SULFUR BLOCK 9.9.4
Emergency Shutdown The SRU ESD system can be initiated by any of the actuating devices outlined in these guidelines, or by a power failure. The operator must determine and correct the condition causing the shutdown before the sulfur plant can be restarted. The problems outlined below should be investigated first by the operator in his troubleshooting procedure. If the malfunction causing the emergency shutdown can be determined and corrected in a short period of time, the SRU can be put back on-line using the rapid restart procedure outlined in these guidelines.
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S/D Actuation Device
Possible Causes
Acid Gas Knock-Out Drum High-High Level
1. Excessive liquids being received by the Knock-Out Drum. 2. Malfunction of level control system. 3. Level warning transmitters on the Knock-Out Drum are plugged or inoperable. 4. Knock-Out Drum Pump malfunction. 5. Pump suction or discharge line plugged, strainer plugged, or block valve closed. 6. Malfunction of the stripper reflux pumps in the upstream system.
Process Air Blower Not Running
1. Equipment damage has caused the blower to quit running. 2. A failure in the starter contacts is causing a false indication that the blower is not running.
Reactor Furnace High-High Pressure
1. Warmup bypass valve or tailgas block valve not open. 2. A sulfur condenser separator chamber is filled with molten sulfur due to plugging of a sulfur rundown line or a drain seal. 3. Steam pressure is too low in the Sulfur Condenser, causing tubes to be plugged with solid sulfur. 4. Soot or carbon buildup in a catalyst bed or a sulfur condenser mist eliminator is restricting flow. 5. Malfunction of the air pressure sensing system.
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SULFUR BLOCK
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S/D Actuation Device
Possible Causes
Acid Gas Burner Flame Failure
1. Failure of a component in the flame sensor circuit. 2. Condensation of sulfur or water vapor on the lens of the flame scanner. 3. Low acid gas (or fuel gas) flow. 4. Low process air flow due to: a. Malfunction of the blower suction valve or the flow control system. b. Blower discharge valve is not fully open. c. Blower blow-off valve is open excessively. d. Blower shutdown due to mechanical problems with the blower, the motor, or the switchgear. e. High pressure drop due to plugging or blockage downstream.
Waste Heat Boiler Low-Low Level
1. Loss of make-up water supply pressure. 2. Make-up water line plugged, or manual block valve closed or pinched. 3. Malfunction of the level control system. 4. Manual blowdown valve left open.
Reactor 1st Bed Outlet High-High Temperature
1. Malfunction of the air:acid gas ratio control system, allowing excess air to enter the system. 2. Malfunction of the control system has caused less than 1/3 of the acid gas to be routed to the burner, allowing free oxygen to reach the catalyst bed. 3. Low H2S concentration in the inlet acid gas is causing incomplete combustion in the Reactor Furnace, allowing free oxygen to reach the catalyst bed. 4. Damaged acid gas burner tip causing incomplete mixing and combustion of air and acid gas, allowing free oxygen to reach the catalyst bed. 5. Malfunction of the control system has caused a high reactor inlet temperature.
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SULFUR BLOCK
9.9.5
S/D Actuation Device
Possible Causes
Sulfur Condenser Low-Low Level
1. Loss of make-up water supply pressure. 2. Make-up water line plugged, or manual block valve closed or pinched. 3. Malfunction of the level control system. 4. Manual blowdown valve left open.
Neither Warmup Bypass Valve Closed Interlock
1. Neither warmup bypass valve is fully closed. 2. Malfunction of a limit switch is causing a false indication that a valve is not closed.
Effects of Shutdowns and Outages in Other Systems The Sulfur Recovery system is directly or indirectly affected by shutdowns and/or outages in five other systems in the plant. These effects are described below.
9.9.5.1
ATU / ARU Outages Acid gas flow from the ARU can be interrupted for a variety of reasons. For instance, the gas flow to the absorber in the ATU in the plant can be blocked manually or automatically, the solvent flow from the flash tank to the stripper can be interrupted, etc. When these events occur, the acid gas flow will not cease immediately due to the residence time in the solvent distribution piping, the flash tank, and the stripper. If processing in the affected ARU is restarted within the time frame of this system residence time, the amine acid gas flow to the SRU will probably dip, but should not stop completely. If the interruption in the ARU is long enough, though, the amine acid gas flow can fall far enough to cause the acid gas flame in the SRU to become unstable, at which point the SRU ESD system will be activated by "flame failure". If this happens, the SRU can be restarted on fuel gas and run in hot stand-by using the Warmup Bypass Valves, then brought back on-line once amine acid gas flow resumes. If the SRU is currently processing SWS gas, it is possible that the acid gas flame may remain stable enough for continued operation on just SWS gas. If the SRU is processing only SWS gas, note the cautions in these guidelines regarding this mode of operation.
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SULFUR BLOCK 9.9.5.2
Sour Water Stripper Outages SWS gas flow from the Sour Water Stripper can also be interrupted for a variety of reasons. However, since the loss of SWS gas flow to the SRU generally has minimal impact, outages in this system are usually of little consequence.
9.9.5.3
TGCU ESD System When the TGCU ESD system is activated, its warmup/bypass valve opens immediately to divert the tailgas from the upstream SRUs to the Thermal Oxidizer. At the same time, the PLC opens the Tailgas Valve to the TTO proves the valve open, then closes the Tailgas Valve to the TGCU. Once this switch is complete, the SRU tailgas stream is blocked off from the TGCU and flows directly to the Thermal Oxidizer. When the TGCU warmup/bypass valve first opens, the pressure drop through the TGCU will no longer be imposing back-pressure on the SRUs. Depending on the magnitude of this change in back-pressure (which is mainly determined by the unit throughput), there may be a temporary "bobble" in the feed and air flow rates to the SRUs. Although this will probably cause brief deviations from the proper air:acid gas ratio in the SRUs, the "bobble" should not be large enough to cause a "flame failure" shutdown in the SRU. If so, the SRU will remain on-line with its tailgas flowing to its Thermal Oxidizer, so that there is no need to restart the SRUs. Once the TGCU has been restarted, the SRU tailgas streams can be reintroduced into the TGCU to resume processing with as little interruption as possible.
9.9.5.4
Thermal Oxidizer ESD System A TTO ESD has no direct effect on the upstream SRUs, as the flow of SRU tailgas and/or TGCU effluent to the Thermal Oxidizer will not be interrupted. However, when the TTO ESD shuts down the Thermal Oxidizer Burner, the sulfur compounds in the Thermal Oxidizer feed gas will no longer be oxidized to sulfur dioxide. This means that hydrogen sulfide will be vented to the atmosphere from the top of its Thermal Oxidizer Vent Stack. Under normal circumstances, this is not a cause for concern because the TGCU is on-line processing the SRU tailgas. Since the H2S content of the
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SULFUR BLOCK TGCU effluent is low and the stack is tall, dangerous ground level concentrations of H2S should not develop. However, if the SRU is running directly to the TTO while operating off-ratio on the "air deficient" side (negative air demand), high concentrations of H2S could be vented from the stack when the TTO is shut down. For this reason, pay very close attention to the air demand controller and the air:acid gas ratio control system in the SRU when the TTO is off-line, and be prepared to shut down the SRU if it is not operating properly. In particular, note the warnings in the TTO Sections of these guidelines regarding high temperature in the Thermal Oxidizer if the SRU tailgas contains excessive amounts of H2S. Also, note that the operating permit for this plant may not allow venting un-incinerated gases for extended periods. Review the permit before operating in this mode for a lengthy period. If the H2S concentration in the TTO feed gas is high (above 3.0%), do not attempt to restart the Thermal Oxidizer. Instead, direct your attention to the amine or SWS unit(s) upstream of the SRUs that are probably causing the problem and bring the SRUs back on-ratio, so that the H2S concentration in the Thermal Oxidizer feed gas is reduced to an acceptable level and restart of the Thermal Oxidizer can proceed smoothly. Failure to correct the upstream problem(s) first will likely lead to the TTO shutting down again, requiring another restart of the TTO. If the H2S concentration is high enough, there is also a possibility of causing an explosion in the Thermal Oxidizer. 9.9.5.5
Steam System Outage There are two impacts on the SRU if the complex steam system is shut down. One of these will only create problems if the steam supply to the SRUs is unavailable for a long period of time. The heating steam for the sulfur vapor switching valves, the sulfur rundown lines, the Sulfur Surge Tanks and the Sulfur Storage Tank will be lost, leading to solid sulfur freezing in these locations. The more immediate impact on the SRU will be the loss of LP steam to the stripper reboiler in the upstream Amine Regeneration Unit if the steam outage lasts long enough. As the heat input to the reboiler
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SULFUR BLOCK declines, stripping of the acid gas from the solvent will decline and the amine acid gas flow rate to the SRU will gradually diminish. If the amine acid gas flow falls far enough to cause the acid gas flame to become unstable, the SRU ESD system will be activated by "flame failure" as described previously in the discussion about Amine Regeneration Unit outages.
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SULFUR BLOCK
9.10 Analytical Procedures This section contains analytical procedures for determining: 1.
The H2S concentration in the inlet amine acid gas using Tutweiler analysis (Sections 9.10.1, 9.10.2, 9.10.6, and 9.10.7).
2.
The H2S and SO2 concentrations in the SRU tailgas using Tutweiler analysis (Sections 9.10.1 and 9.10.3 through 9.10.7).
3.
The H2S and SO2 concentrations in the SRU tailgas using gas detector tubes (Section 9.10.8).
9.10.1
Procedure for Sampling and Titrating with a Tutweiler Apparatus The procedure given below is specifically written for a 100 ml Tutweiler apparatus, commonly used when analyzing streams with high H2S concentrations (amine acid gas, for instance). The same procedure can be used with the 500 ml Tutweiler apparatus, commonly used for analyzing dilute streams (SRU tailgas, for instance), by substituting a reference to the 500 ml apparatus for all the references to the 100 ml apparatus. With this in mind, the few differences in the procedure have been noted by enclosing specific directions for the 500 ml apparatus in parenthesis. 1.
Using a 100 ml (500 ml) Tutweiler apparatus, fill the 10 ml titrating burette on top of the Tutweiler apparatus with 0.1 N iodine solution to some level below 10 ml. Carefully read and record this reading.
2.
Fill a leveling bottle with fresh starch solution.
3.
Attach a short piece of rubber tubing to the process sample valve.
4.
Attach the leveling bottle filled with starch solution to the lower stopcock of the Tutweiler burette.
5.
Use the starch solution to purge the Tutweiler burette: Raise the leveling bottle, open the lower stopcock, open the upper stopcock to the inlet tube connection and completely fill the burette. Close the upper stopcock when a few drops of the starch solution flow out of the inlet tube connection. Close the lower stopcock.
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SULFUR BLOCK 6.
Purge the rubber tubing by venting acid gas (tailgas) to the atmosphere a few seconds. Pinch the rubber tubing closed at the end, close the gas sample valve, and slip the end of the rubber tubing onto the inlet tube connection of the Tutweiler burette's upper stopcock.
7.
Crack the gas sample valve open and draw gas into the burette by lowering the leveling bottle and opening the stopcocks. When the liquid level is several milliliters below the 100-ml mark (500-ml mark), close the lower stopcock, upper stopcock, and gas sample valve.
8.
Remove the sample gas rubber tubing from the Tutweiler burette.
9.
Open the lower stopcock and bring the starch solution to the 100-ml mark (500-ml mark) by raising the leveling bottle; then close the lower stopcock. Open the upper stopcock long enough to equalize the pressure inside the burette with the atmosphere, then close the top stopcock. There is now exactly 100 ml (500 ml) of gas at atmospheric pressure and ambient temperature in the Tutweiler burette.
10. Open the lower stopcock and lower the leveling bottle. Lower the level of the starch solution in the burette to the 110-ml mark (550-ml mark) to pull a partial vacuum. Close the lower stopcock. 11. Place a tubing clamp on the rubber hose to the leveling bottle and remove the hose from the Tutweiler burette lower stopcock. 12. Carefully crack the stopcock on the iodine burette and allow a small amount of iodine solution to be sucked into the large burette. Close the stopcock. NOTE:
Experience will soon allow the operator to know approximately how much iodine will be needed. It is good procedure to admit 75% of this "estimate" the first time.
13. Shake the burette vigorously, carefully holding the glass cap in place on top of the iodine burette with one finger. As soon as all traces of blue are gone, repeat the addition of iodine solution, adding smaller and smaller amounts as the "anticipated" volume is approached. NOTE:
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For best accuracy, the entire titration procedure explained above should be done smoothly and quickly without
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SULFUR BLOCK interruption or delays. A yellow or red color may develop during the titration, but it is of no significance. 14. Continue the titration until the starch solution turns a definite blue color and holds the color without fading during shaking for approximately one minute. Carefully read the final iodine burette level. 15. Record the temperature of the air around the sampling point.
9.10.2
H2S Concentration in Acid Gas by the Tutweiler Method The inlet amine acid gas can be sampled from the sample connection on the outlet of the Acid Gas Knock-Out Drum. 1.
Using a 100 ml Tutweiler apparatus, sample and titrate the acid gas feed to the SRU as outlined in Section 9.10.1.
2.
Chemical reaction involved: H2S + I2
2 HI + S
The hydrogen sulfide (H2S) is converted to small particles of elemental sulfur by the iodine during the shaking. Good shaking is required to get good contact between the hydrogen sulfide in the gas and the iodine in the liquid. When all of the hydrogen sulfide is converted, the excess iodine causes the characteristic blue color in the presence of starch. This is a universal test for starch. (Iodine causes a blue color when it contacts starchy foods, such as potato for example.) 3.
Calculation of Mole (or Volume) percent H2S (dry basis): ml Iodine Normality of 273 T 760 Mole % H2S (11.85) 289 P - V.P. Solution Used Iodine Solution
Where
T P
= =
sample temperature, °C atmospheric pressure at particular location, mm Hg
V.P
=
vapor pressure of water at sample temperature, mm Hg
The Normality of the standard iodine solution will be 0.1 N. The last three factors (which correct the actual acid gas content to compensate for expansion due to temperature, pressure, and water content) can be combined and calculated as a function of temperature only. This has been done for the 100-ml gas sample
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SULFUR BLOCK and is included as the Tutweiler Factor Chart in this section (Chart 1). Therefore, the equation above is simplified to: Factor from ml Iodine Normality of Mole % H2S Solution Used Iodine Solution Tutweiler Factor Chart
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16.0
SULFUR BLOCK
15.5
Chart 1
15.0
Tutweiler Factor vs. Air Temperature
Tutweiler Factor
9.0
9.5
10.0
10.5
11.0
11.5
12.0
12.5
13.0
13.5
14.0
14.5
Sample Volume: 100 ml Baro. Pressure: 1.033 kg/cm2(a)
-30
-20
-10
0
10
20
30
40
50
Air Temperature, °C Issued 30 August 2011
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SULFUR BLOCK 9.10.3
H2S and SO2 Concentration in Tailgas by the Tutweiler Method The sulfur plant tailgas can be sampled from the sample valve on the outlet line from the fourth pass of the Sulfur Condenser. 1.
Using a 500 ml Tutweiler apparatus, sample and titrate the SRU tailgas as outlined in Section 9.10.1.
2.
Chemical reactions involved: H2S + I2
S + 2 HI
SO2 + I2 + 2 H2O
H2SO4 + 2 HI
The hydrogen sulfide (H2S) and sulfur dioxide (SO2) are converted by the iodine during the shaking. When both gases are completely converted, the slightest excess of free iodine causes the characteristic blue color with the starch solution. Although the relative amount of each gas cannot be determined from the Tutweiler titration alone, only sulfur dioxide is converted to sulfuric acid (H2SO4). Therefore, a further step can be used to determine the amount of sulfuric acid formed in order to calculate the amount of sulfur dioxide originally present in the gas sample. NOTE:
Sulfur dioxide and hydrogen sulfide react in the presence of water to form sulfur: 2 H2S + SO2
3 S + 2 H2O
This side reaction (the Claus reaction) causes the iodine titration to give a low answer. This can be minimized by rapid titration.
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3.
Carefully drain the blue starch solution into a clean 250 ml Erlenmeyer flask. Rinse the inside of the Tutweiler burette with distilled water and add this washing water to the flask with the blue starch solution.
4.
Using an eyedropper, add one drop of 0.1 N sodium thiosulfate (Na2S2O3) and swirl the flask. This drop should use up the excess iodine and the starch solution should lose its blue color. If more than one drop is required, too much iodine was added.
5.
Add five drops of methyl purple indicator to the flask and swirl gently.
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SULFUR BLOCK 6.
Titrate carefully to a definite green end point with 0.1 N sodium hydroxide (NaOH).
7.
Chemical reactions in this titration:
8.
H2SO4 + 2 NaOH
2 H2O + Na2SO4
HI + NaOH
H2O + NaI
Calculations: a.
For a 500-ml gas sample, Mole (or Vol) percent H2S + SO2 (dry basis): Mole % (H2S SO2)
Where
ml Iodine Normality of 273 T 760 Iodine Solution (2.369) Solution Used 289 P - V.P.
T P
= =
sample temperature, °C atmospheric pressure at particular location, mm Hg
V.P
=
vapor pressure of water at sample temperature, mm Hg
The Normality of the standard iodine solution will be 0.1 N. The last three factors (which correct the actual gas content to compensate for expansion due to temperature, pressure, and water content) can be combined and calculated as a function of temperature only. This has been done for the 500-ml gas sample and is included as the Tutweiler Factor Chart in this section (Chart 2). Therefore, the equation above is simplified to: Mole % Factor from ml Iodine Normality of (H2S SO2) Solution Used Iodine Solution Tutweiler Factor Chart
b.
Mole (or Volume) percent SO2 (dry basis): ml NaOH Normality of Mole % Used NaOH Solution Mole % SO2 1 H S SO ml Iodine Normality of 2 2 Used Iodine Solution
c.
Mole (or Volume) percent H2S (dry basis): Mole % H2S = Mole % ( H2S + SO2 ) – Mole % SO2
d. Issued 30 August 2011
Molar (or Volume) Ratio of H2S to SO2 in tailgas: Sulfur Recovery
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SULFUR BLOCK H2S : SO2 Ratio
Mole % H2S Mole % SO2
Calculate each quantity as shown above and divide to obtain the H2S:SO2 ratio, or consult the Process Gas Analysis Table or the Process Gas Analysis Operating Chart that follows the Tutweiler Factor Chart.
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3.2
SULFUR BLOCK
3.1
Chart 2
3.0
Tutweiler Factor vs. Air Temperature
Tutweiler Factor
1.8
1.9
2.0
2.1
2.2
2.3
2.4
2.5
2.6
2.7
2.8
2.9
Sample Volume: 500 ml Baro. Pressure: 1.033 kg/cm2(a)
-30
-20
-10
0
10
20
30
40
50
Air Temperature, °C Issued 30 August 2011
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SULFUR BLOCK 9.10.4
Tailgas Analysis Table After completion of the Tutweiler iodine and sodium hydroxide titrations (see Section 1 on the preceding pages) the Molar (or Volume) ratio of hydrogen sulfide to sulfur dioxide in the SRU tailgas can be read directly from this table. If the readings fall off the table, divide (or multiply) both titration volumes by the same number in order to get within the range of the table. Note, however, that the iodine and sodium hydroxide solutions must be of the same Normality for the tabulated values to be correct. Examples: If 1.3 ml of 0.1 N iodine is used and 1.8 ml of 0.1 N sodium hydroxide is used, the molar ratio of H2S:SO2 = 1.60. If 3.0 ml I2 and 4.6 ml NaOH are used (these are off the table), divide by 2 to get 1.5 ml I2 and 2.3 ml NaOH, for a molar ratio of H2S:SO2 = 0.88. If 0.8 ml I2 and 1.1 ml NaOH are used, multiply by 2 to get 1.6 ml I2 and 2.2 ml NaOH, for a molar ratio of H2S:SO2 = 1.67. The values in the table below are the ratio of H2S:SO2 for the quantities of iodine and sodium hydroxide used in the titrations. NOTE:
This table is valid only when the Normalities of the iodine and sodium hydroxide solutions are the same.
ml I2
0.9 1.0 1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9 2.0
ml of NaOH 1.0
1.1
1.2
1.3
1.4
1.5
1.6
1.7
1.8
1.9
2.0
8.00 * * * * * * * * * * *
3.50 9.00 * * * * * * * * * *
2.00 4.00 10.00 * * * * * * * * *
1.25 2.33 4.50 11.00 * * * * * * * *
0.80 1.50 2.67 5.00 12.00 * * * * * * *
0.50 1.00 1.75 3.00 5.50 13.00 * * * * * *
0.28 0.67 1.20 2.00 3.33 6.00 14.00 * * * * *
0.12 0.43 0.84 1.40 2.25 3.67 6.50 15.00 * * * *
0.00 0.25 0.58 1.01 1.60 2.50 4.00 7.00 16.00 * * *
* 0.11 0.38 0.73 1.18 1.80 2.75 4.33 7.50 17.00 * *
* 0.00 0.51 0.88 1.35 2.00 3.00 4.67 8.00 18.00 *
* Erroneous Test
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SULFUR BLOCK ml I2
ml of NaOH 2.0
1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9 2.0 2.1 2.2 2.3 2.4 2.5 2.6
2.1
2.2
2.3
2.4
2.5
2.6
2.7
2.8
2.9
3.0
3.1
0.51 0.33 0.20 0.09 0.00 * * * * 0.88 0.63 0.44 0.30 0.18 0.08 0.00 * * 1.35 1.00 0.75 0.56 0.40 0.27 0.17 0.08 0.00 2.00 1.50 1.14 0.88 0.67 0.50 0.36 0.25 0.15 3.00 2.20 1.67 1.29 1.00 0.78 0.60 0.45 0.33 4.67 3.25 2.40 1.83 1.43 1.13 0.89 0.70 0.55 8.00 5.00 3.50 2.60 2.00 1.57 1.25 1.00 0.80 18.00 8.50 5.33 3.75 2.80 2.17 1.71 1.38 1.11 * 19.00 9.00 5.67 4.00 3.00 2.33 1.86 1.50 * * 20.00 9.50 6.00 4.25 3.20 2.50 2.00 * * * 21.00 10.00 6.33 4.50 3.40 2.67 * * * * 22.00 10.50 6.67 4.75 3.60 * * * * * 23.00 11.00 7.00 5.00 * * * * * * 24.00 11.50 7.33 * * * * * * * 25.00 12.00
* * * 0.07 0.23 0.42 0.64 0.90 1.22 1.63 2.14 2.83 3.80 5.33 7.67
* * * 0.00 0.14 0.31 0.50 0.73 1.00 1.33 1.75 2.29 3.00 5.25 5.50
* * * * 0.07 0.21 0.38 0.58 0.82 1.10 1.44 1.88 2.43 4.00 4.20
* Erroneous Test
9.10.5
Tailgas Analysis Operating Chart The titration volumes can also be used with the following Tailgas Analysis Operating Chart for a quick check to see how close to optimum ratio the sulfur plant is currently running.
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SULFUR BLOCK 6.0
Chart 3
5.5
Tailgas Analysis Operating Chart
5.0
H2S:SO2 = 2.3
(Both solutions must be the same normality) H2S:SO2 = 1.7
4.5
4.0
ml of Iodine Solution
DEFICIENT AIR
3.5
EXCESS AIR
3.0
2.5
2.0
1.5
1.0
0.5
0.0 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5.5 6.0 6.5 7.0 7.5 8.0 8.5
ml of Sodium Hydroxide Solution Issued 30 August 2011
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SULFUR BLOCK 9.10.6
Essential Apparatus for Tutweiler Analysis 1.
Tutweiler apparatus, complete, two 100 milliliter size and one 500 milliliter size.
2.
Burette clamps, single, two.
3.
Graduated cylinders, 100 milliliter and 50 milliliter, one each.
4.
Automatic burettes with Teflon stopcocks, 50 milliliter, two.
5.
Erlenmeyer flasks, 250 milliliter, four.
6.
Ring stands, two.
7.
Avery labels, approximately 7/8" x 1¼", one package.
8.
Thermometers, 0°C - 400°C and -30°C - 120°C ranges, three each.
9.
Volumetric flasks with glass stoppers, 1000 milliliter, two.
10. Volumetric flask with glass stopper, 2000 milliliter, one. 11. Dropper bottles, PE (polyethylene), 4 ounce (approx. 125 ml), two. 12. Rubber tubing, ¼" I.D. 13. Tubing clamps, six. 14. Tube fittings, ¼" pipe to ¼" rubber tubing, six. 15. Wash bottle, PE, 1 liter, one. 16. Reagent bottles, plain narrow mouth, with flat head stopper, Pyrex, 1 liter capacity, three. 17. Amber bottles with Bakline screw caps, 5 pint capacity (approx. 2.5 liters), two. 18. Aspirator bottle, 125 milliliter capacity, two.
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SULFUR BLOCK 9.10.7
9.10.8
Materials for Tutweiler Analysis 1.
Acculutes, sodium thiosulfate, 0.1 normal, two.
2.
Acculutes, sodium hydroxide, 0.1 normal, four.
3.
Acculutes, iodine, 0.1 normal, six.
4.
Methyl purple indicator in dropper bottle, 4 ounce (approx. 125 ml), one.
5.
Starch solution, stabilized, 1 quart (approx. 1 liter), one.
6.
Distilled water, 5 gallon, (approx. 20 liters), one.
7.
Stopcock grease, silicone, one tube.
H2S and SO2 Conc. in Tailgas Using Gas Detector Tubes As an alternative to the traditional wet-chemistry methods described in the preceding Section 1 for determining the concentrations of H2S and SO2 in the sulfur plant tailgas, gas detector tubes can be used to quickly and easily make this determination. Although the discussion that follows specifically addresses using gas detector tubes manufactured by Drägerwerk AG of West Germany, there may be suitable detector tubes available from other manufacturers. Dräger tubes can be purchased from most safety equipment supply companies. The following Dräger tubes are needed for this procedure:
9.10.8.1
H2S 0.2%
Dräger Cat. No. CH 281 01
(H2S + SO2) 0.2%
Dräger Cat. No. CH 282 01
Operating Principles Dräger tubes and other gas detector tubes measure gas concentrations by using a sample pump to draw a specific volume of the gas to be sampled into a glass tube containing a suitable reagent. The gaseous compound of interest chemically reacts with the reagent to produce a color change. The length of the "stain" line is a direct function of the concentration of the compound in the sample gas. Some detector tubes are calibrated with measured lines to allow reading the concentration directly on the tube. Others, such as the two listed above, have reference marks on the tube that can be multiplied by a factor to compute the concentration.
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SULFUR BLOCK Dräger tubes are designed to be used with a Dräger Model 31 gas detector pump. This is a hand-operated bellows pump that will draw a 100 cc sample volume for each pump stroke. Some tubes are designed for a single sample stroke, while others may use 5, 10, or even 20 strokes. In some cases, a tube may be used for measuring different concentration ranges by using a different number of strokes. a.
Dräger Cat. No. CH 281 01, H2S 0.2% This tube will measure H2S concentrations in the range of 0.2% to 7% when one sample stroke is used. If desired, the range can be reduced to 0.02% to 0.7% by using 10 sample strokes. Each tube contains a substrate of a pale blue copper compound. When exposed to H2S, the copper compound is converted to black copper sulfide. The length of the black stain, marked in cm on the tube, is multiplied by a factor stamped on the box to give the H2S concentration in percent. This copper sulfide reaction is not affected by any of the other compounds normally found in sulfur plant tailgas. SO2 in the tailgas may turn the indicating layer somewhat yellow (due to precipitation of elemental sulfur), but does not affect the H2S measurement.
b.
Dräger Cat. No. CH 282 01, (H2S + SO2) 0.2% This tube will measure the combined concentration of H2S and SO2 in the range of 0.2% to 7% if one sample stroke is used. If desired, the range can be reduced to 0.02% to 0.7% by using 10 sample strokes. Each tube contains a substrate of brown iodine. When exposed to H2S and/or SO2, the iodine reacts to form hydroiodic acid (a gas) and the brown color disappears. Since H2S reacts with iodine to form elemental sulfur, the brown will become pale yellow. The length of the yellow stain, marked in cm on the tube, is multiplied by a factor stamped on the box to give the H2S+SO2 concentration in percent.
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SULFUR BLOCK 9.10.8.2
Sampling the Tailgas The sulfur plant tailgas can be sampled from the sample valve on the outlet line from the fourth pass of the Sulfur Condenser.
Issued 30 August 2011
a.
Before beginning, check the Dräger pump for leaks by inserting an unopened tube into the pump and stroking the pump. Confirm that the bellows does not re-expand. If it does, either the pump or its seal around the tube is leaking, and the test results will not be accurate.
b.
Attach a short piece of rubber tubing to the process sample valve.
c.
Break off the tips at each end of an H2S Dräger tube and insert it into the sample pump (with the arrow on the side of the tube pointing toward the pump).
d.
Purge the rubber tubing by venting tailgas to the atmosphere for a few seconds. Pinch the rubber tubing closed at the end, close the gas sample valve, slip the end of the rubber tubing onto the end of the Dräger tube, and reopen the sample valve.
e.
Stroke the sample pump one time (be sure to compress the bellows until reaching the stops) and allow the pump to draw the gas sample into the detector tube. The sample stroke is complete when the metal chain on the bellows is taut.
f.
Close the sample valve, remove the rubber tubing from the end of the Dräger tube, and use the pump to draw two strokes of fresh air through the detector tube to complete the reactions.
g.
Read the length of the black stain using the cm marks on the tube and record the reading.
h.
Break off the tips at each end of an H2S+SO2 Dräger tube and insert it into the sample pump (with the arrow on the side of the tube pointing toward the pump).
i.
Repeat steps d through f.
j.
Read the length of the yellow stain using the cm marks on the tube and record the reading.
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SULFUR BLOCK k.
9.10.8.3
Check that the sample valve is closed, then remove the rubber tubing.
Calculations a.
Mole (or Volume) percent H2S (wet basis): Stain Factor 1013 Mole % H2S Length, cm on Box Baro. Pres., mbar
The last factor corrects the measurement for pressure effects when samples are taken at elevations above sea level. Note that the average barometric pressure at the complex is 14.7 PSIA = 1013 mbar. b.
Mole (or Volume) percent H2S+SO2 (wet basis): Stain Factor 1013 Mole % ( H2S SO2 ) Length, cm on Box Baro. Pres., mbar
c.
Mole (or Volume) percent SO2 (wet basis): Mole % SO2 = Mole % ( H2S + SO2 ) – Mole % H2S
d.
Molar (or Volume) Ratio of H2S to SO2 in the tailgas: H2S : SO2 Ratio
9.10.8.4
Mole % H2S Mole % SO2
Example Suppose, for example, that the following measurements are taken: Stain Length
Issued 30 August 2011
Factor on Box
H2S Tube
1.5 cm
0.44
H2S+SO2 Tube
2.1 cm
0.51
a.
Mole % H2S
1013 = (1.5 cm) (0.44) 1013
= 0.66%
b.
Mole % (H2S +SO2)
1013 = (2.1 cm) (0.51) 1013
= 1.07%
c.
Mole % SO2
= 1.07% - 0.66%
= 0.41%
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SULFUR BLOCK d.
H2S : SO2 Ratio
=
0.66% 0.41%
= 1.61
This indicates that the H2S:SO2 ratio is a little low (less than 2.0), so the air:acid gas ratio is on the high side. The output from the air demand hand control should be lowered slightly, and the measurements repeated after the SRU reaches a steady state again. If the H2S:SO2 ratio had been high (greater than 2.0), that would have meant that the air:acid gas ratio was on the low side. In that case, the output from thr air demand hand control would need to be raised slightly to increase the air flow and bring the H2S:SO2 ratio down.
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SULFUR BLOCK
9.11 Adjusting StackMatch® Ignitor/Pilots The pilots for the burners are StackMatch® DRAM (Dual Range Air Mixed) ignitor/pilot assemblies. The ignitor inside each pilot burner is a flame front generator (FFG). It works by taking part of the air and fuel gas mixture that is flowing to the primary pilot, igniting the mixture with a high-energy plasma spark, and allowing the flame "front" to travel down a flame delivery tube to the primary pilot tip, lighting the primary pilot. The small primary flame then ignites the much larger secondary pilot flame. Flame front generator ignitors are preferred for burners in sour service because the electrical parts are not exposed to the corrosive process atmosphere, giving the ignitor better long-term reliability. In order for a flame front generator to work properly, two conditions must be satisfied. First, the air:gas mixture must be within the flammability limits (neither too lean nor too rich). Second, the flowing velocity of the mixture must be higher than the flame speed so that the "fireball" will travel to the pilot. The ignitor has orifices to regulate the air and fuel gas, sized by the manufacturer to provide the proper quantities of air and fuel gas when both streams are at the manufacturer’s specified pressure as indicated on the pressure gauges for both air and fuel gas supplied on the pilot assembly. In theory, adjusting the pilot air and fuel gas regulators to the manufacturer’s specified pressure should be all that is needed to make the ignitor work. In practice, a certain amount of adjustment of the pressures is sometimes required before the ignitor works reliably, especially if the fuel gas composition is variable. However, once the proper pressures are determined, the ignitor can usually be made to work easily by making sure that the regulators are set to these pressures before attempting to ignite the pilot. If the pilot does not light with the regulators set at the design pressures, trial-and-error can be used to determine the proper regulator pressures. One technique that has worked well is described below. It requires two operators: one to adjust the regulators, one to control the ignition cycle and observe the pilot. 1.
Adjust the pilot air regulator to the manufacturer’s specified pressure.
2.
Unscrew the adjustment screw on the pilot fuel gas regulator so that the pilot fuel gas is at minimum pressure.
3.
Follow the procedures given in these guidelines to start the air blower and reset the shutdown system.
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SULFUR BLOCK 4.
The first operator raises the air flow (using the hand indicator controller) to satisfy the "PURGE REQUIRED" light, lowers the air flow to get the "PERMIT TO IGNITE", then pushes the "IGNITION" push-button to begin an ignition attempt.
5.
Once the ignition cycle starts, the second operator begins gradually increasing the pilot fuel gas pressure from the pressure control valve (observing the pressure on the local pressure gauge) while the first operator observes the operation of the pilot through one of the viewports on the burner.
6.
As the pilot fuel gas pressure increases, a flame will be observed on the pilot. When the flame is observed, the second operator should stop increasing the pilot fuel gas pressure.
7.
If the pilot does not ignite, repeat the sequence beginning at Step 4, starting with the pilot fuel gas regulator set where it was at the end of the previous ignition attempt, or a little lower.
8.
If repeated attempts at adjusting the fuel gas pressure are unsuccessful, changing the pilot air pressure regulator setting may be required. Try adjusting the air pressure 0.05-0.10 bar one way or the other.
9.
Once a flame is observed on the pilot, the pilot fuel gas pressure can then be adjusted to produce a good stoichiometric pilot flame. While the first operator continues to observe the pilot flame through the burner viewport, the second operator can raise or lower the pilot fuel gas pressure slightly until the pilot flame is dark blue:
10.
Issued 30 August 2011
a.
If the flame is yellow, the air:natural mixture is too "rich". Lower the fuel gas pressure with the pressure control valve to reduce the amount of fuel gas flowing to the pilot.
b.
If the flame is light blue, the air:natural mixture is too "lean". Raise the fuel gas pressure with the pressure control valve to increase the amount of fuel gas flowing to the pilot.
Once the pilot has ignited, make note of the pilot air and fuel gas pressures for future reference. The pilot regulators should be adjusted to these settings prior to subsequent startups.
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SULFUR BLOCK
Table of Contents 10.
SULFUR DEGASSING, STORAGE & LOADING .................................................. 10-3
10.1 PURPOSE OF SYSTEM ..................................................................................... 10-3 10.2 SAFETY ............................................................................................................... 10-4 10.3 PROCESS DESCRIPTION.................................................................................. 10-5 10.4 EQUIPMENT DESCRIPTION .............................................................................. 10-7 10.4.1 Sulfur Degassing Reactor, A2-DC1550 ........................................................ 10-7 10.4.2 Sulfur Storage Tank, A2-FB1550 ................................................................. 10-7 10.4.3 Sulfur Feed Pump, A2-GA1532A/B (A2-GA1542A/B) .................................. 10-8 10.4.4 Sulfur Loading Pump, A2-GA1550A/B ......................................................... 10-8 10.4.5 Degassing Air Blower, A2-GB1550A/B ......................................................... 10-9 10.4.6 Bed Support and Limiter for Sulfur Degassing Reactor, A2-DC1551 ........... 10-9 10.4.7 Degassed Sulfur Drain Seal Assembly, A2-ME1550.................................... 10-9 10.5 INSTRUMENTATION AND CONTROL SYSTEMS ........................................... 10-11 10.5.1 Sulfur Feed Rate Control ............................................................................ 10-11 10.5.2 Degassing Air Flow..................................................................................... 10-12 10.5.3 Sulfur Degassing Unit Startup Interlock ...................................................... 10-13 10.5.4 Snuffing Steam ........................................................................................... 10-13 10.5.5 Sulfur Loading ............................................................................................ 10-14 10.5.6 Sulfur Loading Pump Local Stop Switches................................................. 10-17 10.5.7 Sulfur Degassing Shutdown System .......................................................... 10-18 10.5.8 Sulfur Loading ESD System ....................................................................... 10-21 10.6 PROCESS PRINCIPLES AND OPERATING TECHNIQUES ........................... 10-23 10.6.1 Equipment Damage .................................................................................... 10-23 10.6.2 Degassing Air Blower Operation ................................................................ 10-26 10.6.3 Sulfur Solidification ..................................................................................... 10-29 10.6.4 Sulfur Pumping ........................................................................................... 10-29 10.7 PRECOMMISSIONING PROCEDURES ........................................................... 10-31 10.7.1 Preliminary Check-out ................................................................................ 10-31 10.7.2 Commissioning the Heating and Ventilation Systems ................................ 10-32 10.7.3 Purging the Sulfur Degassing Reactor ....................................................... 10-37 10.8 STARTUP PROCEDURES................................................................................ 10-40 10.8.1 Initial Startup of the Sulfur Degassing Unit ................................................. 10-40 10.8.2 Normal Startup of the Sulfur Degassing System ........................................ 10-46 10.8.3 Initial Sulfur Loading Operation .................................................................. 10-51 10.8.4 Normal Sulfur Loading Operation ............................................................... 10-53 10.9 SHUTDOWN PROCEDURES ........................................................................... 10-54 10.9.1 Planned Shutdown - No Reactor Entry....................................................... 10-54
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SULFUR BLOCK 10.9.2 10.9.3
Planned Shutdown for Reactor Entry ......................................................... 10-55 Shutdown for Tank Entry ............................................................................ 10-57
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SULFUR BLOCK
10. SULFUR DEGASSING, STORAGE & LOADING 10.1 Purpose of System The purpose of the Sulfur Degassing Unit (SDU) is to reduce the H2S content of the molten sulfur product to 10 PPMW or less, then transport the sulfur to the Sulfur Storage Tank.
The raw sulfur product from the sulfur plant contains
approximately 200-300 PPMW of hydrogen sulfide, which is typically reduced to 50-100 PPMW after one or more days of storage by natural "weathering". Since this natural weathering is not enough to meet the 10 PPMW specification for the sulfur product, the SDU provides additional degassing that will ensure that the H2S content is sufficiently low before the sulfur is transferred to the storage tank. The purpose of the Sulfur Storage & Loading system is to collect the degassed sulfur, hold it in a molten state, and then load it into trucks as a product for sale.
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SULFUR BLOCK
10.2 Safety
WARNING
ALL PIPING AND VESSELS INCLUDED IN THESE SYSTEMS CONTAIN MOLTEN SULFUR, WHICH IS A BURN HAZARD FOR PERSONNEL. CLOSE ATTENTION SHOULD BE PAID TO THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES REGARDING THE HAZARDS POSED BY MOLTEN SULFUR. IN ADDITION, ALL PIPING AND VESSELS INCLUDED IN THIS UNIT EITHER CONTAIN OR HAVE THE POTENTIAL FOR CONTAINING HAZARDOUS GASES THAT MAY CAUSE SERIOUS INJURY OR DEATH.
THE TWO GASES THAT ARE MOST COMMON
AND HAZARDOUS IN A TOXIC WAY ARE HYDROGEN SULFIDE AND SULFUR DIOXIDE.
CLOSE ATTENTION SHOULD BE PAID TO THE
"GENERAL SAFETY" SECTION OF THESE GUIDELINES AS TO THE NATURE AND ABILITY OF THESE GASES TO CONTAMINATE OTHER ELEMENTS IN THIS UNIT. AN EMPLOYEE'S KNOWLEDGE OF THE HAZARDOUS CHEMICALS AND COMPOUNDS WITH WHICH HE WILL BE WORKING IS ONE OF THE MOST BASIC PREREQUISITES FOR HIS OWN SAFETY, THE SAFETY OF
OTHERS,
AND
THE
PROTECTION
OF
EQUIPMENT.
ALL
EMPLOYEES SHOULD REVIEW THE "GENERAL SAFETY" SECTION OCCASIONALLY TO REFRESH THEIR MEMORIES. NEW EMPLOYEES SHOULD STUDY IT UNTIL THE INFORMATION IS THOROUGHLY UNDERSTOOD. PEOPLE WHO HAVE NOT BEEN PROPERLY TRAINED SHOULD NOT BE ALLOWED TO OPERATE OR WORK IN AND AROUND THIS PLANT.
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SULFUR BLOCK
10.3 Process Description The Systems Diagram, Material Balance and Process Flow Diagram, Dwg. Nos. 507000-7000-01, and 507000-7000-07 through -08, are contained in the "Process Flow Diagrams" Section of the Basic Engineering Package. Please refer to these drawings to follow this description of the process. The liquid sulfur produced in the condensers of a Claus sulfur plant is in contact with process gas containing hydrogen sulfide at elevated temperature and pressure. As a result, the fresh sulfur product from Claus plants contains a significant amount of hydrogen sulfide. Some of the hydrogen sulfide in the sulfur is dissolved H2S gas, but the majority of it is hydrogen polysulfide (H2SX) formed in the condensers by the following reaction: (1)
H2S + (x-1) S
H2SX
While the liquid sulfur is stored in the Sulfur Surge Tank, a considerable portion of the polysulfide will break down into H2S and be released into the ventilation air circulated through the vapor space of the tank. This natural "weathering" process typically reduces the H2S content of the molten sulfur to 50-100 PPMW after one or more days of storage. However, since the natural decomposition of H2SX in the liquid sulfur is a slow and generally incomplete process, additional means of degassing the sulfur must be employed to ensure that the H2S content of the sulfur product does not exceed 10 PPMW. The sulfur degassing technology licensed by BP Amoco Corporation is used to reduce the H2S content of the freshly produced sulfur (approximately 200-300 PPMW) to less than 10 PPMW.
The Sulfur Feed Pumps,
A2-GA1532A/B and A2-GA1542A/B pump the fresh liquid sulfur from the Sulfur Surge Tanks, A2-FB1530 and A2-FB1540 to the Sulfur Degassing Reactor, A2-DC1550. Compressed air from the Degassing Air Blower, A2-GB1550A/B is supplied to a sparger in the bottom of the reactor, so that the air and sulfur flow co-currently upward through a catalyst bed.
The catalyst promotes
decomposition of the polysulfide into H2S and sulfur, so that the air can strip the H2S from the sulfur and remove it from the reactor. Since reaction (1) is an equilibrium reaction, removal of the H2S by the air stream shifts the equilibrium toward the left side of the equation, allowing almost complete decomposition of
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SULFUR BLOCK the polysulfide. The degassed sulfur, containing less that 10 PPMW hydrogen sulfide, gravity-drains from the top of the reactor into the Sulfur Storage Tank, A2-FB1550, through the Degassed Sulfur Drain Seal Assembly, A2-ME1550. The drain seal has a "U" tube that uses static head from a column of liquid sulfur to serve as a seal and prevent the degassing air from escaping. The drain seal is steam jacketed to prevent sulfur from freezing and has a view hatch to allow verifying that the rundown line is flowing. The spent degassing air (containing H2S and traces of elemental sulfur vapor) leaves the top of the Sulfur Degassing Reactor and is routed to the TTO for incineration. The Sulfur Storage Tank is sized to hold about two week of production from the two SRUs, or about 500 MT when completely full. The tank is constructed of carbon steel and is equipped with internal steam coils and a ventilation system. The steam-jacketed Sulfur Loading Pump, A2-GA1550A/B, mounted beside the tank is used to load molten sulfur into trucks at two loading spots.
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SULFUR BLOCK
10.4 Equipment Description 10.4.1
Sulfur Degassing Reactor, A2-DC1550 The Sulfur Degassing Reactor contains a catalyst bed to promote the decomposition of the polysulfide into H2S and sulfur, so that the air from the Degassing Air Blowers can strip the H2S from the sulfur and remove it from the reactor. Sulfur enters the bottom of this vertical vessel and mixes with air entering through a sparger so that the air and sulfur flow co-currently upward through the catalyst bed.
The degassed sulfur
gravity-drains from the top of the vessel through the Degassed Sulfur Drain Seal Assembly and into the Sulfur Tank. The degassing air flows through a mist eliminator as it leaves the top of the reactor and is then routed to the Tailgas Thermal Oxidation system. Since the normal liquid level for molten sulfur in this reactor is at the top of the weir on the draw pan above the catalyst bed, the bottom head and shell of the vessel are steam-jacketed. The inlet and outlet sulfur, inlet air, outlet gas, and clean-out nozzles are also steam-jacketed.
10.4.2
Sulfur Storage Tank, A2-FB1550 The Sulfur Storage Tank is an above-ground vertical cylindrical tank. It has serpentine steam coils in the bottom and circumferential steam coils on the sides to keep the sulfur molten, each with its own steam supply and trap. Should a steam coil develop a leak, it can be shut off while the others keep the sulfur hot. It has a level transmitter to indicate the sulfur level, with a high level alarm to alert the operators of a high level. There is a snuffing steam line entering the top of the tank in case of fire. The primary ventilation system for the Sulfur Storage Tank is a natural-draft ventilation system.
Ambient air enters through the four
breather vents placed around the top of the tank and sweeps through the tank. This air circulation dilutes the H2S that may "weathers off" from the liquid sulfur so that the concentration remains below the lower explosive limit. The air circulation also prevents accumulation of water in the tank that could cause rapid corrosion. The vapors are vented from the vessel
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SULFUR BLOCK through a 3 m tall heated vent stack, mounted on top of the tank. The steam-jacketing on the vent stack heats the air in the stack, providing the natural-draft driving force that draws ambient air into the tank to sweep the vapor space.
WARNING
IT IS VERY IMPORTANT TO KEEP HEAT (STEAM) ON THE VENT STACK TO MAINTAIN THE NATURAL DRAFT. IN ADDITION, THE STEAM SPACE IN THE VENT STACK JACKET MUST VENTED PERIODICALLY
TO
PREVENT
NON-CONDENSIBLES
FROM
ACCUMULATING AND "BLANKING OFF" THE STEAM HEATING SURFACES. A VENT LINE IS PROVIDED EXPRESSLY FOR THIS PURPOSE.
10.4.3
Sulfur Feed Pump, A2-GA1532A/B (A2-GA1542A/B) These special steam-jacketed sump-type pumps are used to transfer the molten sulfur product from the Sulfur Surge Tanks to the Sulfur Degassing Reactor. This type of pump is unique in that it uses the molten sulfur to lubricate its bearings.
For this reason, the pumps should never be
operated dry.
10.4.4
Sulfur Loading Pump, A2-GA1550A/B These pumps are horizontal centrifugal pumps. They are steam-jacketed to keep the sulfur in the molten state and send it to the loading stations for sulfur trucks. Start and stop push-buttons are located at the loadings station for ease of loading. Stop switches are also located at the pumps for emergency use.
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SULFUR BLOCK 10.4.5
Degassing Air Blower, A2-GB1550A/B These single-stage rotary lobe blowers provide the degassing air required to strip the H2S from the sulfur in the Sulfur Degassing Reactor. The blowers are connected to the discharge piping through flexible connectors to allow the necessary freedom for the expansion and movement that occurs during normal operation.
10.4.6
Bed Support and Limiter for Sulfur Degassing Reactor, A2-DC1551 A bed support and a bed limiter fabricated from grid-type 304 S.S. screen are used to hold the catalyst bed in the Sulfur Degassing Reactor. The screens are fabricated in sections that fit through the vessel manways. One side of each screen section is equipped with flashing where it fits next to its neighbor, so that the screen sections can expand and contract without creating gaps where the catalyst could leak through. Both the bed support and the bed limiter are designed to have about a 12 mm gap next to the vessel shell to allow for differential thermal expansion between the bed support and the vessel.
Ceramic rope
packing is used to fill this gap so that catalyst cannot leak between the bed support and the vessel shell.
10.4.7
Degassed Sulfur Drain Seal Assembly, A2-ME1550 One of Ortloff's proprietary Sulfur Drain Seal Assemblies is used for the Degassed Sulfur Drain Seal Assembly. It is designed to drain liquid sulfur from the Sulfur Degassing Reactor. The seal is built as a "U-type" trap that uses liquid sulfur to seal and prevent process gases from flowing to the Sulfur Tank along with the liquid sulfur product. The drain seal is sized to provide a seal leg which should not blow out at the maximum operating pressure of the Sulfur Degassing Reactor. The seal is fully steam-jacketed and designed to be installed in the top of the Sulfur Tank.
The seal has a hinged inspection hatch to allow
observation and sampling of the flow from the Sulfur Degassing Reactor. The liquid sulfur from the inspection basin flows down to the bottom of the
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SULFUR BLOCK Sulfur Tank through a drain pipe to prevent free-fall of the liquid sulfur, which could cause static electricity to build up. The drain seal is mostly carbon steel, except for the inspection hatch which is aluminum. The drain seal has a removable blind flange to allow "rodding" its rundown line, and a removable blind flange to allow "rodding" its dip leg. Before removing either flange, close the plug valve in the rundown line to prevent the escape of process gas to the surroundings when the plug is cleared. When the rodding operation is complete and the flange(s) are back in place, remember to reopen the plug valve.
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SULFUR BLOCK
10.5 Instrumentation and Control Systems 10.5.1
Sulfur Feed Rate Control A reasonably steady sulfur feed rate to the Sulfur Degassing Reactor will help the Sulfur Degassing Unit operate smoothly.
At the same time,
however, the feed rate to the reactor must match the sulfur production rate into the Sulfur Surge Tanks from the SRUs reasonably closely, or else the Surge Tanks will eventually run dry. A level/flow cascade control loop is used to satisfy these requirements. Traditional level measuring devices do not function reliably in molten sulfur service. For this reason, a "bubbler"-type level transmitter is most often used in this service.
A steam-jacketed pipe (a bubbler tube) is
mounted through the top of the Sulfur Surge Tank and extended nearly to the bottom of the tank. A small flow of instrument air is introduced into the inner pipe, so that air slowly bubbles from the bottom of the pipe up through the sulfur. The pressure inside the bubbler tube depends on the static head imposed by the liquid sulfur in the tank, which is a linear function of the liquid level.
The DCS can then convert this pressure
measurement into the corresponding liquid sulfur level in the tank. This type of level measuring device is used for A2-LT15450 and A2-LT15449. Traditional flow measuring devices also do not function reliably in molten sulfur service. For this reason, a "Coriolis"-type mass flow meter is used to measure the liquid sulfur as it is pumped from the Sulfur Surge Tanks into the Sulfur Degassing Reactor by the Sulfur Feed Pumps. The flow meter, A2-FT15450, is located downstream of the take-off for the spill-back line so that the sulfur feed rate from SRU 1 into the reactor can be adjusted by varying the amount of sulfur spilling back into the tank. The level in the tank is controlled by A2-LIC15450, which supplies a cascade setpoint to the sulfur feed rate controller, A2-FIC15450. If the level is rising in the tank, the feed rate from SRU1 to the Sulfur Degassing Reactor will be slowly increased by raising the setpoint of A2-FIC15450. If the level is falling, the setpoint will be lowered to slowly reduce the feed rate. In this manner, the level in the Sulfur Surge Tank can be maintained
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SULFUR BLOCK at the desired value while avoiding sudden changes in the feed rate to the Sulfur Degassing Reactor.
10.5.2
Degassing Air Flow A constant ratio of degassing air flow to sulfur flow is not necessary for the Sulfur Degassing Unit to operate smoothly. It is only necessary that the air:sulfur flow ratio be maintained above a minimum value (45 Nm3/MT) to ensure adequate stripping of the sulfur. The air flow rate to the Sulfur Degassing Reactor is not controlled, but instead is simply dictated by the capacity of the Degassing Air Blower. The design flow rate of one of these blowers is high enough to maintain the air:sulfur flow ratio above the minimum even at the design sulfur production rate. There are two reasons for using a fixed degassing air flow rate rather than controlling the air:sulfur flow ratio.
The first reason is that the spent
degassing air from the Sulfur Degassing Reactor is routed to the Thermal Oxidizer as a part of its feed. Keeping the degassing air flow rate at a constant value makes it easier to maintain good temperature control in the TTO. The second reason is that variations in the air flow rate can cause fluctuations in the sulfur feed rate to the Sulfur Degassing Reactor. The pumping rate of the Sulfur Feed Pumps depends on the discharge pressure from the pumps, which is in turn a function of the static head imposed on the pump discharge. This static head has two components: the static head of the liquid sulfur in the discharge piping going to the Sulfur Degassing Reactor, and the static head of the sulfur/air mixture in the Sulfur Degassing Reactor. While the first static head is essentially constant because the density of liquid sulfur is relatively constant, the second static head depends on the density of the sulfur/air mixture in the reactor. Small changes in the degassing air flow rate cause very large changes in the density of the sulfur/air mixture, which then cause very large changes in the pump discharge pressure.
Field experience has
shown that the sulfur flow rate remains much steadier when the degassing air flow rate is held at a fixed value. If the degassing air flow rate ever drops too low (as signaled by the low Issued 30 August 2011
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SULFUR BLOCK flow alarm on A2-FI15702) and the low flow condition cannot be corrected in a reasonable length of time, the SDU should be shut down until the air flow problem has been corrected.
10.5.3
Sulfur Degassing Unit Startup Interlock The purpose of this interlock is to ensure the Sulfur Degassing Unit equipment is placed in operation in a safe manner. This interlock includes several permissives which must be satisfied in the correct order, or the pumps and blowers will not start. The logic flowchart for the SDU "start" permissives is contained in the Instrumentation and Controls Diagrams section of the Basic Engineering Package. These permissives are (in order): (1)
Start a Sulfur Feed Pump.
(1)
Allow the pump to fill the Sulfur Degassing Reactor to satisfy its low-low level shutdown.
(2)
Start a Degassing Air Blower and press its "reset" push-button to open its discharge valve.
Failure to satisfy a permissive will prevent proceeding any further in the startup sequence.
This prevents creating conditions in the Sulfur
Degassing Reactor that could lead to problems (fires, etc.)
10.5.4
Snuffing Steam There are snuffing steam lines entering the top of each Sulfur Surge Tank to flood the vapor space with LP steam in case a fire develops inside a tank. The snuffing steam supply valves are operated by either a remote switch in the DCS or a local switch that is located at least 50 feet from the tank. Opening this valve for a few minutes will fill the vapor space of the tank with steam and displace all of the air, quickly extinguishing the fire. There is a snuffing steam line entering the top of the Sulfur Storage Tank to flood the tank vapor space with LP steam in case a fire develops inside the tank. The snuffing steam supply valve is operated by either a remote switch in the DCS or a local switch that is located at least 50 feet from the tank. Opening this valve for a few minutes will fill the vapor space of the
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SULFUR BLOCK tank with steam and displace all of the air, quickly extinguishing the fire. The logic for the snuffing steam valves is contained in the Instrumentation and Controls Diagrams section of the Basic Engineering Package. They can be opened by "toggling" the switch in the DCS to "on" or by pressing the local push-button. The valve can be closed later by "toggling" the switch in the DCS to "off" or by pressing the local push-button again.
10.5.5
Sulfur Loading The Sulfur Loading system is designed to load molten sulfur from the Sulfur Storage Tank into sulfur trucks, or both simultaneously.
The
loading operations are controlled by a programmable logic controller (PLC) housed in a local control panel located inside the loading building in the sulfur loading area. Status indicator lights are mounted on the front of this panel to allow monitoring operation of the system and to assist with troubleshooting. The logic for sulfur loading operations is shown on the Logic Flow Diagrams contained in the Instrumentation and Controls Diagrams section of the Basic Engineering Package. Note that only one Sulfur Loading Pump at a time is used for loading, regardless of whether one or both loading spots are being used. Selector switch A2-HS15716 is used to select which Sulfur Loading Pump is active. 10.5.5.1
Starting Sulfur Loading The sequence of events when beginning sulfur loading can be summarized as follows. (1)
The truck driver spots his truck and connects the grounding cable.
(2)
The truck driver presses the "START" push-button on the applicable start/stop station. The associated status light at that loading spot begins flashing and a timer for that loading spot is started.
(3)
The discharge valve on the Sulfur Loading Vent Ejector (A2-EE1550A or A2-EE1550B) at that loading spot is opened
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SULFUR BLOCK and proven open. (4)
The motive steam valve on the Sulfur Loading Vent Ejector at that loading spot is opened and proven open.
(5)
The sulfur loading valve at that loading spot is opened and proven open.
(6)
A Sulfur Loading Pump (A2-GA1550A or A2-GA1550B) is started, a timer for that pump is started, and the associated status light for that pump on the local loading control panel begins flashing. If the other loading spot is not currently active, the "lead" pump is started. If the other loading spot is active, the "lag" pump is started. When selector switch A2-HS15716 is set to "NORMAL", the "A" and "B" pumps will alternate in the "lead" position after each loading operation. If A2-HS15716 is set to either "A" or "B", only that pump is to be started even when both loading spots are active.
(7)
When its motor starter contacts show that the pump is running, the discharge valve for that pump is opened and proven open.
(8)
If the pump discharge valve is proven open before the timer on that pump times out, the pump status light stops flashing and remains steadily illuminated. If the timer times out before the pump discharge valve is proven open, the pump is stopped, its discharge valve is closed, its status light is extinguished, and the corresponding "pump start failure" alarm is activated. If it was the "lead" pump that failed to start, then an attempt is made to start the "lag" pump beginning at step (6). If the timer for the "lag" pump times out before its discharge valve is proven open, the "lag" pump is stopped, its discharge valve is closed, its status light is extinguished, the corresponding "pump start failure" alarm is activated, and the "PUMP START FAILURE" status
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SULFUR BLOCK light on the local loading control panel is illuminated. The Sulfur Loading ESD is also activated to stop both pumps and close all of the valves (pump discharge, sulfur loading, motive steam, and ejector discharge). (9)
If one of the pumps is successfully started before the timer on that loading spot times out, the status light for that loading spot stops flashing and remains steadily illuminated, and sulfur will begin flowing into the truck.
10.5.5.2
Stopping Sulfur Loading The sequence of events when ending sulfur loading can be summarized as follows. (1)
The truck driver presses the "STOP" push-button on the applicable start/stop station. The associated status light at the loading spot begins flashing.
(2)
If the other loading spot is not currently active, stopping of the "lead" pump is initiated.
If the other loading spot is active,
stopping of the "lag" pump is initiated. The applicable pump status light on the local loading control panel begins flashing. (3)
The applicable pump (A2-GA1550A or A2-GA1550B) is stopped.
(4)
The applicable discharge valve is closed and proven closed.
(5)
When its motor starter contacts show that the pump is stopped and the limit switches show the pump discharge valve is closed, the pump status light on the local loading control panel is extinguished.
(6)
The sulfur loading valve at that loading spot is closed and proven closed.
(7)
The motive steam valve on the Sulfur Loading Vent Ejector at that loading spot is closed and proven closed.
(8)
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The discharge valve on the Sulfur Loading Vent Ejector at that
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SULFUR BLOCK loading spot is closed and proven closed. (9)
10.5.6
The status light for that loading spot is extinguished.
Sulfur Loading Pump Local Stop Switches Section 10.5.5 describes how the pump start and stop push-buttons located at the truck loading stations are used to transfer sulfur from the Sulfur Storage Tank to the loading spots. Local pump "stop" switches are located at each pump for maintenance or emergency use. Setting one of these switches to the "STOP" position will remove the power from the corresponding pump motor to prevent that pump from running.
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SULFUR BLOCK 10.5.7
Sulfur Degassing Shutdown System The purpose of the Sulfur Degassing Unit Emergency Shutdown system (SDU ESD) is to shut off the sulfur and degassing air flow to the Sulfur Degassing Reactor, A2-DC1550, when serious problems occur.
The
Cause and Effect Diagram, contained in the Instrumentation and Controls Diagrams section of the Basic Engineering Package, describes the SDU ESD system in block format. For reference, the causes and effects of the ESD system shown on this diagram are explained below. 10.5.7.1
Causes Any one of the devices listed below will activate the SDU ESD:
a.
No Sulfur Feed Pump Running, A2-GA1542A&B starter contacts
A2-GA1532A&B
and
If no Sulfur Feed Pump is running, the loss of sulfur flow with continued degassing air flow could cause a fire in the Sulfur Degassing Reactor.
The motor starter contacts are used to
determine whether a pump is running, and activate the SDU ESD if neither is running. a.
Sulfur Degassing A2-TT15703A/B/C
Reactor
High-High
Temperature,
There is always a potential for a fire in the Sulfur Degassing Reactor since sulfur is flammable at elevated temperatures (generally above 237°C) and it is in contact with air. The heat from a sulfur fire would damage the equipment if allowed to continue burning. If this device detects a high temperature from a fire or a runaway reaction, it will activate the SDU ESD to shut off the sulfur and degassing air flows before equipment damage occurs. The setpoint for these devices is 205°C. b.
No Degassing Air Blower Running, A2-GB1550A and A2-GB1550B starter contacts If there is no Degassing Air Blower running, the Sulfur Degassing system is not operating properly and requires operator attention. The motor starter contacts are used to determine whether a blower is
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SULFUR BLOCK running, and activate the SDU ESD if neither of the blowers is running. c.
Sulfur Degassing Reactor High-High Level, A2-LT15704A A high-high level in the Sulfur Degassing Reactor could allow liquid sulfur to begin to carry-over into the Thermal Oxidizer. This device activates the SDU ESD to shut off the pumps and blowers should this occur. The shutdown setpoint for this device is 5,300 mm above the bottom seam of the reactor vessel.
d.
Sulfur Degassing Reactor Low-Low Level, A2-LT15704B A low-low level in the Sulfur Degassing Reactor indicates the Sulfur Degassing system is not operating properly and requires operator attention. This device activates the SDU ESD to shut off the pumps and blowers should this occur. The shutdown setpoint for this device is 3,850 mm above the bottom seam of the reactor vessel.
10.5.7.2
Effects A Sulfur Degassing Shutdown, activated by any one of the devices listed above, has the following effects on the Sulfur Degassing Unit:
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a.
Shuts down the Sulfur Feed Pump, A2-GA1532A/B and A2-GA1542A/B, to stop the flow of sulfur into the Sulfur Degassing Reactor.
b.
Shuts down the Degassing Air Blower, A2-GB1550A/B, to stop the flow of air into the Sulfur Degassing Reactor.
c.
Closes the Sulfur Feed Pump discharge valves to prevent draining all of the sulfur out of the Sulfur Degassing Reactor.
d.
Closes the Degassing Air Blower discharge valves, A2-NV15701A and A2-NV15701B, to prevent back-flow and possible venting of any hazardous gases to the atmosphere.
e.
Places each sulfur feed controller in "manual" and sets its output to 0% to close the control valve in each spill-back line and prevent draining all of the sulfur out of the Sulfur Degassing Reactor. (The normal control action would close these valves when the associated pump stops and the sulfur quits flowing, but it may not do so quickly enough to prevent much of the
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SULFUR BLOCK sulfur from draining out of the reactor.) 10.5.7.3
Non-ESD Shutdowns and Alarms a.
Sulfur Surge Tank Low-Low Level, A2-LT15449 and A2-LT649 Each Sulfur Feed Pump is based on a unique design that uses the molten sulfur to lubricate the shaft bearings. It requires a minimum submergence above the impeller to ensure steady flow so that the bearings remain lubricated; otherwise, the pump could be damaged.
This transmitter will activate the
SDU ESD to shut down the pump if the level in the raw production section of the Sulfur Tank gets too low. It is set to actuate if the liquid level drops to 450 mm above the tank floor, however this value should be confirmed once a specific pump has been selected.
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SULFUR BLOCK 10.5.8
Sulfur Loading ESD System The purpose of the Sulfur Loading Emergency Shutdown (ESD) system is to stop all the sulfur loading equipment when serious problems occur. The Cause and Effect Diagrams, contained in the Instrumentation and Controls Diagrams section of the Basic Engineering Package, describes the Sulfur Loading ESD system in block format. For reference, the causes and effects of the ESD system shown on this diagram are explained below.
10.5.8.1
Causes Any one of the causes listed below will activate the Sulfur Loading ESD system: a.
Manual Shutdown Switches, A2-HS15727 and A2-HS15728 An operator can activate the Sulfur Loading ESD system using either of two manual shutdown switches:
b.
(1)
A2-HS15727 is a NORMAL / ESD selector switch mounted in the truck loading area.
(2)
A2-HS15728 is a NORMAL / ESD selector switch mounted on the local loading control panel.
Sulfur Storage Tank Low-Low Level, A2-LT711A The Sulfur Loading Pump (A2-GA1550A/B) could be damaged if the pump loses suction because the level in the Sulfur Storage Tank drops too low. These devices will protect the pump by stopping it before this can occur.
The shutdown
setpoint is 600 mm above the bottom of the tank. c.
Both Sulfur Loading Pumps Fail to Start, PLC logic If neither the "lead" nor the "lag" Sulfur Loading Pump starts, the Sulfur Loading ESD system is activated to shut down the system and direct operator attention to the loading system.
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SULFUR BLOCK 10.5.8.2
Effects A Sulfur Loading Shutdown, activated by any one of the devices listed above, has the following effects on the Sulfur Loading system:
10.5.8.3
a.
Shuts down the Sulfur Loading Pump (A2-GA1550A&B) to stop the flow of sulfur to the loading arms.
b.
Closes the Sulfur Loading Pump discharge valves.
c.
Closes the sulfur loading valves to stop the flow of sulfur from the loading arms.
d.
Once the sulfur loading valves are closed, closes the motive steam valves on the Sulfur Loading Vent Ejector (A2-EE1550A&B).
e.
Once the motive steam valves are closed, closes the discharge valves on the Sulfur Loading Vent Ejector.
Non-ESD Shutdowns In addition to the devices listed in Section 10.5.8.1 that activate the Sulfur Loading ESD system, there is one additional interlock of significance that shuts down individual pieces of equipment. a.
Loading Spot Ground Disconnected, A2-CS15721A&B If continuity is lost for the ground connection at a loading spot, that loading spot is shut down, and the applicable Sulfur Loading Pump is stopped.
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SULFUR BLOCK
10.6 Process Principles and Operating Techniques The more important considerations involved in startup, operation, shutdown, maintenance, and emergency procedures of the Sulfur Degassing and Sulfur Storage & Loading systems are discussed in the remaining sections of this portion of the operating guidelines. The operator should also be thoroughly acquainted with the equipment and the "Process Description" section in these guidelines before attempting to operate the plant in accordance with the operating techniques that follow. If the function of each portion of the plant equipment is understood, the sequence of steps outlined in the "procedures" sections will be more easily understood.
In addition, the following general
discussion of principles and techniques will clarify the reasons for some of the procedures.
10.6.1
Equipment Damage After the initial startup, the Sulfur Degassing Unit will contain some sulfur throughout the system. Even when sulfur is drained out of the Sulfur Degassing Reactor, the interior of the vessel will still be coated with residual sulfur.
Elemental sulfur and/or iron sulfide in the Sulfur
Degassing Reactor may ignite if the Degassing Air Blower continues to run during periods when either both Sulfur Feed Pumps are shut off or the reactor is not full of liquid sulfur. The heat from the fire can damage the reactor and its outlet lines if allowed to continue burning. For this reason, it is important that the degassing air not be introduced into the Sulfur Degassing Reactor until it has been filled up to its normal operating level with molten sulfur. This will ensure that if any iron sulfide ever develops on the walls of the reactor, it will be immersed in the liquid sulfur so that air cannot contact the walls directly and cause spontaneous auto-ignition of the iron sulfide. The walls of the reactor above the normal liquid level are always exposed to an oxygen-rich atmosphere, so iron sulfide should not form above the air-liquid interface level in the reactor. Note that the interior of the Sulfur Degassing Reactor is lined with a baked phenolic coating to prevent iron sulfide from forming, but over time the lining may deteriorate and expose some of the carbon steel.
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SULFUR BLOCK When air first begins flowing through the Sulfur Degassing Reactor when it is full of raw (not partially degassed) sulfur, it is possible for the H2S concentration in the degassing air leaving the reactor to be above the lower explosive limit for a short period of time if the air flow rate is too low. For this reason, it is important to raise the air flow to its normal value quickly when first starting air flow to the Sulfur Degassing Reactor with it full of raw sulfur.
WARNING
NEVER START A DEGASSING AIR BLOWER UNLESS EACH OF THE FOLLOWING IS TRUE: 1. THE SULFUR DEGASSING REACTOR IS FILLED WITH LIQUID SULFUR UP TO ITS NORMAL OPERATING LEVEL AND SULFUR IS RUNNING OUT OF THE SULFUR DRAIN SEAL. 2. A SULFUR FEED PUMP IS RUNNING AND THE SULFUR FLOW METER DOWNSTREAM OF THE RUNNING PUMP INDICATES SULFUR IS FLOWING. 3. THE UPSTREAM SRU(S) IS OPERATING SMOOTHLY IF IT(THEY) IS ON-LINE. 4. THE THERMAL OXIDIZER IS ON-LINE AND OPERATING SMOOTHLY.
FAILURE TO OBSERVE THESE PRECAUTIONS COULD CAUSE A FIRE
AND/OR
EXPLOSION
IN
THE
SULFUR
DEGASSING
REACTOR.
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SULFUR BLOCK
CAUTION
NEVER "HYDROBLAST" THE STEEL SURFACES IN THE SULFUR DEGASSING EQUIPMENT. NOT ONLY DOES THIS REMOVE THE PROTECTIVE SULFIDE FILM THAT FORMS ON CARBON STEEL AND PREVENTS CORROSION, THE WATER WILL REACT WITH THE SULFUR COMPOUNDS PRESENT IN THE EQUIPMENT TO FORM A VARIETY OF ACIDS (SULFUROUS, POLYTHIONIC, ETC.) THAT WILL RAPIDLY CORRODE THE STEEL. After the initial startup, the Sulfur Storage & Loading system will also contain sulfur throughout the system. Even when the sulfur is pumped out of the Sulfur Storage Tank, the interior of the tank will still be coated with residual sulfur. Elemental sulfur and/or iron sulfide in the Sulfur Storage Tank may ignite when ventilating the tank with air prior to maintenance operations. The heat from the fire can damage the tank if allowed to continue burning, so use the snuffing steam to extinguish the fire should this occur. The walls of the tank above the liquid level are exposed to an oxygen-rich atmosphere (due to the ventilation system sweeping air through the vapor space of the tank), so little iron sulfide should form above the highest air-liquid interface level in the tank. The middle region of the tank walls should not have much iron sulfide, either, since the oxygen in the sweep air will oxidize the iron sulfide as soon as the level is pumped back down. However, the "heel" region of the tank may build up a considerable quantity of iron sulfide, so auto-ignition of this iron sulfide is always a potential problem when preparing the tank for maintenance.
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SULFUR BLOCK 10.6.2
Degassing Air Blower Operation The Degassing Air Blowers, A2-GB1550A/B, are conventional rotary-lobe positive displacement air compressors.
Although these air blowers
operate much like conventional air compressors, the blowers do require some special attention during startup or when bringing an off-line blower into service. These cases are discussed in the sections below. 10.6.2.1
Starting a Degassing Air Blower There are a couple of issues that merit discussion regarding starting a Degassing Air Blower.
First, like any positive displacement
compressor or pump, these blowers must not be started up against a blocked discharge to avoid physically damaging the blower. Instead, the blow-off valve in the blower discharge line should always be fully opened before starting a blower. This allows the blower to start in an unloaded condition, minimizing the stress on the blower and motor, and prevents any possibility of over-pressuring the blower casing or discharge piping. The second issue is related to the manner in which the Sulfur Degassing Reactor must be brought on-line. The Sulfur Degassing Reactor must be filled with liquid sulfur up to the normal operating level (the top of the side weir on its draw pan) before degassing air is introduced into the reactor. As the sulfur is filling the reactor, it will "back" into the degassing air feed line (since there is no air flow at this point) as the liquid "seeks its own level". Once the reactor has been filled with sulfur, there will be liquid sulfur in the degassing air line up to about the same elevation as the sulfur in the reactor. This section of piping is steam-jacketed so freezing of the sulfur is not a concern. What is a concern, however, is what happens when the discharge valve on the Degassing Air Blower first opens. Before the valve opens, the pressure in the vapor space of the Sulfur Degassing Reactor should be at nearly atmospheric pressure, since the spent degassing air is routed to the Thermal Oxidizer.
The
degassing air line will also be at low pressure because the discharge
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SULFUR BLOCK valve on the Degassing Air Blower will still be closed at this point, even though the blower may be running. But when a Degassing Air Blower is started and it's "reset" push-button is pressed, the PLC will open the discharge valve on the blower. If there is back-pressure on the Sulfur Degassing Reactor from the TTO when the discharge valve opens, the pressure inside the Sulfur Degassing Reactor will force liquid sulfur from the reactor up into the degassing air line. If the back-pressure is high enough, liquid sulfur could overflow the "loop seal" in the degassing air line, allowing sulfur to back down the line to the Degassing Air Blower. This can be prevented by "pinching" the blow-off valve on the Degassing Air Blower discharge line before pressing the "reset" push-button to allow the pressure in the line to build up before the valve opens. Then the pressure in the degassing air line will keep the sulfur from overflowing the loop seal.
The procedure for
commencing degassing air flow described later in these guidelines includes the following steps:
10.6.2.2
(1)
Fully open the blow-off valve on the blower.
(2)
Start the blower and let it come up to speed.
(3)
Slowly "pinch" the blow-off valve until the discharge pressure increases to 0.07-0.15 kg/cm2(g).
(4)
Press the "reset" push-button to open the blower discharge valve.
(5)
Slowly close the blow-off valve the rest of the way to establish air flow into the Sulfur Degassing Reactor.
"Swapping" Degassing Air Blowers During Operation While the Sulfur Degassing Unit is running, it is sometimes necessary to "swap" air blowers to bring the off-line blower on-line so that the other blower can be shut down.
This can usually be
accomplished with only a slight "bobble" to the SDU by starting and stopping the blowers in the proper sequence. The procedure given below is one technique that should make swapping blowers relatively
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SULFUR BLOCK simple and avoid any problems. A.
On the on-line blower: (1)
B.
Confirm that the valve in its blow-off line is fully closed.
On the off-line blower: (1)
Confirm that its discharge valve is closed.
(2)
Fully open its blow-off valve.
C.
Start the off-line blower using its local start/stop control station.
D.
After the off-line blower comes up to speed, press its "reset" push-button to open its discharge valve. Since its blow-off valve is still wide open at this point, the blower will not be able to develop enough discharge pressure to open the check valve in its discharge line.
E.
Slowly "pinch" the blow-off valve on the off-line blower until its discharge pressure rises enough to open its check valve and begin sending some of its air to the Sulfur Degassing Reactor.
F.
Slowly open the blow-off valve on the on-line blower to begin venting some of its air to atmosphere.
G.
Continue to close the blow-off valve on the off-line blower and open the blow-off valve on the on-line blower. Observe the degassing air flow rate on the local indicator on the degassing air flow transmitter and proceed slowly enough to keep the degassing air flow rate stable.
H.
Once the blow-off valve is fully closed on the one blower and fully open on the other blower, the off-line blower is now the on-line blower and vice versa. Use the local start/stop control on what is now the off-line blower to stop that blower and close its discharge valve, then close its blow-off valve.
I.
The blower swap is now complete. Before leaving the area, visually confirm that: (1)
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The off-line blower is stopped.
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SULFUR BLOCK
10.6.3
(2)
The discharge and blow-off valves on the off-line blower are closed.
(3)
The on-line blower is running smoothly.
(4)
The Sulfur Degassing Unit has returned to steady operation.
Sulfur Solidification Sulfur melts at 119°C [246°F]. All surfaces in these systems must be maintained above this temperature while the system contains sulfur to avoid plugging the piping or damaging rotating equipment due to formation of solid sulfur. For this reason, there are steam coils along the bottom inside of the Sulfur Surge Tanks, and along the walls and bottom inside the Sulfur Storage Tank. The Sulfur Feed Pumps and Sulfur Loading Pump are steam-jacketed. All of the piping and valves in liquid sulfur service are steam-jacketed, as are the ventilation systems on the Sulfur Surge Tanks and Sulfur Storage Tank. The steam traps serving these heating systems should be checked regularly to verify proper operation. The simplest method to do this is to verify that sulfur will melt on the steam trap inlet; if the condensate there is hot enough to melt sulfur, then the steam in the jackets will be hot enough, too. It is also important to periodically sweep the non-condensibles out of the jackets and coils by giving their vent valves a good "blow". This will prevent the accumulation of non-condensibles that could create localized "cold" spots where sulfur can freeze.
10.6.4
Sulfur Pumping Pure sulfur undergoes a phase change at about 158°C [317°F] that causes a tremendous increase in its viscosity. Although dissolved H2S reduces the magnitude of the increase, and sulfur produced in Claus SRUs always contains some H2S, this temperature region must be avoided to prevent problems in handling the molten sulfur.
This is
particularly important for the sulfur in the Sulfur Storage Tank, since degassing significantly reduces the H2S content of the sulfur. Accordingly, the temperature inside the Sulfur Storage Tank and the
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SULFUR BLOCK Sulfur Loading Pump should be kept below 158°C [317°F] to avoid overloading the pump due to high liquid viscosity. Note that the tank is equipped with a local temperature indicator to allow easy monitoring of this temperature.
Maintaining the steam coil pressure in the tank at
2
5.0 kg/cm (g) or less should ensure that the sulfur does not get too hot. Note that the sulfur experiences a small temperature rise inside the Sulfur Loading Pump due to the pumping energy, so it may be necessary to maintain the tank temperature slightly lower than 158°C [317°F] so that the pumped sulfur does not get too hot.
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SULFUR BLOCK
10.7 Precommissioning Procedures Prior to the initial startup, there are a number of precommissioning activities that are necessary to ensure that the newly constructed plant is ready to be placed in service. The activities outlined below should serve as a guide, but there may be others required as a part of your normal plant procedures.
10.7.1
Preliminary Check-out A.
Check all equipment to ensure that it is properly installed. This will probably require consulting Manufacturer's literature as well as construction drawings.
B.
Check and lubricate all equipment, in accordance with the Manufacturer's recommendations.
C.
Check the rotation of the Degassing Air Blower and Sulfur Feed Pumps: (1)
Operate each Degassing Air Blower for a short period (20 seconds or less) with its discharge valve closed and its blow-off valves open.
(2)
The Sulfur Feed Pumps depend on molten sulfur to lubricate their bearings, and should not be operated dry. Remove the coupling between each pump and its motor while checking the rotation of the motor.
D.
Check the rotation of the Sulfur Loading Pump by "bumping" each pump.
E.
Check all piping and equipment to be sure that all blinds have been removed and that no valves are vented to atmosphere.
F.
Place the Instrument Air System in service to all instruments and check the action of controllers and control valves.
G.
Place the instrument air in service to the bubbler-type level transmitters on the two Sulfur Surge Tanks and the Sulfur Storage Tank.
H.
Once the heating systems have been placed in service (see Section 10.7.2), manually "stroke" each steam-jacketed liquid sulfur valve and confirm that each valve still moves freely.
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SULFUR BLOCK 10.7.2
Commissioning the Heating and Ventilation Systems The heating and ventilation systems for the two Sulfur Surge Tanks and the Sulfur Storage Tank, the heating system for the Sulfur Degassing Reactor, and the heating systems for the other system components can be placed in service at any time prior to the beginning of sulfur degassing. It is advantageous to place them in service prior to startup of an SRU so that any problems can be corrected without impacting the schedule for commissioning the Sulfur Degassing system. To place the heating and ventilation systems in service, proceed as follows: A.
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Commission the steam supply to the Sulfur Storage Tank, A2-FB1550, and place its ventilation system in service as follows: (1)
Confirm that the steam supply valves to the steam coils in the Sulfur Storage Tank are all closed, and that the steam trap stations on each of the coils are all blocked-in.
(2)
Establish steam flow into each of the coils by opening the steam supply valves to each coil.
(3)
Open the upstream block valve of the steam trap on each coil and use the bleeder on each trap to vent air (and any liquids or debris) from each coil. Close the bleeder on each trap once hot condensate begins flowing through the trap.
(4)
Open the test valve on each trap and confirm that each trap is operating properly. Then close the test valve and open the downstream block valve on each trap to place the traps in service to the condensate header.
(5)
Repeat Steps 1 through 4 to commission the heating system on the air sweep vent stack. Open the vent valves on the steam jackets long enough to vent the air from the jackets. In particular, use the vent line on the air sweep vent stack to vent the air from its steam jacket.
(6)
Make sure that the breather vents at each quadrant of the top of the Sulfur Storage Tank are unobstructed and that the air
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SULFUR BLOCK sweep vent stack has begun to draft air into the tank through the breather vents. (7)
Confirm that the block valve in the snuffing steam supply line for the Sulfur Storage Tank is closed, and that the steam trap station for the steam jackets on the snuffing steam shutdown valve and the tank nozzle is blocked-in.
(8)
Open the block valve in the snuffing steam supply line, then open the upstream block valve of the steam trap and use its bleeder to vent air (and any liquids or debris) from the piping and jackets. Close the bleeder on the trap once hot condensate begins flowing through the trap.
(9)
Open the test valve on the trap and confirm that the trap is operating properly. Then close the test valve and open the downstream block valve to place the trap in service to the condensate header.
(10) Press the local push-button to open the automated snuffing steam valve. Leave the valve open long enough to confirm that steam is blowing into the tank, then press the push-button again to close the valve. Visually confirm that the valve has closed and that steam has stopped flowing into the tank. (11) Confirm that the steam supply valves to the jacketed suction and discharge piping on the Sulfur Loading Pump are all closed, and that the steam trap stations on each pump's steam jacket and the steam-jacketed piping are all blocked in. (12) Open all of the vent valves on the steam-jacketed piping. (13) Establish steam flow into the jacketed piping and the steam jackets on each pump by opening the steam supply valves. (14) Allow air (and any liquids or debris) to purge from the vent valves. Close each vent valve as it begins to blow steam. (15) Open the upstream block valve of each steam trap on the jacketed piping and the steam jackets on each pump, and use the bleeder on each trap to drain water (and any other liquids) from the pump and piping. Close the bleeder on each trap once hot condensate begins flowing through the trap.
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SULFUR BLOCK (16) Open the test valve on each trap and confirm that each trap is operating properly. Then close the test valve and open the downstream block valve on each trap to place the traps in service to the condensate header. B.
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Commission the steam supply to the Train 1 Sulfur Surge Tank, A2-FB1530 and place its ventilation system in service as follows: (1)
Confirm that the steam supply valves to the steam coils in the Sulfur Surge Tank are all closed, and that the steam trap stations on each of the coils are all blocked-in.
(2)
Establish steam flow into each of the coils by opening the steam supply valves to each coil.
(3)
Open the upstream block valve of the steam trap on each coil and use the bleeder on each trap to vent air (and any liquids or debris) from each coil. Close the bleeder on each trap once hot condensate begins flowing through the trap.
(4)
Open the test valve on each trap and confirm that each trap is operating properly. Then close the test valve and open the downstream block valve on each trap to place the traps in service to the condensate header.
(5)
Repeat Steps 1 through 4 to commission the heating systems on the air sweep vent stack the Sulfur Surge Tank Vent Ejector, the ejector suction line, and the ejector discharge line. Open all of the vent valves on the steam jackets long enough to vent the air from the jackets. In particular, use the vent line on the air sweep vent stack to vent the air from its steam jacket.
(6)
Make sure that the breather vents at the top of the Sulfur Surge Tank are unobstructed and that the air sweep vent stack has begun to draft air into the tank through the breather vents.
(7)
Confirm that the ejector discharge valve is closed and the ejector suction valve is open. Confirm that the motive steam supply to the ejector is blocked-in. The ejector cannot be placed in service until a TTO is operating.
(8)
Confirm that the block valves in both of the snuffing steam supply lines for the Sulfur Surge Tank are closed, and that the
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SULFUR BLOCK steam trap stations for the steam jackets on both snuffing steam shut-down valves and the tank nozzles are blocked-in. (9)
For each snuffing steam supply line, open the block valve in the supply line, then open the upstream block valve of the steam trap and use its bleeder to vent air (and any liquids or debris) from the piping and jackets. Close the bleeder on the trap once hot condensate begins flowing through the trap.
(10) Open the test valve on each trap and confirm that the traps are operating properly. Then close the test valves and open the downstream block valves to place the traps in service to the condensate header. (11) For each snuffing steam supply line, press the local push-button to open the automated snuffing steam valve. Leave the valve open long enough to confirm that steam is blowing into the tank, then press the push-button again to close the valve. Visually confirm that the valve has closed and that steam has stopped flowing into the tank. C.
Commission the steam supply to the Train 2 Sulfur Surge Tank, A2-FB1540 and place its ventilation system in service in the same manner.
D.
Confirm that the steam supply valve(s) to the jacketed discharge piping on the Train 1 Sulfur Feed Pump, A2-GA1532A/B, are all closed, and that the steam trap stations on each pump are all blocked in.
E.
Open all of the vent valves on the jacketed discharge piping.
F.
Establish steam flow into the jacketed pipe and the pumps by opening the steam supply valve(s).
G.
Allow air (and any liquids) to purge from the vent valves. Close each vent valve as it begins to blow steam.
H.
Open the upstream block valve of the steam trap on each pump and use the bleeder on each trap to drain water (and any other liquids) from each pump. Close the bleeder on each trap once hot condensate begins flowing through the trap.
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SULFUR BLOCK I.
Open the test valve on each trap and confirm that each trap is operating properly. Then close the test valve and open the downstream block valve on each trap to place the traps in service to the LP Condensate header.
J.
Repeat Steps D through I to commission the heating systems on each of the following jacketed equipment items and piping systems. Open all of the vent valves on the steam jackets long enough to vent the air from the jackets, and work from top to bottom to use the steam pressure to empty any liquids from the heating systems. (1)
The Train 1 sulfur spill-back line, and control valve.
(2)
The Train 2 Sulfur Feed Pump, A2-GA1542A/B.
(3)
The Train 2 sulfur spill-back line, and control valve.
(4)
The bubbler tubes for all of the level transmitters in the two Sulfur Surge Tanks and the Sulfur Storage Tank.
(5)
The sulfur drain line, from the Sulfur Degassing Reactor, the strainer, and the associated Degassed Sulfur Drain Seal Assembly, A2-ME1550.
(6)
The jacket on the Sulfur Degassing Reactor, A2-DC1550.
(7)
The degassing air line feeding the Sulfur Degassing Reactor.
(8)
The spent degassing air line from the Sulfur Degassing Reactor.
Confirm that all steam traps are functioning properly before directing your attention away from these heating systems.
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SULFUR BLOCK 10.7.3
Purging the Sulfur Degassing Reactor During normal operation of the Sulfur Degassing Reactor, the spent degassing air from the overhead of the vessel is routed to the Thermal Oxidizer to incinerate the traces of H2S in the air. Before operating the system, the Sulfur Degassing Reactor must be purged to ensure that there are no combustible substances in the vessel that could cause problems in the TTO. This is accomplished by using nitrogen to purge the vessel and its associated piping.
WARNING
UNTIL THE SULFUR DEGASSING REACTOR HAS BEEN PURGED, THERE MAY BE FLAMMABLE GAS MIXTURES PRESENT IN THE VESSEL AND ITS PIPING.
ENSURE THAT ALL IGNITION
SOURCES, INTERNAL AND EXTERNAL TO THE VESSEL, HAVE BEEN REMOVED BEFORE PROCEEDING. A.
Place the Train 1 sulfur feed rate controller in the DCS in "manual" and set its output to 0%.
B.
Verify that the control valve in the associated Train 1 sulfur spill-back line is fully closed.
C.
Place Train 2 sulfur feed rate controller in the DCS in "manual" and set its output to 0%.
D.
Verify that the control valve in the Train 2 sulfur spill-back line is fully closed.
E.
Verify that the discharge valves on the Sulfur Feed Pumps for both SRU trains are closed.
F.
Close the block valve in the spent degassing air line.
G.
Open the block valve upstream of the strainer in the rundown line to the Degassed Sulfur Drain Seal Assembly.
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SULFUR BLOCK H.
Confirm that the steam-out valve on the degassing air line is closed and remove its blind flange.
I.
Use a temporary hose to connect nitrogen to the steam-out valve then open the valve to commence the flow of nitrogen into the Sulfur Degassing Reactor and out the open path through the Degassed Sulfur Drain Seal Assembly.
J.
Allow the nitrogen to continue flowing long enough to reduce the oxygen concentration in the vessel and piping to less than 1%. Use a portable oxygen analyzer to determine the oxygen concentration.
K.
When the oxygen concentration is below 1%, set the output of the Train 1 sulfur feed rate controller to 100%
L.
Verify that the control valve in the Train 1 spill-back line is fully open.
M.
"Force" the PLC to open the Train 1 Sulfur Feed Pump (A2-GA1532A/B) discharge valves.
N.
Close the block valve in the rundown line to the Degassed Sulfur Drain Seal Assembly.
O.
Allow the nitrogen to continue flowing long enough to reduce the oxygen concentration in the piping to less than 1%. Use a portable oxygen analyzer to determine the oxygen concentration.
P.
When the oxygen concentration is below 1%, open the block valve in the spent degassing air line to the Thermal Oxidizer.
Q.
Close the following valves: (1)
Adjust the output of the Train 1 sulfur feed rate controller in the DCS to 0% to close the spill-back valve.
(2)
Remove the "forces" from the PLC and confirm that the automated discharge block valves on the Train 1 Sulfur Feed Pumps close.
R.
Set the output of the Train 2 sulfur feed rate controller to 100%
S.
Verify that the control valve in the Train 2 spill-back line is fully open.
T.
"Force" the PLC to open the Train 2 Sulfur Feed Pump (A2-GA1542A/B) discharge valves.
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SULFUR BLOCK U.
Close the block valve in the spent degassing air line to the Thermal Oxidizer.
V.
Allow the nitrogen to continue flowing long enough to reduce the oxygen concentration in the piping to less than 1%. Use a portable oxygen analyzer to determine the oxygen concentration.
W.
When the oxygen concentration is below 1%, open the block valve in the spent degassing air line to the Thermal Oxidizer.
X.
Close the following valves: (1)
Adjust the output of the Train 2 sulfur feed rate controller in the DCS to 0% to close the spill-back valve.
(2)
Remove the "forces" from the PLC and confirm that the automated discharge block valves on the Train 2 Sulfur Feed Pumps close.
Y.
Allow the nitrogen to continue flowing long enough to reduce the oxygen concentration in the piping to less than 1%. Use a portable oxygen analyzer to determine the oxygen concentration.
Z.
Close the steam-out valve where the nitrogen "jumper" is connected to stop the flow of nitrogen, and disconnect the nitrogen hose. Replace the blind flange on the steam-out valve.
AA. Open the block valve in the rundown line to the Degassed Sulfur Drain Seal Assembly. BB. Close the block valve in the spent degassing air line to the Thermal Oxidizer. The Sulfur Degassing System is now ready for service. Once an SRU has been started up and there has been sufficient sulfur production into a Sulfur Surge Tank to commence operation of a Sulfur Feed Pump, sulfur degassing can begin.
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SULFUR BLOCK
10.8 Startup Procedures This section describes the procedures for the initial startup of the Sulfur Degassing Unit, subsequent startups of the Sulfur Degassing Unit, and operation of the Sulfur Loading system.
10.8.1
Initial Startup of the Sulfur Degassing Unit During the initial startup, the Sulfur Degassing Reactor is filled with liquid sulfur to seal the Degassed Sulfur Drain Seal Assembly in the degassed sulfur outlet line. Subsequent startups will probably not require this step. Once this has been accomplished, the system can be placed into operation. The following steps are based on placing the Train 1 Sulfur Feed Pump in service first. The same procedures can be used for the Train 2 Sulfur Feed Pump.
10.8.1.1
Filling the Sulfur Drain Seal in the Sulfur Outlet Line
CAUTION
THE SHAFT BEARINGS ON THE SULFUR FEED PUMPS ARE LUBRICATED BY SOME OF THE LIQUID SULFUR BEING PUMPED. TO ENSURE AN ADEQUATE SUPPLY OF SULFUR FOR
THE
BEARINGS,
THE
PUMP
MANUFACTURER
TYPICALLY RECOMMENDS MAINTAINING A MINIMUM OF 450 mm OF SULFUR LEVEL ABOVE THE PUMP SUCTION WHEN OPERATING ONE OF THESE PUMPS. CHECK THE SULFUR LEVEL IN THE SULFUR SURGE TANK(S) BEFORE STARTING UP THE SULFUR DEGASSING UNIT. DO NOT PROCEED UNTIL THE LEVEL MEASURES AT LEAST 450 MM ABOVE THE BOTTOM OF THE TANK(S).
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
Issued 30 August 2011
A.
Place the Train 1 sulfur feed rate controller in the DCS in "manual" and set its output to 0%.
B.
Verify that the control valve in the Train 1 spill-back line is closed.
C.
Verify that the block valve in the Sulfur Degassing Reactor overhead line is closed.
D.
Verify that the block valve in the sulfur rundown line, is open.
E.
Verify that the shutdown valves in the discharge lines from the Train 1 Sulfur Feed Pumps are closed.
F.
Start a Sulfur Feed Pump, A2-GA1532A or A2-GA1532B, using its local start/stop control push-button and verify that its discharge valve is open.
G.
The Train 1 sulfur flow meter should begin to indicate that sulfur is flowing into the Sulfur Degassing Reactor.
H.
It will take the Sulfur Feed Pump about 3-5 hours to fill the Sulfur Degassing Reactor up to the top of the weir on the side of its draw pan so that sulfur begins to flow out the degassed sulfur outlet nozzle. Once it does so, it will take a few more minutes for sulfur to fill the Degassed Sulfur Drain Seal Assembly, A2-ME1550, and begin flowing into the Sulfur Storage Tank. Open the view hatch on the Sulfur Drain Seal and confirm that sulfur is now flowing into the tank.
I.
Open the block valve in the Sulfur Degassing Reactor overhead line and lock it open.
Sulfur Degassing
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 10.8.1.2
Placing the Sulfur Degassing Reactor in Operation At this point, liquid sulfur is flowing through the Sulfur Degassing Reactor at the full pumping rate. The sulfur feed rate can now be adjusted to maintain a relatively constant level in the Sulfur Surge Tank, and degassing air flow can be established to bring the system on-line.
WARNING
NEVER START A DEGASSING BLOWER UNLESS EACH OF THE FOLLOWING IS TRUE: 1.
THE SULFUR DEGASSING REACTOR IS FILLED WITH LIQUID SULFUR UP TO ITS NORMAL OPERATING LEVEL AND SULFUR IS RUNNING OUT OF THE SULFUR DRAIN SEAL.
2.
A SULFUR FEED PUMP IS RUNNING AND THE ASSOCIATED SULFUR FLOW METER INDICATES SULFUR IS FLOWING.
3.
THE UPSTREAM SRU(S) IS OPERATING SMOOTHLY IF IT(THEY) IS ON-LINE.
4.
THE THERMAL OXIDIZER IS ON-LINE AND OPERATING SMOOTHLY.
FAILURE TO OBSERVE THESE PRECAUTIONS COULD CAUSE A FIRE AND/OR EXPLOSION IN THE SULFUR DEGASSING REACTOR. A.
Issued 30 August 2011
Confirm that the setpoint of the Train 1 sulfur feed rate flow controller is tracking its current reading, then switch it to "automatic" (not "cascade"). Slowly adjust the setpoint as
Sulfur Degassing
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK necessary so that the spill-back valve opens to regulate the sulfur feed rate to roughly the same value as the current sulfur production rate. Note:
1 metric ton per day = 42 kg/H
B.
Confirm that the block valve in the spent degassing air line is open.
C.
Confirm that both the Degassing Air Blower discharge valves are fully closed.
D.
Start a Degassing Air Blower: (1)
Open the valve in its blow-off line.
(2)
Start the blower push-button.
(3)
Once the blower comes up to speed, slowly "pinch" the valve in the blow-off line until the discharge pressure increases to 0.07-0.15 kg/cm2(g).
(4)
Press the "reset" push-button on the blower to open its discharge valve.
(5)
Slowly close the valve in the blow-off line.
NOTE:
using
its
local
start/stop
control
Do not allow the pressure to exceed 3.5 kg/cm2(g), as this will cause the relief valves on the blower discharge lines to open in order to relieve the excessive pressure.
Issued 30 August 2011
E.
As degassing air begins to flow into the Sulfur Degassing Reactor and aerate the sulfur inside, the discharge pressure on the Sulfur Feed Pump will begin to drop, which will change the sulfur feed rate to the reactor. Be prepared to take control of the sulfur feed rate flow controller in the DCS if necessary to stabilize the sulfur feed rate.
F.
Confirm that the degassing air flow rate indicated in the DCS is 200 Nm3/H or higher.
G.
Place the level controller for the Train 1 Sulfur Surge Tank in service as follows:
Sulfur Degassing
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
H.
(1)
Confirm that the level controller in the DCS is in "automatic".
(2)
Confirm that the remote setpoint the level controller is supplying to the sulfur feed rate controller matches the current local sulfur feed rate setpoint on the controller.
(3)
Switch the sulfur feed rate controller to "cascade" mode so that the setpoint for the sulfur feed rate will now be adjusted automatically by the level controller.
(4)
The setpoint of the level controller will be set at the last reading. Adjust the setpoint to its normal value.
Once SRU Train 2 has been started up and there is sufficient sulfur production into the Train 2 Sulfur Surge Tank, the Train 2 Sulfur Feed Pump can be placed in service as follows:
Issued 30 August 2011
(1)
Place the Train 2 sulfur feed rate controller in the DCS in "manual" and set its output to 0%.
(2)
Verify that the control valve in the Train 2 spill-back line is closed.
(3)
Verify that the shutdown valves in the discharge lines from the Train 2 Sulfur Feed Pumps are closed.
(4)
Start a Sulfur Feed Pump, A2-GA1542A or A2-GA1542B, using its local start/stop control push-button and verify that its discharge valve is open.
(5)
The Train 2 sulfur flow meter should begin to indicate that sulfur is flowing to the Sulfur Degassing Reactor.
(6)
Confirm that the setpoint of the Train 2 sulfur feed rate flow controller is tracking its current reading, then switch it to "automatic" (not "cascade"). Slowly adjust the setpoint as necessary so that the spill-back valve opens to regulate the sulfur feed rate to roughly the same value as the current sulfur production rate.
(7)
Place the level controller for the Train 2 Sulfur Surge Tank in service.
Sulfur Degassing
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK I.
Issued 30 August 2011
The Sulfur Degassing Unit is now in operation. Before directing your attention away from this system make sure that: (1)
The Train 1 sulfur feed rate controller is functioning properly.
(2)
The level in the Train 1 Sulfur Surge Tank is under control.
(3)
The Train 2 sulfur feed rate controller is functioning properly.
(4)
The level in the Train 2 Sulfur Surge Tank is under control.
(5)
The degassing air flow rate is at its normal value or above.
(6)
Sulfur is draining freely from the Degassed Sulfur Drain Seal Assembly.
(7)
All steam heating systems are in service and functioning properly.
(8)
The TTO is operating smoothly.
Sulfur Degassing
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 10.8.2
Normal Startup of the Sulfur Degassing System To place the Sulfur Degassing Unit back in operation, the Sulfur Degassing Reactor must be filled with sulfur and degassing air flow established. Prior to commencing startup: 1.
Check for the completion of all maintenance work (connecting lines, removing blinds, etc.) if such work was performed.
2.
Place all steam heating systems in service. Check all steam traps for proper operation, and use the vent valves to sweep non-condensibles out of the steam spaces.
The following steps are based on placing the Train 1 Sulfur Feed Pump in service first. The same procedures can be used for the Train 2 Sulfur Feed Pump. 10.8.2.1
Filling the Sulfur Degassing Reactor
CAUTION
CHECK THE SULFUR LEVEL IN THE SULFUR SURGE TANK BEFORE STARTING UP THE SULFUR DEGASSING UNIT. DO NOT PROCEED UNTIL THE LEVEL MEASURES AT LEAST 450 mm ABOVE THE BOTTOM OF THE TANK.
Issued 30 August 2011
A.
Place the Train 1 sulfur feed rate controller in the DCS in "manual" and set its output to 0%.
B.
Verify that the control valve in the Train 1 spill-back line is closed.
C.
Verify that the block valve in the Sulfur Degassing Reactor overhead line is open.
D.
Verify that the block valve in the sulfur rundown line is open.
E.
Verify that the shutdown valves in the discharge lines from the Train 1 Sulfur Feed Pumps are closed.
Sulfur Degassing
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
Issued 30 August 2011
F.
Start a Sulfur Feed Pump, A2-GA1532A or A2-GA153/B, using its local start/stop control push-button and verify that its discharge valve is open.
G.
The Train 1 sulfur flow meter should begin to indicate that sulfur is flowing into the Sulfur Degassing Reactor.
H.
It will take the Sulfur Feed Pump about 3-5 hours to fill the Sulfur Degassing Reactor up to the top of the weir on the side of its draw pan so that sulfur begins to flow out the degassed sulfur outlet nozzle. Once it does so, it will take a few more minutes for sulfur to fill the Degassed Sulfur Drain Seal Assembly, A2-ME1550, and begin flowing into the Sulfur Storage Tank.
I.
Open the view hatch on the Degassed Sulfur Drain Seal Assembly and observe when sulfur begins to flow into the tank. When sulfur begins to flow out of the Degassed Sulfur Drain Seal Assembly, proceed to the next section to complete the startup of the Sulfur Degassing Unit.
Sulfur Degassing
Page 10-47
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 10.8.2.2
Placing the Sulfur Degassing Reactor in Operation
WARNING
NEVER START A DEGASSING BLOWER UNLESS EACH OF THE FOLLOWING IS TRUE: 1.
THE SULFUR DEGASSING REACTOR IS FILLED WITH LIQUID SULFUR UP TO ITS NORMAL OPERATING LEVEL AND SULFUR IS RUNNING OUT OF THE SULFUR DRAIN SEAL.
2.
A SULFUR FEED PUMP IS RUNNING AND THE ASSOCIATED SULFUR FLOW METER INDICATES SULFUR IS FLOWING.
3.
THE UPSTREAM SRU(S) IS OPERATING SMOOTHLY IF IT(THEY) IS ON-LINE.
4.
THE THERMAL OXIDIZER IS ON-LINE AND OPERATING SMOOTHLY.
FAILURE TO OBSERVE THESE PRECAUTIONS COULD CAUSE A FIRE AND/OR EXPLOSION IN THE SULFUR DEGASSING REACTOR. A.
Confirm that the setpoint of the Train 1 sulfur feed rate flow controller is tracking its current reading, then switch it to "automatic" (not "cascade"). Slowly adjust the setpoint as necessary so that the spill-back valve opens to regulate the sulfur feed rate to roughly the same value as the current sulfur production rate. Note:
Issued 30 August 2011
1 metric ton per day = 42 kg/H
Sulfur Degassing
Page 10-48
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK B.
Confirm that both the Degassing Air Blower discharge valves are fully closed.
C.
Start a Degassing Air Blower: (1)
Open the valve in its blow-off line.
(2)
Start the blower push-button.
(3)
Once the blower comes up to speed, slowly "pinch" the valve in the blow-off line until the discharge pressure increases to 0.07-0.15 kg/cm2(g).
(4)
Press the "reset" push-button on the blower to open its discharge valve.
(5)
Slowly close the valve in the blow-off line.
NOTE:
using
its
local
start/stop
control
Do not allow the pressure to exceed 3.5 kg/cm2(g), as this will cause the relief valves on the blower discharge lines to open in order to relieve the excessive pressure.
Issued 30 August 2011
D.
Be prepared to take control of the sulfur feed rate flow controller in the DCS if necessary to stabilize the sulfur feed rate.
E.
Confirm that the degassing air flow rate indicated in the DCS is 200 Nm3/H or higher.
F.
Place the level controller for the Train 1 Sulfur Surge Tank in service as follows: (1)
Confirm that the level controller in the DCS is in "automatic".
(2)
Confirm that the remote setpoint the level controller is supplying to the sulfur feed rate controller matches the current local sulfur feed rate setpoint on the controller.
(3)
Switch the sulfur feed rate controller to "cascade" mode so that the setpoint for the sulfur feed rate will now be adjusted automatically by the level controller.
(4)
The setpoint of the level controller will be set at the last reading. Adjust the setpoint to its normal value. Sulfur Degassing
Page 10-49
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK G.
Once SRU Train 2 has been started up and there is sufficient sulfur production into the Train 2 Sulfur Surge Tank, the Train 2 Sulfur Feed Pump can be placed in service as follows:
H.
Issued 30 August 2011
(1)
Place the Train 2 sulfur feed rate controller in the DCS in "manual" and set its output to 0%.
(2)
Verify that the control valve in the Train 2 spill-back line is closed.
(3)
Verify that the shutdown valves in the discharge lines from the Train 2 Sulfur Feed Pumps are closed.
(4)
Start a Sulfur Feed Pump, A2-GA1542A or A2-GA1542B, using its local start/stop control push-button and verify that its discharge valve is open.
(5)
The Train 2 sulfur flow meter should begin to indicate that sulfur is flowing to the Sulfur Degassing Reactor.
(6)
Confirm that the setpoint of the Train 2 sulfur feed rate flow controller is tracking its current reading, then switch it to "automatic" (not "cascade"). Slowly adjust the setpoint as necessary so that the spill-back valve opens to regulate the sulfur feed rate to roughly the same value as the current sulfur production rate.
(7)
Place the level controller for the Train 2 Sulfur Surge Tank in service.
The Sulfur Degassing Unit is now in operation. Before directing your attention away from this system make sure that: (1)
The Train 1 sulfur feed rate controller is functioning properly.
(2)
The level in the Train 1 Sulfur Surge Tank is under control.
(3)
The Train 2 sulfur feed rate controller is functioning properly.
(4)
The level in the Train 2 Sulfur Surge Tank is under control.
(5)
The degassing air flow rate is at its normal value or above.
Sulfur Degassing
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
10.8.3
(6)
Sulfur is draining freely from the Degassed Sulfur Drain Seal Assembly.
(7)
All steam heating systems are in service and functioning properly.
(8)
The TTO is operating smoothly.
Initial Sulfur Loading Operation Once a level of liquid sulfur has been established in the Sulfur Storage Tank, loading of sulfur trucks can commence. A.
Confirm that the steam-jacket heating systems are operating properly on each Sulfur Loading Pump, their seals, their suction piping and valves, their discharge piping and valves, and the sulfur loading arm at each loading spot.
B.
Confirm that there is sufficient sulfur in the Sulfur Storage Tank to load a truck.
C.
Select a Sulfur Loading Pump for service by turning the selector switch to that pump.
D.
Position a truck under a sulfur loading arm, and connect the grounding cable to it.
E.
Confirm that the applicable grounding status light is illuminated on the loading control panel, then lower the loading arm into the tank hatch.
F.
Start the selected Sulfur Loading Pump by pressing the applicable start/stop push-button mounted at the sulfur loading platform.
G.
If sulfur does not begin flowing into the truck within 60 seconds, stop the Sulfur Loading Pump by pressing the start/stop push-button. The following items should be investigated to determine why sulfur is not being pumped:
Issued 30 August 2011
(1)
Confirm that selector switch is set to the correct Sulfur Loading Pump.
(2)
Confirm that the "stop" switch for that pump, either is in the "run" position.
Sulfur Degassing
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK (3)
Confirm that the steam-jacketed heating systems, steam traps, etc. on the pumps, piping, and loading arms are functioning properly.
(4)
Confirm that there is adequate level in the tank.
Once the problem has been corrected, station an observer by the Sulfur Loading Pump, return to Step F to commence loading again, and have the observer confirm that the pump suction valve opens, the pump starts, and then the discharge valve opens. H.
Once the sulfur truck is full, stop the Sulfur Loading Pump by pressing the start/stop push-button at the loading spot.
I.
Confirm that the Sulfur Loading Pump has stopped and its suction and discharge valves are now closed.
CAUTION
ALWAYS CONFIRM THAT THE BLOCK VALVE AT THE LOADING SPOT CLOSES AFTER STOPPING THE SULFUR LOADING PUMP. THE SULFUR LOADING ARMS ARE LOWER THAN THE TOP OF THE SULFUR STORAGE TANK, SO THE TANK CAN PARTIALLY EMPTY THROUGH THE LOADING LINE, EVEN WHEN A PUMP IS NOT RUNNING, IF THE LEVEL IN THE TANK IS HIGH ENOUGH AND THE BLOCK VALVE REMAINS OPEN.
Issued 30 August 2011
Sulfur Degassing
Page 10-52
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 10.8.4
Normal Sulfur Loading Operation A.
Position a truck under a sulfur loading arm, and connect the grounding cable to it.
B.
Confirm that the applicable grounding status light is illuminated on the loading control panel, then lower the loading arm into the tank hatch.
C.
Commence sulfur loading by pressing the applicable start/stop push-button mounted at the sulfur loading platform.
D.
If sulfur does not begin flowing into the truck within 60 seconds, stop the Sulfur Loading Pump by pressing the start/stop push-button. Investigate the items listed above to determine why sulfur is not being pumped.
E.
Once the sulfur truck is full, stop the sulfur loading operation by pressing the start/stop push-button at the loading spot.
CAUTION ALWAYS CONFIRM THAT THE BLOCK VALVE AT THE LOADING SPOT CLOSES WHEN LOADING IS STOPPED.
THIS WILL
PREVENT THE SULFUR STORAGE TANK FROM PARTIALLY EMPTYING ITSELF DUE TO GRAVITY-FLOW THROUGH THE LOADING LINE IF THE LEVEL IN THE TANK IS HIGH.
Issued 30 August 2011
Sulfur Degassing
Page 10-53
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
10.9 Shutdown Procedures The procedures to be used in performing a planned shutdown of the Sulfur Degassing Unit will vary depending on the extent and type of work to be performed in and around the Sulfur Degassing Reactor during the downtime period. If there are no plans for entering the Sulfur Degassing Reactor, no special procedures are required in performing the shutdown. However, if you plan to enter any vessels for inspection or maintenance, the procedure for Planned Shutdown with Entry should be followed to accomplish a satisfactory shutdown and minimize the time required for performance of the desired maintenance work. Typical shutdown procedures are outlined and discussed in the sections that follow for the more common cases. Your existing company procedures and common sense operational judgment should be used to modify these procedures as needed to serve the purpose of any given planned shutdown situation.
10.9.1
Planned Shutdown - No Reactor Entry If there are no plans to enter the Sulfur Degassing Reactor during the shutdown, the Sulfur Degassing Reactor can remain full of liquid. This will allow placing the Sulfur Degassing Unit back on-line quicker, since there will be no delay while filling the vessel with sulfur. A.
Stop the Sulfur Feed Pump, A2-GA1532A/B using its local start/stop control push-button. Stop the Sulfur Feed Pump, A2-GA1542A/B using its local start/stop control push-button. This should activate the SDU ESD system to shut down the Degassing Air Blower.
B.
Issued 30 August 2011
Place the Train 1 sulfur feed rate controller in the DCS, in "manual" and set its output to 0% to close the control valve in the spill-back line.
Sulfur Degassing
Page 10-54
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK Place the Train 2 sulfur feed rate controller in the DCS, in "manual" and set its output to 0% to close the control valve in the spill-back line. This will prevent sulfur from draining out of the Sulfur Degassing Reactor. C.
D.
Visually confirm that: (1)
All Sulfur Feed Pumps are stopped, and that their discharge valves are closed.
(2)
Both Degassing Air Blowers are stopped and their discharge valves are closed.
(3)
The control valves in both spill-back lines are closed.
Confirm that all steam heating services are still functioning and the steam traps are operating properly.
The Sulfur Degassing Unit can remain in this condition indefinitely. Periodically confirm that the steam heating services are functioning properly so that solid sulfur cannot form anywhere in the system.
10.9.2
Planned Shutdown for Reactor Entry Use the following steps to shut down the Sulfur Degassing Unit for maintenance or inspection. A.
Stop the Sulfur Feed Pump, A2-GA1532A/B using its local start/stop control push-button. Stop the Sulfur Feed Pump, A2-GA1542A/B using its local start/stop control push-button. This should activate the SDU ESD system to shut down the Degassing Air Blower.
B.
Issued 30 August 2011
Visually confirm that: (1)
All Sulfur Feed Pumps are stopped, and that their discharge valves are closed.
(2)
Both Degassing Air Blowers are stopped and their discharge valves are closed.
Sulfur Degassing
Page 10-55
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK C.
Confirm that the block valve in the spent degassing air line is open to the TTO. This will prevent creating a vacuum in the Sulfur Degassing Reactor as the sulfur is drained back into the Sulfur Surge Tank(s).
Note:
The sulfur from the Sulfur Degassing Reactor may be drained into the surge tank for either SRU. Unless noted otherwise, the following procedure applies to both Train 1 and Train 2. D.
Place the sulfur feed rate controller in the DCS, in "manual" and set its output to 100%. This will fully open the control valve in the spill-back line and allow all of the liquid sulfur to empty from the Sulfur Degassing Reactor back into the Sulfur Surge Tank.
E.
Once the Sulfur Degassing Reactor is empty, set the output from the flow controller to 0%. Confirm that the control valve in the spill-back line is fully closed.
F.
Remove the blind flange then open the steam-out valve on the degassing air line and use LP steam to purge the gases in the Sulfur Degassing Reactor out to the TTO.
G.
Discontinue steam-out of the vessel and re-install the blind flange.
H.
Isolate the Sulfur Degassing Reactor from all potential contaminating gases using slip blinds or by disconnecting the piping. In particular, isolate the Sulfur Degassing Reactor from the TTO using slip-blinds, etc.
I.
Close the block valve in the sulfur drain line to isolate the Sulfur Degassing Reactor from the drain trap and the Sulfur Storage Tank. Once the Sulfur Degassing Reactor is isolated, it can be opened for entry. Refer to the "General Safety" section of these guidelines for procedures to be followed when performing maintenance work on this plant.
Issued 30 August 2011
Sulfur Degassing
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 10.9.3
Shutdown for Tank Entry If the Sulfur Storage Tank is to be entered, it should be isolated, emptied, purged, and ventilated using normal procedures. This should include at least the following: A.
Close the block valves in the sulfur inlet lines to the Sulfur Storage Tank and install slip blinds at the tank flanges.
B.
Use the Sulfur Loading Pump to empty the Sulfur Storage Tank as completely as possible. Since the pump suction lines inside the tank extend to near the bottoms of recessed sumps in the tank bottom, it should be possible to remove all of the molten sulfur covering the tank floor before the pump loses suction.
C.
Briefly operate the other Sulfur Loading Pump until it loses suction to remove as much sulfur as possible from the other suction sump.
D.
Install slip blinds in the pump suction lines at the tank flanges.
E.
Close the block valves in the steam and condensate lines for the steam coils inside the tank, then de-pressure the coils.
F.
Remove the covers from the roof and shell manholes, then use fans or other means to sweep air through the tank and displace all of the tank vapors.
G.
If desired, the steam supply to the steam jacket on the air sweep vent stack can be left in service so that the stack will help ventilate the tank.
H.
Monitor the air inside the tank and continue to sweep the tank with air until no H2S is detected.
I.
Once these steps have been completed, entry into the tank following your company's policies for "confined space entry" should be possible.
Issued 30 August 2011
Sulfur Degassing
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
WARNING
THE SULFUR STORAGE TANK ALWAYS HAS THE POTENTIAL TO CONTAIN H2S AND/OR SO2.
ALL SAFETY PRECAUTIONS
OUTLINED IN THE GENERAL SAFETY SECTION OF THIS GUIDELINES REGARDING WORKING SAFELY WHEN H2S AND/OR SO2 MAY BE PRESENT SHOULD BE FOLLOWED. MOLTEN SULFUR MAY ALSO BE PRESENT INSIDE THE TANK, INCLUDING UNDERNEATH WHAT OTHERWISE APPEARS TO BE SOLID SULFUR. MOLTEN SULFUR CAN CAUSE SEVERE BURNS, SO ALWAYS USE APPROPRIATE PERSONAL PROTECTION EQUIPMENT.
Issued 30 August 2011
Sulfur Degassing
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
Table of Contents 11.
TAILGAS CLEANUP .............................................................................................. 11-1
11.1 PURPOSE OF SYSTEM ..................................................................................... 11-1 11.2 SAFETY ............................................................................................................... 11-2 11.3 PROCESS DESCRIPTION.................................................................................. 11-3 11.3.1 General ......................................................................................................... 11-3 11.3.2 Tailgas Hydrogenation/Hydrolysis ................................................................ 11-3 11.3.3 Process Gas Cooling .................................................................................... 11-4 11.3.4 Gas Contacting ............................................................................................. 11-5 11.3.5 Solvent Regeneration Section ...................................................................... 11-6 11.3.6 Steam Production/Consumption ................................................................... 11-7 11.4 EQUIPMENT DESCRIPTION .............................................................................. 11-8 11.4.1 TGCU Quench Column, A2-DA1560 ............................................................ 11-8 11.4.2 TGCU Quench Column Packing, A2-DB1560 .............................................. 11-8 11.4.3 TGCU Contactor, A2-DA1561 ...................................................................... 11-8 11.4.4 TGCU Contactor Packing & Internals, A2-DB1561 ...................................... 11-8 11.4.5 TGCU Stripper, A2-DA1562 ......................................................................... 11-9 11.4.6 TGCU Stripper Trays, A2-DB1562 ............................................................... 11-9 11.4.7 TGCU Reactor, A2-DC1560 ....................................................................... 11-10 11.4.8 TGCU Stripper Reflux Accumulator, A2-FA1560 ....................................... 11-10 11.4.9 Catalyst for TGCU Reactor, A2-MC1560 ................................................... 11-10 11.4.10 TGCU Stripper Reboiler Condensate Pot, A2-FA1562 ........................... 11-10 11.4.11 TGCU Reactor Feed Heater, A2-EA1560 ............................................... 11-11 11.4.12 TGCU Waste Heat Reclaimer, A2-EA1561 ............................................ 11-11 11.4.13 TGCU Quench Water Trim Cooler, A2-EA1562A/B ................................ 11-11 11.4.14 TGCU Lean/Rich Exchanger, A2-EA1564 .............................................. 11-11 11.4.15 TGCU Stripper Reboiler, A2-EA1565 ..................................................... 11-12 11.4.16 TGCU Lean Amine Trim Cooler, A2-EA1563 ......................................... 11-12 11.4.17 TGCU Quench Water Cooler, A2-EC1560 ............................................. 11-12 11.4.18 TGCU Stripper Reflux Condenser, A2-EC1562 ...................................... 11-12 11.4.19 TGCU Lean Amine Cooler, A2-EC1561 ................................................. 11-12 11.4.20 TGCU Quench Water Pump, A2-GA1560A/B......................................... 11-13 11.4.21 TGCU Rich Amine Pump, A2-GA1561A/B ............................................. 11-14 11.4.22 TGCU Stripper Reflux Pump, A2-GA1563A/B ........................................ 11-14 11.4.23 TGCU Lean Amine Pump, A2-GA1562A/B ............................................. 11-14 11.4.24 TGCU Start-Up Blower, A2-GB1560 ....................................................... 11-14 11.4.25 Refractory for TGCU Reactor, A2-MR1560 ............................................ 11-15 11.4.26 TGCU Reactor Feed Mixer, A2-ME1560 ................................................ 11-16
Issued 30 August 2011
Tailgas Cleanup
Page 11-i
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 11.4.27 TGCU Quench Water Filter, A2-FD1560A/B .......................................... 11-16 11.4.28 TGCU Rich Amine Filter, A2-FD1562A/B ............................................... 11-16 11.4.29 TGCU Lean Amine Filter, A2-FD1563 .................................................... 11-17 11.4.30 TGCU Amine Carbon Filter, A2-FD1564 ................................................ 11-17 11.4.31 TGCU Amine After-Filter, A2-FD1565 .................................................... 11-17 11.4.32 pH Meter Sample Filter, A2-FD1561A/B ................................................. 11-17 11.5 INSTRUMENTATION AND CONTROL SYSTEMS ........................................... 11-18 11.5.1 TGCU Reactor Feed Control Loops ........................................................... 11-18 11.5.1.1 Reactor Feed Temperature Control .................................................... 11-18 11.5.1.2 Hydrogen Concentration Control ......................................................... 11-19 11.5.1.3 Controls for Startup and Shutdown ..................................................... 11-20 11.5.2 Hydrogen and Hydrogen Sulfide Analyzer, A2-AE15858/A2-AE15859 ...... 11-23 11.5.3 Boiler Low-Low Level S/D Transmitter Testing .......................................... 11-24 11.5.4 Tailgas Switching Valve Controls ............................................................... 11-26 11.5.4.1 Repositioning the Tailgas Valves Following a TGCU ESD ................. 11-26 11.5.4.2 Introducing SRU Tailgas into the TGCU — Scenario 1 ....................... 11-27 11.5.4.3 Introducing SRU Tailgas into the TGCU — Scenario 2 ....................... 11-29 11.5.5 TGCU Shutdown System ........................................................................... 11-33 11.5.5.1 Causes ................................................................................................ 11-33 11.5.5.2 Effects ................................................................................................. 11-36 11.5.5.3 Non-ESD Shutdowns .......................................................................... 11-37 11.6 PROCESS PRINCIPLES AND OPERATING TECHNIQUES ........................... 11-39 11.6.1 Equipment Damage .................................................................................... 11-39 11.6.2 Catalyst Fouling .......................................................................................... 11-40 11.6.3 TGCU Reactor Operation ........................................................................... 11-41 11.6.4 TGCU Catalyst ........................................................................................... 11-43 11.6.5 TGCU Start-Up Blower Operation .............................................................. 11-44 11.6.6 TGCU Quench Column Operation.............................................................. 11-45 11.6.7 TGCU Contactor Operation ........................................................................ 11-48 11.6.8 TGCU Stripper Operation ........................................................................... 11-52 11.6.9 TGCU Amine Water Balance...................................................................... 11-55 11.6.10 TGCU Amine Loss .................................................................................. 11-59 11.6.11 Operation at Low Flow Rates.................................................................. 11-60 11.6.12 Pressure Drop Surveys ........................................................................... 11-61 11.6.13 Boiler Water Treatment ........................................................................... 11-63 11.7 PRECOMMISSIONING PROCEDURES ........................................................... 11-64 11.7.1 Preliminary Check-out ................................................................................ 11-64 11.7.2 Shutdown System Check-out ..................................................................... 11-65 11.7.3 Commissioning Nitrogen and Utility Air to the Process .............................. 11-66 11.7.4 Commissioning Hydrogen to the Process .................................................. 11-72
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SULFUR BLOCK 11.7.5 Leak Testing the Process Piping and Equipment ....................................... 11-75 11.7.6 Washing the Quench Water System .......................................................... 11-79 11.7.6.1 Water Flush ......................................................................................... 11-79 11.7.6.2 Acid Wash ........................................................................................... 11-82 11.7.6.3 Alkaline Wash...................................................................................... 11-82 11.7.6.4 Initial Water Fill .................................................................................... 11-84 11.7.7 Washing the Amine System ....................................................................... 11-85 11.7.7.1 Water Flush ......................................................................................... 11-86 11.7.7.2 Acid Wash ........................................................................................... 11-89 11.7.7.3 Weak Amine Wash .............................................................................. 11-91 11.7.7.4 Initial Solvent Fill ................................................................................. 11-93 11.7.8 Purging the Low Pressure TGCU Columns ................................................ 11-97 11.7.8.1 Establishing Nitrogen Flow .................................................................. 11-97 11.7.8.2 Purging the TGCU Start-Up Blower .................................................... 11-99 11.7.8.3 Purging the Columns ......................................................................... 11-100 11.8 STARTUP PROCEDURES.............................................................................. 11-102 11.8.1 Initial Startup of the TGCU ....................................................................... 11-102 11.8.1.1 Initial Preparations............................................................................. 11-102 11.8.1.2 Establishing Nitrogen Flow ................................................................ 11-103 11.8.1.3 Establishing Re-circulation Flow ....................................................... 11-104 11.8.2 Pre-Sulfiding the TGCU Catalyst .............................................................. 11-107 11.8.2.1 Establishing Reducing Gas Flow....................................................... 11-108 11.8.2.2 Pre-Sulfiding the Catalyst .................................................................. 11-111 11.8.3 Routing SRU Tailgas to the TGCU ........................................................... 11-115 11.8.3.1 Introducing SRU Tailgas into the TGCU — Scenario 1 ..................... 11-116 11.8.3.2 Introducing SRU Tailgas into the TGCU — Scenario 2 ..................... 11-119 11.8.4 Quench Water and Amine Systems ......................................................... 11-122 11.8.5 Process Gas Flow to the TGCU Columns ................................................ 11-124 11.8.6 Normal Startup of the TGCU .................................................................... 11-128 11.8.6.1 Initial Preparations............................................................................. 11-128 11.8.6.2 Purging the Low Pressure TGCU Columns....................................... 11-130 11.8.6.3 Establishing Nitrogen Flow ................................................................ 11-130 11.8.6.4 Establishing Re-circulation Flow ....................................................... 11-131 11.8.6.5 Establishing Reducing Gas Flow....................................................... 11-133 11.8.6.6 Routing SRU Tailgas to the TGCU.................................................... 11-134 11.8.6.7 Quench Water and Amine Systems .................................................. 11-138 11.8.6.8 Process Gas Flow to the TGCU Columns ......................................... 11-140 11.9 SHUTDOWN PROCEDURES ......................................................................... 11-144 11.9.1 Planned Shutdown - No Reactor Entry..................................................... 11-145 11.9.2 Planned Shutdown for Reactor Entry ....................................................... 11-151
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SULFUR BLOCK 11.9.3 Shutting Down When Boiler Tubes Are Leaking ...................................... 11-158 11.9.4 Special Precaution During Shutdowns ..................................................... 11-159 11.9.5 Emergency Shutdown .............................................................................. 11-163 11.9.6 Effects of Shutdowns and Outages in Other Systems.............................. 11-164 11.9.6.1 Amine Regeneration Unit Outages.................................................... 11-164 11.9.6.2 Sour Water Stripper Outages ............................................................ 11-164 11.9.6.3 Sulfur Recovery Unit ESD System .................................................... 11-164 11.9.6.4 Thermal Oxidizer ESD System.......................................................... 11-165 11.9.6.5 Steam System Outage ...................................................................... 11-166 11.10 ANALYTICAL PROCEDURES ..................................................................... 11-167 11.10.1 General Procedures for Analyzing TGCU Solvent, ............................... 11-167 11.10.2 Determination of Amine Concentration in TGCU Solvent ..................... 11-171 11.10.3 Determination of Total Acid Gas Loading in TGCU Solvent ................. 11-173 11.10.4 Determination of H2S and CO2 Loading in TGCU Solvent .................... 11-175 11.10.5 Determination of Foaming Tendency of TGCU Solvent ........................ 11-179 11.10.6 H2S Conc. in TGCU Contactor Ovhd by the Tutweiler Method ............. 11-181 11.10.7 H2S Conc. in TGCU Contactor Ovhd Using Gas Detector Tubes ......... 11-182 11.10.7.1 Operating Principles.......................................................................... 11-182 11.10.7.2 Sampling the TGCU Contactor Overhead Gas ................................. 11-183 11.10.7.3 Calculations ...................................................................................... 11-184 11.10.8 Monitoring the Performance Level of TGCU Catalyst ........................... 11-185
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SULFUR BLOCK
11.
TAILGAS CLEANUP 11.1 Purpose of System The purpose of the Tailgas Cleanup system is to remove objectionable components from the sulfur plant tailgas, thereby allowing the treated effluent to be incinerated and safely discharged to the atmosphere. The Shell Claus Off-gas Treating (SCOT) process licensed by Shell Global Solutions (US) Inc. processes the tailgas from the SRU, converting sulfur compounds present in the tailgas back into H2S. The H2S is then absorbed in a selective solvent, stripped from the solvent, and recycled back to the SRU, allowing an overall sulfur recovery in excess of 99.9%. Treated vent gas from the Tailgas Cleanup Unit (TGCU) is routed to the Tailgas Thermal Oxidation system and afterwards dispersed to the atmosphere. Due to the sulfur removal by the TGCU process, the incinerated effluent gas will normally contain less than 200 PPMV of SO2 on a dry, 0% oxygen basis.
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SULFUR BLOCK
11.2 Safety
WARNING
ALL PIPING AND VESSELS INCLUDED IN THIS UNIT EITHER CONTAIN OR HAVE THE POTENTIAL FOR CONTAINING HAZARDOUS GASES THAT MAY CAUSE SERIOUS INJURY OR DEATH. THE TWO GASES THAT ARE MOST COMMON AND HAZARDOUS IN A TOXIC WAY ARE HYDROGEN SULFIDE AND SULFUR DIOXIDE. CLOSE ATTENTION SHOULD BE PAID TO THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES AS TO THE NATURE AND ABILITY OF THESE GASES TO CONTAMINATE OTHER ELEMENTS IN THIS UNIT. AN EMPLOYEE'S KNOWLEDGE OF THE HAZARDOUS CHEMICALS AND COMPOUNDS WITH WHICH HE WILL BE WORKING IS ONE OF THE MOST BASIC PREREQUISITES FOR HIS OWN SAFETY, THE SAFETY OF OTHERS, AND THE PROTECTION OF EQUIPMENT. ALL EMPLOYEES SHOULD REVIEW THE "GENERAL SAFETY" SECTION OCCASIONALLY TO REFRESH THEIR MEMORIES. NEW EMPLOYEES SHOULD STUDY IT UNTIL THE INFORMATION IS THOROUGHLY UNDERSTOOD. PEOPLE WHO HAVE NOT BEEN PROPERLY TRAINED SHOULD NOT BE ALLOWED TO OPERATE OR WORK IN AND AROUND THIS PLANT.
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SULFUR BLOCK
11.3 Process Description 11.3.1
General The Systems Diagram, Material Balance and Process Flow Diagrams, Dwg. Nos. 507000-7000-01, and 507000-7000-10 through -12, are contained in the "Process Flow Diagrams" Section of the Basic Engineering Package. Please refer to these drawings to follow this description of the process. The Tailgas Cleanup Unit (TGCU) receives tailgas from the two Sulfur Recovery Units and uses the Shell Claus Off-gas Treating (SCOT) process licensed by Shell Global Solutions (US) Inc. for sulfur removal. The TGCU Unit has been designed to process the 7,655 Nm3/H of sulfur plant tailgas that results when each SRU receives a total fresh acid gas feed containing 34.6 MT/D of sulfur. The TGCU process reduces all of the sulfur compounds in the sulfur plant tailgas to H2S, then uses selective amine absorption to recover H2S from the tailgas while allowing most of the CO2 to "slip" by. The H2S and CO2 removed by the amine are stripped from the amine and recycled to the two SRUs, allowing an overall sulfur recovery in excess of 99.9 wt. %. Less than 220 PPMV of sulfur (wet basis, expressed as H2S) remains in the treated effluent flowing to the Tailgas Thermal Oxidation Unit. This sulfur content is low enough to keep the SO2 content of the incinerated effluent below 200 PPMV (on a dry, 0% oxygen basis) when the H2S and sulfur in the spent degassing air from the Sulfur Degassing Unit and the sweep air from the Sulfur Surge Tanks are included, due to the dilution effect of the thermal incineration process.
11.3.2
Tailgas Hydrogenation/Hydrolysis The tailgas stream from the fourth pass of the Sulfur Condenser in each SRU is combined and heated using HP steam in the TGCU Reactor Feed Heater, A2-EA1560. The heated gas is then mixed with hydrogen-rich reducing gas by the TGCU Reactor Feed Mixer, A2-ME1560, (a static mixer) before the mixture flows to the TGCU Reactor, A2-DC1560, at 240°C [464°F]. As the gas flows through the bed of Criterion 234 cobalt-molybdenum catalyst, the reducing atmosphere hydrogenates or hydrolyzes most of the sulfur compounds to H2S: (1)
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SO2 + 3 H2
H2S + 2 H2O
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SULFUR BLOCK (2)
S + H2
H2S
(3)
COS + H2O
H2S + CO2
(4)
CS2 + 2 H2O
2 H2S + CO2
Carbon monoxide in the tailgas also reacts with the water vapor in the gas to form hydrogen, the classic "water gas shift" reaction: (5)
CO + H2O
H2 + CO2
These reactions are all exothermic, causing the gas temperature to increase to 291°C [556°F] at the outlet of the TGCU Reactor.
11.3.3
Process Gas Cooling Before the amine solvent can be used to remove the H2S from the process gas, the gas must be cooled to an acceptable contact temperature. The first stage of cooling occurs in the TGCU Waste Heat Reclaimer, A2-EA1561, where the effluent from the TGCU Reactor is cooled to 166°C [331°F] by generating LP steam. During the course of starting up the TGCU, the equipment must be brought up to operating temperature before the sulfur plant tailgas is introduced. The TGCU Start-Up Blower, A2-GB1560, accomplishes this by re-circulating gas from the outlet of the TGCU Waste Heat Reclaimer back to the TGCU Reactor Feed Heater. This gas is circulated through the system and heated with the TGCU Reactor Feed Heater until the sulfur plant tailgas is ready to be routed to the TGCU, at which time the TGCU Start-Up Blower can be shut down. The partially cooled gas from the TGCU Waste Heat Reclaimer enters the bottom of the TGCU Quench Column, A2-DA1560, for the second stage of cooling. As the gas passes upward through the packed bed in this tower, it is further cooled by direct contact with a circulating stream of quench water. As the gas is cooled, most of the water vapor produced by the upstream reactions (Claus, combustion, and hydrogenation) is condensed and removed from the gas stream. In addition to cooling the gas, direct contact with the quench water serves to absorb trace quantities of SO2 that may "break through" the TGCU Reactor periodically. Since SO2 will react with amines to form heat-stable salts, the "washing" action of the quench water helps minimize degradation of the MDEA solvent.
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SULFUR BLOCK The cooled gas stream leaves the top of the TGCU Quench Column at 39°C [102°F] and flows to the TGCU Contactor, A2-DA1561, while the quench water exits the bottom of the tower at 67°C [153°F]. The TGCU Quench Water Pump, A2-GA1560A/B, circulates the water stream to the TGCU Quench Water Cooler, A2-EC1560, and the TGCU Quench Water Trim Cooler, A2-EA1562A/B, to reject the heat removed in the TGCU Quench Column. This cools the quench water to 38°C [104°F] before it is returned to the top of the tower. A sidestream of the quench water flows through the TGCU Quench Water Filter, A2-FD1560A/B, to remove solids from the quench water system. A portion of the filtrate is routed to the Sour Water Stripping Unit to balance the water condensed from the gas in the TGCU Quench Column, on level control from the tower. The remainder of the filtrate returns to the suction of the circulating pump.
11.3.4
Gas Contacting The cooled gas from the TGCU Quench Column enters the bottom of the TGCU Contactor at 39°C [102°F] and 0.06 kg/cm2(g) [0.9 PSIG]. As the gas flows upward through the packed bed in this tower, it is contacted with an aqueous solution of methyldiethanolamine, MDEA. The MDEA solvent (45 wt% MDEA) absorbs the H2S in the gas stream to reduce the total sulfur content below 220 PPMV on a wet basis while allowing the majority of the CO2 to "slip" overhead. The treated gas exits the top of the TGCU Contactor at 39°C [102°F] and flows to the Tailgas Thermal Oxidation Unit. The reactions between the acidic gases and the basic amine solution can be represented by: (6) H2S + CH3(CH2OHCH2)2N
CH3(CH2OHCH2)2NH+ + HS–
(7) CO2 + CH3(CH2OHCH2)2N + H2O
CH3(CH2OHCH2)2NH+ + HCO3–
The selectivity of the solvent for H2S over CO2 is important since the absorbed gases are recycled to the SRUs. Minimizing CO2 pickup reduces the amount of gas recycling to the sulfur plants, and allows the equipment in the Sulfur Recovery and Tailgas Cleanup Units to be smaller. The selectivity of tertiary amines like MDEA for H2S is a result of the indirect reaction that must occur between the amine and CO2. Unlike
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SULFUR BLOCK primary amines (such as MEA) and secondary amines (such as DEA), tertiary amines do not react directly with CO2. Instead, the CO2 must first be ionized into a bicarbonate ion (a slow reaction) before it will react with the amine. Since MDEA reacts directly (and quickly) with H2S, proper selection of the contact time between the amine and the process gas allows preferential removal of the H2S. The selectivity of MDEA for H2S over CO2 is enhanced by lower contact temperatures, hence the use of the trim cooler to reduce the solvent temperature before it enters the TGCU Contactor. The rich amine leaves the bottom of the tower at 42°C [108°F] and is pumped by the TGCU Rich Amine Pump, A2-GA1561A/B, through the TGCU Rich Amine Filter, A2-FD1562A/B, to remove accumulated solids. The rich amine then flows on level control through the tube side of the TGCU Lean/Rich Exchanger, A2-EA1564A/B/C, and is preheated to 105°C [221°F] by cooling the lean amine before flowing to the TGCU Stripper, A2-DA1562, entering between trays #4 and #5.
11.3.5
Solvent Regeneration Section The TGCU Stripper contains 28 valve trays (4 wash water trays, 24 stripping trays) and one chimney draw tray. As the solvent flows down the column, the absorbed H2S and CO2 are stripped from the MDEA by countercurrent contact with stripping steam rising upward. This stripping steam is generated in the TGCU Stripper Reboiler, A2-EA1565, using LP steam as the heat input. The heat input to the reboiler is adjusted by flow control of the steam. The steam flow controller can optionally be reset by the TGCU Stripper overhead temperature, which will maintain the desired overhead temperature of 118°C [244°F] by varying the heat input in proportion to the amount of acid gas contained in the rich amine. The stripping steam supplies the heat of reaction required to reverse reactions (6) and (7), and carries the H2S and CO2 stripped from the solvent overhead to the TGCU Stripper Reflux Condenser, A2-EC1562, where the steam is condensed as the stream is cooled to 49°C [120°F]. The condensed water is removed by the TGCU Stripper Reflux Accumulator, A2-FA1560, and returned as reflux to the wash water trays in the tower by the TGCU Stripper Reflux Pump, A2-GA1563A/B. The acid gas (H2S and CO2, along with the uncondensed water) stripped from the solvent exits the reflux drum at 0.85 kg/cm2(g) [12.1 PSIG] and flows to the two Sulfur Recovery Units.
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SULFUR BLOCK The TGCU Lean amine Pump, A2-GA1562A/B, pumps the regenerated lean MDEA solvent from the bottom of the TGCU Stripper through the shell side of the TGCU Lean/Rich Exchanger, cooling the lean amine from 127°C [261°F] to 66°C [152°F] by countercurrent heat exchange with the cool rich amine. A slipstream of the lean amine then flows through the TGCU Lean Amine Filter, A2-FD1563, to remove accumulated solids from the solvent and through the TGCU Amine Carbon Filter, A2-FD1564, where the activated carbon adsorbs contaminants such as degradation products from solvent. The TGCU Amine After-Filter, A2-FD1565, catches any carbon "fines" before the filtered slipstream rejoins the main solvent stream and flows to the TGCU Lean Amine Cooler, A2-EC1561, and the TGCU Lean Amine Trim Cooler, A2-EA1563A/B, which cool the solvent to 38°C [100°F] before it returns to the top of the TGCU Contactor on flow control.
11.3.6
Steam Production/Consumption The TGCU consumes steam at two pressure levels, and produces steam at one pressure level. Saturated HP steam from the SRUs is used to heat the TGCU Reactor feed stream, and LP steam is used to reboil solvent in the TGCU Stripper Reboiler. LP steam is produced in the TGCU Waste Heat Reclaimer, supplying a portion of the steam consumed in reboiling the TGCU solvent.
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SULFUR BLOCK
11.4 Equipment Description 11.4.1
TGCU Quench Column, A2-DA1560 The TGCU Quench Column contains a single bed of random packing to provide good contact between the hot process gas and the quench water that is to cool it. The tower has a 304 S.S. woven wire mist eliminator above the packed bed to remove entrained water droplets from the gas before it leaves the tower.
11.4.2
TGCU Quench Column Packing, A2-DB1560 This bed of random packing provides good contact between hot process gas entering below it and quench water fed above it inside the TGCU Quench Column. The packing has a bed limiter above it and rests on a bed support. The quench water is distributed over the packing by a distributor tray. The packing is 304 S.S.; the other internals are 304 S.S. Gaskets are installed where the bed support and distributor tray bolt to the support ring and clips inside the TGCU Quench Column to prevent direct contact between the stainless steel internals and the carbon steel vessel. This electrically isolates the dissimilar metals from each other to prevent direct contact that could lead to galvanic corrosion.
11.4.3
TGCU Contactor, A2-DA1561 The TGCU Contactor contains a single bed of random packing to provide good contact between the process gas and the TGCU solvent to remove H2S from the process gas. The tower has a 304 S.S. woven wire mist eliminator above the top bed to remove entrained solvent droplets from the gas before it leaves the tower.
11.4.4
TGCU Contactor Packing & Internals, A2-DB1561 This random packing bed provides good contact between process gas entering below it and TGCU lean amine fed above it inside the TGCU Contactor. The packing has a bed limiter above it and rests on a bed support. The lean amine is distributed over the packing by a distributor tray. The packing elements are 304 S.S.; the other internals are 304 S.S. Gaskets are installed where the bed support and distributor tray bolt to the support ring and clips inside the TGCU Quench Column to prevent direct contact between the stainless steel internals and the carbon steel vessel.
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SULFUR BLOCK This electrically isolates the dissimilar metals from each other to prevent direct contact that could lead to galvanic corrosion.
11.4.5
TGCU Stripper, A2-DA1562 The TGCU Stripper contains 28 valve trays to provide good contact between the rich TGCU solvent and the reboiler vapors to strip H2S and CO2 from the solvent. The rich amine enters on the fifth tray from the top; the four trays above that are "water wash" trays that allow the reflux water (entering on the top tray) to remove traces of MDEA from the overhead vapor and minimize solvent losses. A chimney tray is located below the bottom valve tray to gather all of the column liquids to feed the TGCU Stripper Reboiler. The column section located below this chimney tray serves to separate the outlet steam and lean amine from the reboiler and to provide surge for the solvent circulating system.
11.4.6
TGCU Stripper Trays, A2-DB1562 These 1-pass valve trays provide good contact between the rich TGCU solvent fed above them and the reboiler vapors fed below them inside the TGCU Stripper. The trays are designed per Shell's requirements. The tray decks are 304 S.S., and the valves are fabricated from 304 S.S. to resist corrosion and to prevent "sticking" to the tray decks. The chimney tray deck is 304 S.S. The bottom valve tray has a seal pan for its downcomer to maintain a liquid seal and prevent gas from blowing up the downcomer. The chimney tray gathers the tower liquids to feed the reboiler. The outlet from the reboiler reenters the column below the chimney tray, with the vapor produced by the reboiler flowing upward through the chimneys in order to reach the valve trays above. The top four trays in the column are located above the rich amine feed point and serve as water-wash trays to minimize the amount of amine carried-over in the tower overhead. Since these trays have only the reflux water flowing over them, the liquid rates for these trays are much lower than for the trays lower in the column. For this reason, these four trays are designed for minimum leakage (i.e., picket fence weirs, minimum downcomer clearance, etc.).
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SULFUR BLOCK 11.4.7
TGCU Reactor, A2-DC1560 The TGCU Reactor is of the down-flow type, with the feed gas entering the top of the vessel and proceeding vertically downward through the catalyst bed. A perforated baffle is installed below the inlet nozzle to distribute the gas over the length of the vessel and prevent the inlet gas stream from impinging directly on the catalyst bed. A catalyst support grating is installed in the vessel to support the catalyst bed in the center of the vessel. The support grating is covered with a stainless steel screen to prevent the catalyst from sifting through the grating. A small bead of castable refractory is used to seal the edges of the support grating to prevent catalyst leaks between the grating and the vessel shell.
11.4.8
TGCU Stripper Reflux Accumulator, A2-FA1560 This vertical pressure vessel removes condensed water from the stream leaving the TGCU Stripper Reflux Condenser so that the water can be used as reflux for the TGCU Stripper. The vessel has a 304 S.S. woven wire mist eliminator in the top to remove entrained liquid droplets from the gas before it leaves the vessel.
11.4.9
Catalyst for TGCU Reactor, A2-MC1560 Refer to the Basic Engineering Package for the type of catalyst used in the TGCU Reactor.
11.4.10 TGCU Stripper Reboiler Condensate Pot, A2-FA1562 This vertical pressure vessel collects the condensate from the TGCU Stripper Reboiler and returns it to the condensate system on level control. This method of removing condensate from the exchanger provides much smoother control of the heat input to the reboiler than a conventional steam trap could. As stated above, this vessel is simply a very good steam trap. During normal operation, the steam pressure required to provide the necessary reboil heat to the TGCU Stripper may be much less than the 3.5-4.2 kg/cm2(g) steam pressure available in the LP steam system. The normal steam pressure in the shell of the reboiler may be such that the water level in the condensate pot will rise upwards from the pot, perhaps even within the shell of the reboiler. During these periods, the level valve will remain fully open and the sight glass will indicate a full water level.
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SULFUR BLOCK This is a normal operating condition for this vessel. The vessel will usually operate with a visible level only when the TGCU Stripper Reboiler is operating near its maximum capacity with full steam pressure on the shell of the exchanger. Under these conditions, the level control and level valve will function normally and maintain a water level in the vessel.
11.4.11 TGCU Reactor Feed Heater, A2-EA1560 This shell and tube exchanger uses HP steam to heat the tailgas stream from the fourth pass of the two Sulfur Condensers up to reaction initiation temperature before it is mixed with hydrogen-rich reducing gas and flows to the TGCU Reactor.
11.4.12 TGCU Waste Heat Reclaimer, A2-EA1561 The TGCU Waste Heat Reclaimer is a fixed tubesheet shell and tube heat exchanger. The tubes are immersed in the water-filled section of the shell, allowing the boiling water in the shell of the exchanger to cool the hot gas leaving the TGCU Reactor catalyst bed by producing LP steam. There is no pressure control on the shell side of the boiler; it simply "floats" on the LP steam header pressure. The boiler is equipped with level transmittersthat will shut down the TGCU should the water level fall to within 75 mm of the top row of tubes. Operation of the boiler without a sufficient water level could possibly damage the tubes.
11.4.13 TGCU Quench Water Trim Cooler, A2-EA1562A/B This shell and tube exchanger is used to provide the final cooling of the quench water, with cooling water from the complex as the cooling medium.
11.4.14 TGCU Lean/Rich Exchanger, A2-EA1564 This shell and tube exchanger conserves energy by providing heat exchange between the rich amine and the lean amine, so that the hot lean amine leaving the TGCU Stripper can preheat the rich amine before it feeds the TGCU Stripper. This cross exchange saves reboiler duty by preheating the rich amine, and reduces the load on the TGCU Lean amine Cooler by partially cooling the hot lean amine.
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SULFUR BLOCK 11.4.15 TGCU Stripper Reboiler, A2-EA1565 The TGCU Stripper Reboiler is a fixed tubesheet shell and tube heat exchanger. The exchanger is arranged as a once-through vertical thermosiphon reboiler, mounted on the side of the TGCU Stripper. The static head of the solvent above the inlet nozzle on the lower channel provides the driving force to circulate the solvent through the tubes. LP steam on the shell of the exchanger heats the solvent inside the tubes, partially vaporizing it to create stripping steam to remove the H2S and the CO2 from the solvent flowing down the TGCU Stripper.
11.4.16 TGCU Lean Amine Trim Cooler, A2-EA1563 This shell and tube exchanger is used to provide the final cooling to the TGCU solvent returning from the regeneration section of the process, with cooling water from the complex as the cooling medium. Since the selectivity of MDEA for absorbing H2S in the presence of CO2 is better at lower temperatures, the use of cooling water is very beneficial to the process and results in reducing the emission of SO2 from the TTO.
11.4.17 TGCU Quench Water Cooler, A2-EC1560 This forced-draft aerial exchanger is used to reject some of the heat from cooling the process gas stream in the TGCU Quench Column by cooling the circulating quench water stream. Fans are used to circulate air across the finned tubes to remove heat from the quench water.
11.4.18 TGCU Stripper Reflux Condenser, A2-EC1562 This forced-draft aerial exchanger provides cooling to condense the majority of the water from the acid gas stream leaving the overhead of the TGCU Stripper. Fans are used to circulate air across the finned tubes to remove heat from the overhead stream and condense the water to be used as reflux for the tower.
11.4.19 TGCU Lean Amine Cooler, A2-EC1561 This forced-draft aerial exchanger provides some of the final cooling of the lean amine stream returning from the regeneration section of the TGCU process. Fans are used to circulate air across the finned tubes to remove heat from the solvent.
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SULFUR BLOCK
CAUTION SINCE THE PUMPS DESCRIBED IN THE FOLLOWING SECTIONS ARE CONSTRUCTED OF STAINLESS STEEL, DO NOT HYDROTEST THE ASSOCIATED VESSELS OR PIPING WITH WATER CONTAINING HIGH LEVELS OF CHLORIDES. AVOID ALLOWING WATER CONTAINING MORE THAN 50 PPM CHLORIDES TO COME IN CONTACT WITH THESE PUMPS TO PREVENT STRESS CORROSION CRACKING OF THE STAINLESS STEEL.
WARNING THE LIQUID IN THESE PUMPS CONTAINS DISSOLVED H2S. THIS H2S CAN BE RELEASED TO THE SURROUNDINGS WHEN LIQUID IS DRAINED FROM THESE PUMPS OR FROM THE PIPING CONNECTED TO THE PUMPS. ALWAYS OBSERVE PROPER PROCEDURES AND PRECAUTIONS WHEN DRAINING LIQUID FROM THESE PUMPS OR PERFORMING MAINTENANCE ON THEM. THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES SHOULD BE CONSULTED IF THERE IS ANY DOUBT ABOUT HOW TO WORK SAFELY WHEN H2S MAY BE PRESENT.
11.4.20 TGCU Quench Water Pump, A2-GA1560A/B These centrifugal pumps are used to circulate quench water to cool the process gas in the TGCU Quench Column. Each pump is designed for the total duty; the other pump is a 100% spare. These pumps are equipped with tandem seals to reduce the likelihood of releasing H2S to the surroundings.
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SULFUR BLOCK 11.4.21 TGCU Rich Amine Pump, A2-GA1561A/B These centrifugal pumps are used to send the rich amine from the TGCU Contactor to the TGCU Stripper. Each pump is designed for the total duty; the other pump is a 100% spare. These pumps are equipped with tandem seals to reduce the likelihood of releasing H2S to the surroundings.
11.4.22 TGCU Stripper Reflux Pump, A2-GA1563A/B These centrifugal pumps are used to send the reflux from the TGCU Stripper Reflux Accumulator to the TGCU Stripper. Each pump is designed for the total duty; the other pump is a 100% spare. These pumps are equipped with tandem seals to reduce the likelihood of releasing H2S to the surroundings.
11.4.23 TGCU Lean Amine Pump, A2-GA1562A/B These centrifugal pumps are used to send the lean amine from the TGCU Stripper to the TGCU Contactor. Each pump is designed for the total duty; the other pump is a 100% spare. These pumps are equipped with tandem seals to reduce the likelihood of releasing H2S to the surroundings.
11.4.24 TGCU Start-Up Blower, A2-GB1560 The TGCU Start-Up Blower is a single-stage fan, used process gas within the TGCU Unit. Flexible connectors are the fan from the suction and discharge piping to allow freedom for the expansion and movement that occurs operation.
to re-circulate used to isolate the necessary during normal
The shaft seal is made gas-tight by using a gas-lubricated non-contacting dual cartridge seal, so that process gas cannot escape to the surroundings. The nitrogen seal purge should be kept in service at all times, whether the blower is operating or not, to prevent leakage of process gas. The blower casing and impeller are constructed of carbon steel and coated with "Heresite", a baked phenolic coating, for corrosion resistance.
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SULFUR BLOCK
WARNING THIS BLOWER HANDLES GASES CONTAINING H2S, SO2, AND OTHER HARMFUL GASES. ALWAYS OBSERVE PROPER PROCEDURES AND PRECAUTIONS WHEN PERFORMING MAINTENANCE ON THIS BLOWER. THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES SHOULD BE CONSULTED IF THERE IS ANY DOUBT ABOUT HOW TO WORK SAFELY WHEN H2S AND/OR SO2 MAY BE PRESENT.
CAUTION
WHEN THIS BLOWER IS NOT OPERATING, WATER CAN CONDENSE FROM THE PROCESS GAS AND CAUSE CORROSION DAMAGE TO THE BLOWER. TO PREVENT THIS, THE BLOWER IS AUTOMATICALLY ISOLATED FROM THE PROCESS BY CLOSING ITS SUCTION AND DISCHARGE BLOCK VALVES WHEN IT STOPS, THEN PURGING THE BLOWER CASING WITH NITROGEN. THE NITROGEN PURGE SHOULD BE CHECKED PERIODICALLY TO CONFIRM THAT IT IS OPERATING PROPERLY.
11.4.25 Refractory for TGCU Reactor, A2-MR1560 A 50 mm bead of castable refractory is installed around the edges of the catalyst bed support inside the TGCU Reactor. This seals the edges of the bed support so that the small catalyst pellets cannot escape from the bed.
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SULFUR BLOCK 11.4.26 TGCU Reactor Feed Mixer, A2-ME1560 This static mixer is designed to thoroughly mix the tailgas leaving the TGCU Reactor Feed Heater and the hydrogen-rich reducing gas before the combined stream enters the TGCU Reactor.
11.4.27 TGCU Quench Water Filter, A2-FD1560A/B This filter is designed to remove solid particles 5 microns and larger from a slipstream of the circulating quench water. If SO2 enters the TGCU Quench Column and reacts with H2S to form small particles of colloidal sulfur, the filter will also help remove them.
WARNING A COMMON CONTAMINANT REMOVED BY THIS FILTER IS IRON SULFIDE, WHICH IS PYROPHORIC AT AMBIENT TEMPERATURE. IF THE FILTER ELEMENTS CONTAIN SUFFICIENT IRON SULFIDE, THE ELEMENTS MAY SPONTANEOUSLY IGNITE ONCE THE ELEMENTS DRY. ACCORDINGLY, EXERCISE PROPER CARE WHEN HANDLING AND DISPOSING OF USED FILTER ELEMENTS.
11.4.28 TGCU Rich Amine Filter, A2-FD1562A/B This full-flow filter is designed to remove solid particles 5 microns and larger from the circulating rich TGCU solvent, which will help prevent fouling of the downstream heat exchangers.
WARNING THIS FILTER HANDLES LIQUID CONTAINING H2S AND OTHER HARMFUL SUBSTANCES. ALWAYS OBSERVE PROPER PROCEDURES AND PRECAUTIONS WHEN PERFORMING MAINTENANCE ON THIS FILTER. THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES SHOULD BE CONSULTED IF THERE IS ANY DOUBT ABOUT HOW TO WORK SAFELY WHEN H2S MAY BE PRESENT.
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SULFUR BLOCK 11.4.29 TGCU Lean Amine Filter, A2-FD1563 This filter is designed to remove solid particles 5 microns and larger from a slipstream of the circulating lean TGCU solvent.
11.4.30 TGCU Amine Carbon Filter, A2-FD1564 This filter is designed to remove organic contaminants (trace hydrocarbons, degradation products, etc.) from a slipstream of the circulating lean TGCU solvent using a bed of activated carbon.
11.4.31 TGCU Amine After-Filter, A2-FD1565 This filter is designed to remove solid particles, particularly carbon fines, 5 microns and larger from the lean TGCU solvent leaving the TGCU Amine Carbon Filter.
11.4.32 pH Meter Sample Filter, A2-FD1561A/B These filters are designed to remove solid particles 5 microns and larger from the small stream of quench water flowing to the pH analyzer probe. There are two 100% filters so that one filter can remain in service while the other filter is being cleaned.
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SULFUR BLOCK
11.5 Instrumentation and Control Systems 11.5.1
TGCU Reactor Feed Control Loops The TGCU Reactor Feed Heater, A2-EA1560, and TGCU Reactor Feed Mixer, A2-ME1560, condition the combined tailgas from the SRUs before it enters the TGCU Reactor, A2-DC1560, by heating the tailgas and mixing it with reducing gas (hydrogen). Saturated HP steam produced in the SRUs is used to heat the tailgas to the desired reaction temperature (~240°C [~464°F]). External reducing gas is then mixed with the tailgas to supply some of the hydrogen needed to convert all of the sulfur compounds to H2S in the reactor. Thus, here are two important control parameters: the reactor feed temperature and the hydrogen concentration in the reactor feed. The loop diagram on page 11-22 illustrates the components of these control loops when implemented in a distributed control system (DCS). There are also controls for handling specific requirements during startup and shutdown of the front-end of the TGCU. These control loops are shown on the loop diagram as well. All of the control loops are discussed in the sections that follow.
11.5.1.1
Reactor Feed Temperature Control The feed to the TGCU Reactor is the gas leaving the TGCU Reactor Feed Mixer. The temperature of this stream depends on the amount of heating that takes places as the combined tailgas stream flows through the TGCU Reactor Feed Heater. A2-TIC15820 on the mixer outlet raises or lowers the setpoint of the steam pressure controller, A2-PIC15820, to control this temperature by adjusting the steam pressure inside the shell of the exchanger. To raise the reactor feed temperature, A2-TIC15820 increases the steam pressure by increasing the setpoint of A2-PIC15820. This will cause A2-PIC15820 to open steam control valve A2-PV15820 more, which results in two effects. First, as the valve opens more, the pressure drop is reduced across the valve, increasing the steam pressure inside the shell of the exchanger. This in turn increases the saturation temperature of the steam inside the shell, increasing the temperature driving force and thus raising the heat input to the process gas in the tubes. Second, as the valve opens more, the steam flow rate increases, supplying more heat to the exchanger to
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SULFUR BLOCK match the increase in the heat input. The net result is to increase the heat transfer, raising the feed temperature accordingly. Conversely, A2-TIC15820 lowers the reactor feed temperature by reducing the setpoint of A2-PIC15820 so that it closes A2-PV15820 more. This drops the steam pressure inside the shell to reduce the heat input, and reduces the steam flow to match. This reduces the heat transfer, thus lowering the feed temperature. 11.5.1.2
Hydrogen Concentration Control To ensure complete conversion of the sulfur compounds in the TGCU Reactor, it is necessary to maintain an excess of hydrogen in the gas leaving the reactor. The hydrogen concentration is measured by the hydrogen analyzer, A2-AE15858, and supplied to A2-AIC15816 in the DCS. The output from A2-AIC15816 is limited from high and low extremes by A2-AY15816 (to protect the process from analyzer malfunctions), and adjusts the flow rate of external reducing gas being supplied to the TGCU Reactor Feed Mixer via adjustment of the remote setpoint on the reducing gas flow controller, A2-FIC15816. A2-AY15816 restricts the remote setpoint supplied to A2-FIC15816 between 10% and 100% of the maximum range of the reducing gas flow meter, 51.3 Nm3/H and 513.0 Nm3/H, respectively. The normal sample point for hydrogen analyzer A2-AE15858 is the treated gas leaving the overhead of the TGCU Contactor, A2-DA1561, because this stream is the "cleanest" due to the H2S removal accomplished in the tower. During startup of the TGCU, however, there is no process gas flowing through the TGCU Contactor until after operation of the TGCU Reactor has been "lined out" and the process gas flow is directed into the TGCU Quench Column and the TGCU Contactor. Until then, there is no gas flowing in the TGCU Contactor overhead line, so an alternate sample point is provided on the outlet of the TGCU Waste Heat Reclaimer, A2-EA1561, to allow the analyzer to sample the gas leaving the TGCU Reactor. The 4-way selector valve, A2-HV15858, provided with the analyzer allows the operators to switch between the two sample points. LP purge gas is also connected to this valve, so that when one sample point is supplying process gas to the analyzer, the other sample point
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SULFUR BLOCK is being back-purged with inert gas. This minimizes the possibility of having one of the sample points plug when it is not in use. The process gas that is being sampled is saturated with water, so the data sheet for the analyzer system specifies that the sample conditioning system includes a dryer. For the sample point on the outlet of the TGCU Waste Heat Reclaimer, there is also the possibility of elemental sulfur vapor being present in the gas during process upsets. To prevent sulfur from reaching the analyzer and damaging it, a "sacrificial sample loop" consisting of a coil of bare tubing is provided in this sample line. The tubing coils provide heat transfer surface, so that if sulfur does find its way to this point in the process, the gas will cool off enough for the sulfur to solidify, plugging the sample loop and stopping the flow of process gas to the analyzer before the sulfur can damage the analyzer. Should this occur, only the coiled tubing will need to be replaced, rather than the expensive analyzer. Note that the sample lines are to free-drain from the analyzer back to the sample points, so the tubing coils should be oriented in the horizontal so that the coils due not cause a "pocket" in the sample line for this sample point. 11.5.1.3
Controls for Startup and Shutdown The front-end of the TGCU is also equipped with three sets of controls for use during startup and shutdown: a.
Prior to introducing SRU tailgas into the TGCU, the equipment in the front-end of the unit must be brought up to operating temperature. This is accomplished by using the TGCU Startup Blower, A2-GB1560, to re-circulate gas from the outlet of the TGCU Waste Heat Reclaimer to the inlet of the TGCU Reactor Feed Heater (via the TGCU Warmup/Bypass Valve, A2-NV15800). This allows using the TGCU Reactor Feed Heater to heat the gas and thereby bring all the equipment up to operating temperature. Flow controller A2-FIC15808 is provided to allow filling the front-end with nitrogen prior to establishing the re-circulation flow during startup. This same control can also be used to add nitrogen during shutdown of the unit for cool-down purposes.
b.
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Prior to the initial startup of the unit, the catalyst in the TGCU Reactor must be pre-sulfided so that it retains its activity when it Tailgas Cleanup
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SULFUR BLOCK is exposed to hydrogen at elevated temperatures. The catalyst will also have to be pre-sulfided when fresh catalyst is added to the reactor following a catalyst change-out. A source of H2S is needed for pre-sulfiding the catalyst, for which a slipstream of amine acid gas from the ARU serves nicely. Flow controller A2-FIC15824 is provided to allow adding a small amount of acid gas to give an H2S concentration of 1-2% in the nitrogen circulating through the front-end of the unit during catalyst pre-sulfiding activities. c.
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After the TGCU has been operating for a period of time, the catalyst becomes pyrophoric due to the presence of iron sulfide, FeS. Exposing catalyst containing pyrophoric FeS to air may result in uncontrolled burning of the FeS to form H2S and/or SO2, which obviously will prevent the entrance of personnel into the vessel. When the TGCU is to be shut down to replace the catalyst, or for other maintenance activities that will allow oxygen to enter the reactor, it is necessary to perform a controlled oxidation ("passivation") of the FeS in the catalyst by operating at low temperature (~150°C [~300°F]) and controlling a small concentration (1-2%) of oxygen in the circulating gas. This converts the FeS into non-pyrophoric iron oxide, Fe2O3, while leaving the catalyst in its sulfided state. Flow controller A2-FIC15805 is provided to allow adding a small amount of utility air to the nitrogen circulating through the front-end of the unit to provide the oxygen for catalyst passivation.
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SULFUR BLOCK
TGCU Reactor Feed Control Loops
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SULFUR BLOCK 11.5.2
Hydrogen and Hydrogen Sulfide Analyzer, A2-AE15858/A2-AE15859 Analyzer A2-AE15858/A2-AE15859 has two separate sensors, one for measuring hydrogen concentration and one for measuring hydrogen sulfide concentration. The H2S sensor is a photometric sensor that is very similar to the one used in the SRU air demand analyzers. It uses the absorption of a specific wavelength of UV light to determine the H2S concentration in the process gas. The H2 sensor in this analyzer is actually a thermal conductivity sensor. Hydrogen has a much higher thermal conductivity than the other gases found in the process stream, so the thermal conductivity of the process gas is a good indication of the hydrogen concentration. To make the sensor reading as accurate as possible, it is necessary to "zero" and "span" the sensor with special calibration gas mixtures that have the same "background" thermal conductivity as the expected process gas. Although this technique works well, always remember that this sensor does not measure hydrogen concentration directly, so its reading (particularly at low hydrogen concentrations) may not always be accurate. The H2/H2S analyzer can sample the process gas from two different locations, depending on the position of the selector valve inside the analyzer enclosure. The first sample connection is on the outlet of the TGCU Waste Heat Reclaimer. It should be used only during startup, pre-sulfiding, and other special operations when the process gas is bypassing the quench and contacting sections. This connection has a "sacrificial" sample line, which is essentially a disposable sample cooling coil. It is intended to protect the analyzer by cooling, condensing, and freezing any sulfur vapor that may be present in the sample due to process upsets. If this occurs, the cooling coil will plug before the sulfur can reach the analyzer, sacrificing the inexpensive tubing to protect the expensive analyzer. The second sample point is on the overhead line from the TGCU Contactor, and is the normal sampling point. During startup of the TGCU, the hydrogen analyzer should be switched to this sample point as soon as the Quench Column hand control in the DCS is used to open the Quench Column Inlet Valve and close Quench Column Bypass Valve to send gas through the TGCU Quench Column and the TGCU Contactor. There is much less chance of damaging the analyzer with contaminants when sampling gas at this point, so it is the preferred sample connection.
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SULFUR BLOCK Liquid water will destroy the H2 sensing element in this analyzer. Although the sample conditioning system includes a dryer to remove water vapor from the sample gas, liquid water can get through the dryer and damage the analyzer. Since water tends to condense from the process gas and accumulate in stagnant areas, make sure there is no liquid in the sample line before switching from one sample point to another.
11.5.3
Boiler Low-Low Level S/D Transmitter Testing The TGCU Waste Heat Reclaimer has three independent level transmitters connected to the PLC that activate the TGCU ESD system before the water level can get low enough to cause tube damage. The shutdown is activated when two out of three transmitters show a low-low level. These transmitters should be tested periodically to determine that they are functioning properly. Since 2oo3 voting is used for the low-low level shutdowns in the TGCU ESD, the level transmitters can be tested one at a time without having to bypass the ESD system. Consider A2-LT15845A on the Waste Heat Reclaimer, for example. The procedure for testing A2-LT15845B and A2-LT15845C will be similar. The procedure for testing A2-LT15845A is as follows:
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(1)
The outside operator notifies the DCS operator that he is preparing to test shutdown level transmitter "A" on the Waste Heat Reclaimer.
(2)
The DCS operator confirms that A2-LI15845B and A2-LI15845C are both indicating adequate level in the boiler, then notifies the outside operator to proceed.
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CAUTION
DO NOT PROCEED UNLESS THE OTHER TWO LEVEL INDICATORS SHOW ADEQUATE LEVEL IN THE BOILER. OTHERWISE THE LOW-LOW LEVEL SHUTDOWN IN THE TGCU ESD WILL BE ACTIVATED AS SOON AS THE OUTSIDE OPERATOR BEGINS DRAINING THE LEVEL TRANSMITTER IN THE NEXT STEP. (3)
After being notified to proceed by the DCS operator, the outside operator blocks-in A2-LT15845A by closing its block valves, then opens the drain valve on the bottom of the transmitter to drain the water from the instrument.
(4)
If the transmitter is operating properly, the DCS will alarm that there is a low level in the Waste Heat Reclaimer on A2-LI15845A. The DCS operator acknowledges the alarm on the DCS and reports it to the outside operator.
(5)
After being notified of the alarm, the outside operator closes the drain valve on A2-LT15845A, slowly opens its bottom block valve to allow the transmitter to fill with water then opens its top block valve. This should clear the low level alarm on A2-LI15845A in the DCS.
(6)
After confirming that the low level alarm has cleared, the other level transmitters can be tested in a similar fashion.
NOTE:
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The DCS operator must not begin another task until confirming that the low level alarm has cleared. This is to guard against having a level transmitter malfunction that causes a TGCU ESD when the other transmitters are tested.
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SULFUR BLOCK 11.5.4
Tailgas Switching Valve Controls The tailgas switching valves and their controls for the Train 1 and Train 2 SRUs are depicted on the P&ID, dwg. no. 507000-7100-34, while the logic flowcharts, show the logic for these controls for the Train 1 SRU. However, it may be helpful to explain why the controls are implemented in this manner. The discussion that follows will describe how these controls allow routing the Train 1 SRU and Train 2 SRU tailgas streams to the Thermal Oxidizer and the TGCU under different operating scenarios, and will explain how the controls depicted on the P&ID correspond to the different sections of the logic diagrams.
11.5.4.1
Repositioning the Tailgas Valves Following a TGCU ESD As shown on the P&ID, prior to restarting the TGCU following a TGCU ESD, the SRU tailgas valves to the TGCU (A2-HV15462 and A2-HV15662) must be closed to satisfy the permissives for the TGCU ESD system reset. However, before these valves can be closed, the tailgas valves to the TTO (A2-HV15457 and A2-HV15657) must be opened first to avoid blocking the tailgas flow and causing the SRUs to shut down on high-high pressure. If the valves are not opened and closed in the proper order, the SRUs could inadvertently be shut down while preparing to restart the TGCU. For this reason, the TGCU ESD is an input to the PLC interlock blocks that manipulate the controllers (A2-HIC15457, A2-HIC15462, A2-HIC15657, and A2-HIC15662) for these valves. The PLCs and DCS automatically reposition the valves following a TGCU ESD to divert the SRU tailgas to the TTO, meaning that the valves are already positioned properly for the subsequent restart of the TGCU. The logic that accomplishes this for the Train 1 SRU is depicted on the logic flow diagram. When the TGCU ESD is activated, the Train 1 SRU PLC directs the DCS to set the output from A2-HIC15457 to 100% to open A2-HV15457, proves the valve open, then directs the DCS to set the output from A2-HIC15462 to 0% to close A2-HV15462 and proves the valve closed. This diverts the Train 1 SRU tailgas directly to the TTO. (The PLC logic will not take these actions if the Train 1 SRU has its startup/run selector switch, A2-HS15314, set to "STARTUP", since both tailgas valves will already be closed by the startup logic for the Train 1 SRU)
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SULFUR BLOCK Note that this same logic is also used to open the tailgas valve to the TTO and close the tailgas valve to the TGCU if the TGCU startup/run selector switch (A2-HS15830) is set to "STARTUP". This safeguard is to prevent sending SRU tailgas into the TGCU before the TGCU Reactor is ready, as this could cause a severe upset in the TGCU Quench Column and/or TGCU Contactor (and possibly damage the piping, equipment, quench water, and/or solvent). 11.5.4.2
Introducing SRU Tailgas into the TGCU — Scenario 1 The first scenario to consider for introducing tailgas into the TGCU is a normal startup of the SRUs and the TGCU. Before being routed to the TGCU, the tailgas from both SRUs is sent to the TTO via valves A2-HV15457 and A2-HV15657, while the TGCU uses the TGCU Startup Blower to re-circulate gas to the TGCU Reactor Feed Heater via the TGCU warmup/bypass valve, A2-NV15800. Once the TGCU is warmed up and ready to accept tailgas, the Train 1 and Train 2 SRUs can be routed to the TGCU as follows (using the Train 1 SRU for this example).
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1.
The operator toggles the "fast" transfer switch, A2-HS15463 in the DCS, to "TRANSFER TO TGCU".
2.
The PLC directs the DCS to set the output from A2-HIC15462 to 100% to open the Tailgas Valve to the TGCU, A2-HV15462, then proves that the valve is open.
3.
Since the Tailgas Valve to the TTO, A2-HV15457, is still open, the SRU tailgas will continue flowing to the TTO at this time (the path of least resistance).
4.
Once the limit switches prove A2-HV15462 is open, the PLC directs the DCS to set the output from A2-HIC15457 to 0% to close A2-HV15457, then proves that the valve is closed.
5.
Since A2-NV15800 is open at this time, some of the SRU tailgas may still flow through this valve directly to the TTO. The TGCU Startup Blower will pull the rest of the tailgas into the TGCU Reactor Feed Heater.
6.
If the second SRU (Train 2 in this example) is also ready to send its tailgas to the TGCU, the operator can also toggle its "fast" transfer switch in the DCS (A2-HS15663) to repeat these actions for the second SRU. Tailgas Cleanup
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SULFUR BLOCK 7.
Once one or both of the tailgas valves to the TGCU is open and the corresponding tailgas valve(s) to the TTO are closed, the operator can use A2-HIC15800 in the DCS to close A2-NV15800.
8.
This will force all of the SRU tailgas to flow to the TGCU Reactor Feed Heater.
9.
Once A2-NV15800 is fully closed, all of the SRU tailgas must flow to the TGCU Reactor Feed Heater because there are no longer any other open paths to the TTO. The TGCU Startup Blower can now be shut down by toggling A2-HPB15855 in the DCS to "STOP" to open the blower bypass valve, turn off the blower, and close the blower suction and discharge valves.
10. All of the SRU tailgas will now be flowing through the TGCU Reactor Feed Heater, TGCU Reactor Feed Mixer, TGCU Reactor, and TGCU Waste Heat Reclaimer, then flowing to the TTO via the TGCU Quench Column bypass valve, A2-HV15851, at the TGCU Startup Blower. Once the plant stabilizes and there is excess hydrogen in the reactor outlet, the TGCU Quench Column inlet valve, A2-HV15850, can be opened and A2-HV15851 closed using A2-HIC15850 in the DCS to send the process gas into the TGCU Quench Column and TGCU Contactor. For this scenario, the opening and closing of A2-HV15462 and A2-HV15457, respectively, (or A2-HV15662 and A2-HV15657 for Train 2) in Steps 2 and 3 can occur rapidly with no impact on either the SRU or the TGCU. This is because A2-NV15800 will still be open at this time, so there will be very little differential pressure across A2-HV15462 (A2-HV15662) and there will not be an abrupt change in pressure when A2-HV15462 (A2-HV15662) is opened or when A2-HV15457 (A2-HV15657) is closed. Note that A2-HS15463 and A2-HS15663 can also be used to take the Train 1 SRU and/or Train 2 SRU tailgas out of the TGCU. Every other toggle of these selector switches will take the opposite action to open the tailgas valve to the TTO and then close the tailgas valve to the TGCU. For instance, if a problem develops while introducing the tailgas into the TGCU, toggling A2-HS15463 and A2-HS15663 to "TRANSFER TO TTO" will immediately divert the SRU tailgas to the TTO
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SULFUR BLOCK and block it from flowing into the TGCU. Once the problem has been corrected, A2-HS15463 and A2-HS15663 can be toggled once again to "TRANSFER TO TGCU" to send the SRU tailgas into the TGCU. 11.5.4.3
Introducing SRU Tailgas into the TGCU — Scenario 2 The second startup scenario to consider is when the TGCU is already processing tailgas from one SRU, and the tailgas from the second SRU needs to be introduced into the TGCU. Assume that the Train 2 SRU is currently feeding the TGCU. Due to the back-pressure from the TGCU, the pressure downstream of A2-HV15462 will be about 0.07 kg/cm2(g), while the pressure upstream of this valve will be close to 0 kg/cm2(g) (since A2-HV15457 will be open to the TTO at this time). If the Train 1 tailgas was quickly switched into the TGCU in the same manner as described above for the first scenario, a major upset would result in both SRUs and in the TGCU: (1)
As soon as A2-HV15462 started to open, tailgas from the Train 2 SRU would begin to back-flow through A2-HV15462 and flow to the TTO, since the pressure downstream of A2-HV15462 at that moment would be higher than the pressure upstream of A2-HV15462. Since A2-HV15462 is a more direct path to the TTO for the tailgas from the Train 2 SRU, most of the Train 2 tailgas would flow through A2-HV15462 as it opens rather than flow through the TGCU. The outlet temperature from the TGCU Reactor Feed Heater would begin to rise (due to the drop in tailgas flow), causing the controls to begin reducing the steam flow rate to the heater. Once A2-HV15462 was fully open, all of the Train 1 tailgas and most of the Train 2 tailgas would be flowing directly to the TTO through A2-HV15457. The TGCU controls would continue reducing the steam flow rate to the TGCU Reactor Feed Heater to try to keep its outlet temperature under control.
(2)
With A2-HV15462 fully open, A2-HV15457 would begin to close. This would begin forcing all of the Train 1 tailgas and Train 2 tailgas into the TGCU Reactor Feed Heater. The outlet temperature from the TGCU Reactor Feed Heater would begin to drop, causing the controls to begin increasing the steam flow rate to the heater. Once A2-HV15457 was fully
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SULFUR BLOCK closed, all of the Train 1 and Train 2 tailgas would be flowing to the TGCU Reactor Feed Heater, causing an abrupt increase in its operating pressure from about 0.07 kg/cm2(g) to about 0.25 kg/cm2(g). This would cause the air and acid gas flow rates to the SRUs to suddenly drop, possibly causing the SRUs to flame-out. If so, the SRUs and the TGCU would shut down and the operators would have to start over again. (3)
If the SRUs and TGCU did manage to stay on-line, the TGCU Reactor Feed Heater would be supplying less than half as much heating as needed until the controls recover and bring the steam flow rate up to the new requirements. Until then, the inlet temperature to the TGCU Reactor would be low, possibly causing incomplete conversion of SO2 in the reactor and allowing SO2 to reach the quench water and solvent systems and foul them. The reducing gas flow rate might also require time to adjust to the higher tailgas flow rate, further compounding the problems with conversion in the reactor.
So, the best that could be expected if the second SRU is routed to the TGCU in the same manner as under the first scenario is an upset in both SRUs, the TGCU Reactor Feed Heater, the TGCU Reactor, the quench water system, and the solvent system. Depending on how quickly the SRUs respond to sudden changes in operating pressure, the SRU burners might flame-out. In this worst case, a complete restart of the SRUs and the TGCU would then be required. Instead of introducing the tailgas from the second SRU into the TGCU in an abrupt manner, what is needed is a slow, controlled redirection of the tailgas from the TTO to the TGCU. This can be accomplished by the DCS operator using A2-HIC15457 and A2-HIC15462: 1.
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Under this scenario, the TGCU is already processing tailgas from the Train 2 SRU. This means that the TGCU warmup/bypass valve, A2-NV15800, is already closed. This signals the PLC to disable the "fast" transfer switches in the DCS, A2-HS15463 and A2-HS15663 so that the rapid switching sequence (scenario 1) cannot be activated inadvertently.
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SULFUR BLOCK 2.
The DCS operator initiates the over-ride for the Train 1 tailgas valves by toggling the "slow" transfer switch, A2-HS15464 in the DCS, to "OVER-RIDE". The PLC temporarily removes the limit switches on A2-HV15457 and A2-HV15462 from the "complete flowpath interlock" for the Train 1 SRU alarms and deactivates the "valve malfunction" alarms on these two valves, then directs the DCS to release control of A2-HIC15457 and A2-HIC15462 to the operator.
3.
The operator uses A2-HIC15457 to slowly begin throttling the tailgas flow with A2-HV15457, so that the pressure at the front-end of Train 1 is slightly higher than at the front-end of the Train 2 SRU. The DCS operator can monitor the flows and pressure in the Train 1 SRU and adjust A2-HIC15457 accordingly.
4.
Once A2-HV15457 is throttling, the operator uses A2-HIC15462 to slowly open A2-HV15462. Some of the Train 1 tailgas may begin to flow into the TGCU at this time, but most of it will still flow through A2-HV15457 directly to the TTO. The DCS operator can monitor the flows and pressures in the Train 1 SRU and the TGCU, and adjust the rate at which A2-HV15462 is opened accordingly.
5.
Once A2-HV15462 is fully open, the operator uses A2-HIC15457 to slowly close A2-HV15457 the rest of the way and send all of the Train 1 tailgas to the TGCU. The DCS operator can monitor the flow rates and temperatures in the TGCU, and adjust the rate at which A2-HV15457 is closed as needed to allow time for the controls in the TGCU to respond.
6.
Once A2-HV15457 is fully closed, the Train 1 SRU is flowing to the TGCU along with the Train 2 SRU, and the TGCU is fully on-line. When A2-HV15462 is fully open and A2-HV15457 is fully closed, the PLC will automatically restore the limit switches on A2-HV15457 and A2-HV15462 to the "complete flowpath interlock" in the SRU alarms, restore the malfunction alarms for these valves to their normal configurations, and reset the "slow"
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SULFUR BLOCK transfer switch, A2-HS15464 in the DCS, back to "NORMAL" to remove the over-ride. One further point to note is that the "slow" transfer over-ride switches can also be used to "back" tailgas out of the TGCU. If the operator wants to shut down the TGCU in a controlled fashion, this can be accomplished by using the TGCU Startup Blower to circulate gas through the TGCU Reactor Feed Heater while slowly "backing" the SRU tailgas out of the TGCU. The steps to perform this are essentially the same as those listed above (but in reverse order).
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SULFUR BLOCK 11.5.5
TGCU Shutdown System The purpose of the Tailgas Cleanup Unit Emergency Shutdown system (TGCU ESD) is to shut off the flow of tailgas, reducing gas, pre-sulfiding gas, nitrogen, and passivation air to the TGCU when serious problems occur. The Cause and Effect Diagram, contained in the Instrumentation and Controls Diagrams section of the Basic Engineering Package, describes the TGCU ESD system in block format. For reference, the causes and effects of the ESD system shown on this diagram are explained below. As noted on the Cause and Effect Diagram, it is recommended that a 5 second delay be used for most of the process parameters included in the causes of the ESD system. This is to prevent the "nuisance" shutdowns that are sometimes caused by momentary fluctuations in the process or the sensing elements.
11.5.5.1
Causes Any one of the causes listed below will activate the TGCU ESD system: a.
Manual Shutdown Switch, A2-HS15827 An operator can activate the TGCU ESD system using the NORMAL / ESD selector switch in the DCS.
b.
Both SRU ESD Systems For normal modes of operation, the TGCU ESD system is activated when both SRU ESD systems are activated. Without any SRU tailgas flowing through the front-end of the TGCU, there is nothing to process in the unit, so the TGCU is shut down whenever both sulfur plants shut down. (Note, however, that the TGCU ESD is not activated if one of the SRUs is still on-line when the other SRU shuts down.) However, if the TGCU is not yet fully processing tailgas from either SRU, there is no reason to shut it down if no SRUs are running. This simplifies startup of the TGCU by allowing its ESD system to be independent of the SRU ESD systems until tailgas is introduced into the TGCU. The example logic below shows this concept:
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SULFUR BLOCK
c.
Complete Flowpath Interlock (see Logic Flow Diagrams for the limit switch tag numbers) In order for the TGCU to operate without over-pressuring itself or the Sulfur Drain Seal Assemblies in the upstream SRUs, there must be a complete flowpath for SRU tailgas through the TGCU to the TTO. The ESD logic can determine whether such a complete flowpath exists by examining the status of the limit switches on the process gas valves. There are basically three different paths that the SRU tailgas can take to reach the TTO: (1)
The TGCU Warmup/Bypass Valve, A2-NV15800, and the TGCU Outlet Valve, A2-HV15801, are both fully open.
(2)
The process gas is diverted to the TTO upstream of the TGCU Quench Column:
(3)
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(a)
The TGCU Quench Column A2-HV15851, is fully open;
Bypass
Valve,
(b)
Either the TGCU Startup Blower Bypass Valve, A2-HV15853, is fully open, or both the TGCU Startup Blower Suction Valve, A2-HV15852, and the TGCU Startup Blower Discharge Valve, A2-HV15854, are fully open; and
(c)
The TGCU Outlet Valve is fully open.
The process gas is flowing through the TGCU Quench Column and the TGCU Contactor to the TTO: (a)
The TGCU Quench Column A2-HV15850, is fully open; and
(b)
The TGCU Outlet Valve is fully open.
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Inlet
Valve,
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SULFUR BLOCK If the "open" limit switches do not indicate that at least one of these flowpaths is valid, the "complete flowpath interlock" is tripped and the TGCU ESD system is activated. Note that the TGCU Complete Flowpath Interlock signal to the Complete Flowpath Interlock logic for the Train 1 SRU and the Train 2 SRU is over-ridden for 60 seconds when this occurs, allowing time for the SRU tailgas valves to be repositioned (see Section 11.5.4.1) and preventing nuisance alarms in the SRUs. d.
TGCU Reactor A2-TT15842A/B/C
Outlet
High-High
Temperature,
These devices shut down the TGCU if the reactor outlet temperature reaches 400°C. The most common cause of high reactor outlet temperature is large concentrations of SO2 in the SRU tailgas streams due to poor sulfur plant performance, leading to excessive heat of reaction in the catalyst bed. These devices will prevent excessive temperatures in the reactor from causing damage to the reactor vessel, its catalyst, or its catalyst bed support. Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD (i.e., at least two transmitters must show high-high temperature) to avoid spurious "trips" due to the malfunction of a single transmitter. e.
TGCU Waste Heat A2-LT15845A/B/C
Reclaimer
Low-Low
Water
Level,
These devices activate the TGCU ESD system to prevent having the water level drop below the top of the tubes in this boiler while hot gas is flowing through the tubes, thereby averting high effluent temperatures and higher than normal tube wall temperatures. High effluent temperatures could cause high overhead temperature from the TGCU Quench Column and result in poor H2S removal in the TGCU Contactor, and high tube wall temperatures could possibly damage the tubes due to differential expansion. These devices are set to actuate if the level falls to within 75 mm of the top of the tubes. Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD.
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SULFUR BLOCK 11.5.5.2
Effects A TGCU shutdown, activated either manually or automatically, has the following effects on the TGCU:
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a.
Opens the Train 1 SRU Tailgas Valve to the TTO, A2-HV15457, proves it open, then closes the Train 1 SRU Tailgas Valve to the TGCU, A2-HV15462, and proves it closed.
b.
Opens the Train 2 SRU Tailgas Valve to the TTO, A2-HV15657, proves it open, then closes the Train 2 SRU Tailgas Valve to the TGCU, A2-HV15662, and proves it closed.
c.
Disables the "fast" and "slow" tailgas transfer switches for the Train 1 SRU (A2-HS15463 and A2-HS15464, respectively) and for the Train 2 SRU (A2-HS15663 and A2-HS15664, respectively).
d.
Shuts off and depressurizes the nitrogen and plant air supplies by closing block valves A2-NV15809 and A2-NV15811 and opening vent valve A2-NV15810.
e.
Shuts off and depressurizes the reducing gas supply by closing block valves A2-NV15817 and A2-NV15819 and opening vent valve A2-NV15818.
f.
Closes the reducing gas flow control valve, A2-FV15816, by placing A2-FIC15816 in "manual" and setting its output to 0%.
g.
Shuts off the pre-sulfiding gas flow by closing block valve A2-NV15825.
h.
Closes the TGCU Quench Column Inlet Valve, A2-HV15850, and the TGCU Quench Column Bypass Valve, A2-HV15851, to stop the flow of SRU tailgas into the TGCU.
i.
Forces the output of A2-HIC15850 in the DCS (which controls the TGCU Quench Column inlet and bypass valves) to 0% in preparation for the subsequent restart.
j.
Shuts down the TGCU Startup Blower, A2-GB1560; closes its suction valve (A2-HV15852), its discharge valve (A2-HV15854), and the nitrogen purge valve for the blower seal (A2-HV15856); and opens its bypass valve (A2-HV15853) and the nitrogen purge valve for the blower casing, (A2-HV15857).
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SULFUR BLOCK k.
11.5.5.3
Resets DCS toggle switches A2-HS15817, A2-HS15825, and A2-HS15809 to "OFF" and A2-HPB15855 to "STOP".
Non-ESD Shutdowns In addition to the devices listed in Section 11.5.5.1 that activate the TGCU ESD system, there are several interlocks of significance that either generate an alarm or shut down an individual piece of equipment. These devices/interlocks and their effects are described in this section. a.
TGCU Quench Column Low-Low Level, A2-LT15867A/B/C The TGCU Quench Water Pump (A2-GA1560A/B) could be damaged if the pump loses suction because the level in the TGCU Quench Column drops too low. These devices will protect the pump by stopping it before this can occur. The shutdown setpoint is 450 mm above the bottom seam of the column. Note that there are three independent transmitters and 2oo3 voting logic is used for the S/D (i.e., at least two transmitters must show low-low level) to avoid spurious "trips" due to the malfunction of a single transmitter.
b.
TGCU Quench A2-WSH15879
Water
Cooler
Fan
High
Vibration,
Each fan on the TGCU Quench Water Cooler (A2-EC1560) is provided with its own vibration switch. If the vibration sensed by the switch exceeds the preset level, the switch will trip to stop the associated fan and activate an alarm in the DCS. The fan will not restart until the vibration switch is reset by an operator. c.
TGCU Contactor Low-Low Level, A2-LT15895A/B/C The TGCU Rich Solvent Pump (A2-GA1561A/B) could be damaged if the pump loses suction because the level in the TGCU Contactor drops too low. These devices will protect the pump by stopping it before this can occur. The shutdown setpoint is 450 mm above the bottom seam of the column. Note that there are three independent transmitters and 2oo3 voting logic is used for the S/D.
d.
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TGCU Lean Solvent Cooler Fan High Vibration, A2-WSH15902
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SULFUR BLOCK Each fan on the TGCU Lean Solvent Cooler (A2-EC1561) is provided with its own vibration switch. If the vibration sensed by the switch exceeds the preset level, the switch will trip to stop the associated fan and activate an alarm in the DCS. The fan will not restart until the vibration switch is reset by an operator. e.
TGCU Stripper Low-Low Level, A2-LT15932A/B/C The TGCU Lean Solvent Pump (A2-GA1562A/B) could be damaged if the pump loses suction because the level in the TGCU Stripper drops too low. These devices will protect the pump by stopping it before this can occur. The shutdown setpoint is 450 mm above the bottom seam of the column. Note that there are three independent transmitters and 2oo3 voting logic is used for the S/D.
f.
TGCU Stripper A2-WSH15942
Reflux
Condenser
Fan
High
Vibration,
Each fan on the TGCU Stripper Reflux Condenser (A2-EC1562) is provided with its own vibration switch. If the vibration sensed by the switch exceeds the preset level, the switch will trip to stop the associated fan and activate an alarm in the DCS. The fan will not restart until the vibration switch is reset by an operator.
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SULFUR BLOCK
11.6 Process Principles and Operating Techniques The more important considerations involved in startup, operation, shutdown, maintenance, and emergency procedures for the TGCU are discussed in the remaining sections of this portion of the operating guidelines. The operator should also be thoroughly acquainted with the equipment and the "Process Description" section in these guidelines before attempting to operate the plant in accordance with the operating techniques that follow. If the function of each portion of the plant equipment is understood, the sequence of steps outlined in the "procedures" sections will be more easily understood. In addition, the following general discussion of principles and techniques will clarify the reasons for some of the procedures.
11.6.1
Equipment Damage After the initial startup, the front-end of the TGCU may contain some sulfur, including the catalyst bed in the TGCU Reactor. Sulfur fires will ignite at temperatures as low as 150°C if sufficient oxygen is available. In addition, TGCU catalyst is pyrophoric at ambient temperatures when in its sulfided state (which is its normal operating condition). For these reasons, it is very important to minimize the time periods when air (or other gases containing oxygen) is routed through the catalyst bed. Localized high temperatures can exist in the catalyst bed even though the temperatures measured around the reactor are low. Because of this, sulfur and/or catalyst ignition sometimes occurs in a catalyst bed when it is not anticipated by temperatures that are readily available for observation. Under ordinary circumstances, oxygen-bearing gases will only be flowing through the reactor when passivating its catalyst. When passivating the catalyst in the reactor, observe the reactor temperatures frequently. If the temperatures begin to increase above 150°C, reduce the amount of air entering the reactor to limit the passivation so that the reactor temperatures remain below 150°C. This will prevent the catalyst from reacting with oxygen so that pre-sulfiding is not required during the subsequent startup. Do not use water to quickly cool the TGCU Reactor after a fire. Not only will this damage the catalyst, the rapid cooling may cause structural damage to the TGCU Reactor. The acidic water that forms may cause corrosion damage to the TGCU Reactor or other equipment. Nitrogen is available to the TGCU for use in cooling a hot catalyst bed.
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SULFUR BLOCK
CAUTION NEVER "HYDROBLAST" THE TUBES (OR ANY OTHER STEEL SURFACES) IN THE TGCU EQUIPMENT. NOT ONLY DOES THIS REMOVE THE PROTECTIVE SULFIDE FILM THAT FORMS ON CARBON STEEL AND PREVENTS CORROSION, THE WATER WILL REACT WITH THE SULFUR COMPOUNDS PRESENT IN THE EQUIPMENT TO FORM A VARIETY OF ACIDS (SULFUROUS, POLYTHIONIC, ETC.) THAT RAPIDLY CORRODE THE STEEL. THERE HAVE BEEN NUMEROUS INSTANCES OF SULFUR PLANT BOILERS BEING BLASTED DURING A TURNAROUND TO CLEAN THEM UP, THEN HAVING THE TUBES BEGIN LEAKING AS SOON AS THE BOILER IS RETURNED TO SERVICE. IF THE TGCU WASTE HEAT RECLAIMER TUBES HAVE BECOME PLUGGED, THE BEST WAY TO CLEAR THE TUBES IS TO MECHANICALLY "ROD" THEM. IF SULFUR OR SULFUR COMPOUNDS HAVE PLUGGED THE TUBES, IT IS OFTEN HELPFUL TO APPLY HEAT TO THE TUBES BEFORE "RODDING", AS THIS WILL MELT ANY SULFUR THAT MAY BE PART OF WHAT HAS PLUGGED THE TUBES. ONE WAY TO DO THIS IS TO DRAIN THE WATER FROM THE BOILER AND PUT STEAM ON THE SHELL. DRAIN THE CONDENSATE PERIODICALLY TO KEEP LIVE STEAM ON THE TUBES.
11.6.2
Catalyst Fouling The catalyst bed in the TGCU Reactor may be severely fouled by carry-over of heavy hydrocarbon liquids or vapors. This will cause permanent damage to the catalyst and is to be avoided if possible, even if shutting down the TGCU for periods is required. The most common source of heavy hydrocarbons in TGCUs is contaminants in the reducing gas stream. The pressure drop across the TGCU Reactor should be monitored regularly to help detect this problem before the pressure drop becomes so high that a plant shutdown is required to remove the fouled catalyst.
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SULFUR BLOCK 11.6.3
TGCU Reactor Operation The purpose of the TGCU Reactor is to convert all of the sulfur compounds in the tailgas from both SRUs into hydrogen sulfide. This is accomplished by catalytic hydrogenation of the sulfur dioxide and sulfur vapor, and hydrolysis of the organic sulfur compounds: (1)
SO2 + 3 H2
H2S + 2 H2O
(2)
S + H2
H2S
(3)
COS + H2O
H2S + CO2
(4)
CS2 + 2 H2O
2 H2S + CO2
The catalyst also promotes the classic "water gas shift" reaction: (5)
CO + H2O
H2 + CO2
This effectively converts carbon monoxide in the tailgas gas into hydrogen for use in reactions (1) and (2) above. This is an equilibrium reaction, so it is typical for a small amount of CO to leave a reactor, depending on the amount of hydrogen and carbon dioxide in the reactor outlet. The CO concentration in the reactor outlet is usually less than 100 PPM, but may be higher if the CO2 content of the feed gas is high or if the catalyst has lost activity. NOTE:
A small portion of the COS and CS2 may either not react at all, or be reduced by the hydrogen to form methane and/or methyl mercaptan:
(6)
COS + 4 H2
CH4 + H2S + H2O
(7)
CS2 + 4 H2
CH4 + 2 H2S
(8)
COS + 3 H2
CH3SH + H2O
(9)
CS2 + 3 H2
CH3SH + H2S
These reactions should produce only a few PPM of methane and/or mercaptan unless there is a large amount of COS/CS2 in the SRU tailgas, or the TGCU catalyst has lost activity. Since the TGCU amine will not remove mercaptans from the gas, any mercaptans formed will escape to the Thermal Oxidizer and cause increased SO2 emissions. Methane in the reactor effluent may result in increased CO emissions from the Thermal
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SULFUR BLOCK Oxidizer (due to partial oxidation), depending on the operating conditions in the Thermal Oxidizer. To avoid these problems, the amount of COS/CS2 entering the TGCU should be maintained as low as possible by proper operation of the upstream SRUs (and amine and sour water stripping units). All of these reactions are exothermic, causing the temperature of the gas to rise as it flows through the reactor. The hydrogenation of the SO2 into H2S is the predominant factor in the temperature rise, so the temperature rise across the TGCU Reactor is usually a direct indication of the amount of SO2 entering the TGCU from the SRUs. If the temperature rise is higher than normal (about 50-60°C at design conditions), this is usually a sign that the upstream sulfur plant(s) is off-ratio. The resulting high outlet temperature from the TGCU Reactor cannot be corrected in the TGCU. Rather, the problem must be corrected in the SRUs, or the upstream units feeding the SRUs. Regardless of the amount of SO2, sulfur vapor, and organic sulfur entering the TGCU Reactor, all of it must be converted to H2S for proper operation of the downstream equipment. This can be achieved (assuming normal catalyst activity) by maintaining an adequate excess of hydrogen in the TGCU Reactor outlet, so that all of the reactions go to completion. The hydrogen concentration is normally measured in the treated gas leaving the TGCU Contactor. Although the design material balance calls for a hydrogen concentration of about 3% at this point, a concentration in the range of 1-2% is normally adequate. However, controlling the concentration at 3% or higher allows a much larger margin for tolerating upsets in the upstream SRUs, and is generally preferred. Unlike other TGCUs which use in-line burners to generate reducing gas (because external hydrogen is not available), this TGCU receives reducing gas from a hydrogen purification unit. However, poor ratio control in either SRU can still lead to an excessively high outlet temperature from the TGCU Reactor. If, for instance, an SRU is operating with excess air, the H2S:SO2 ratio will be low in the SRU tailgas (registered as high air demand) and the SO2 concentration will be high in the TGCU Reactor feed. This will cause a large temperature rise in the reactor. Left unchecked, the temperatures in the TGCU Reactor could rise to the point of damaging the catalyst, the catalyst bed support, and/or the reactor vessel itself. The thermocouples in the catalyst bed and in the outlet line have alarms to provide an early warning of this condition. If the
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SULFUR BLOCK temperature reaches 400°C in the outlet line, the TGCU ESD system will be activated to shut down the TGCU and divert the SRU tailgas to the Thermal Oxidizer, before damaging the TGCU Reactor or its catalyst. Be aware, however, that the "thermal mass" of the TGCU Reactor and its catalyst bed is quite large relative to the gas flowing through them, so temperature changes occur very slowly (particularly at low flow rates). For this reason, it is important to watch the temperature trends around the reactor and be prepared to take corrective action early so that the corrections have time to take effect before a high-high temperature shutdown is activated. It is particularly important to watch these temperatures closely during periods of startup, shutdown, or process upsets when the TGCU Reactor inlet temperature, composition, and/or flow rate are changing significantly.
11.6.4
TGCU Catalyst The active components for the hydrogenation reactions are cobalt and molybdenum sulfides in the cobalt/molybdenum catalyst. The catalyst is normally supplied by the catalyst vendor in its oxidized state, although some vendors can supply pre-sulfided catalyst. Contacting the catalyst with hydrogen at temperatures exceeding 200°C prior to sulfiding should be avoided to prevent impairing the catalyst activity, as hydrogen will irreversibly sinter the metal oxides to form metal hydrides that do not catalyze the TGCU reactions. Pre-sulfiding the catalyst before exposing it to hydrogen at high temperature yields a catalyst with stable, high activity. The catalyst is pre-sulfided by contacting it with an H2S-containing gas (such as the inlet amine acid gas to the SRUs) in the presence of hydrogen. During this operation, the following reactions occur: (1)
CoO + H2S
CoS + H2O
(2)
MoO3 + x H2S + (3-x) H2
1/n MonSn*x + 3 H2O
The molybdenum sulfide will probably be present in the form of Mo2S3, MoS2, and MoS3. These reactions are exothermic (heat liberating), so it is necessary to carefully control pre-sulfiding operations to prevent overheating the catalyst and/or equipment. The TGCU Startup Procedures Section of these guidelines contains a complete description of the suggested pre-sulfiding procedure.
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SULFUR BLOCK The catalyst should be exposed to air only under controlled conditions when it is in the reduced (sulfided) state as it is pyrophoric (capable of spontaneous ignition) and rapid oxidation could occur, causing damage to the catalyst, the TGCU Reactor, and/or the downstream equipment and piping. The pyrophoric nature of the catalyst is caused by the presence of iron sulfide (FeS), which gradually builds up in the catalyst due to accumulation of corrosion products from upstream equipment and piping. Controlled burn-off of the catalyst (passivation) to eliminate FeS can be accomplished by low-temperature oxidation which destroys the FeS but leaves the active Co/Mo sulfides intact. The TGCU Reactor can then be opened for maintenance, etc. The procedure to accomplish this catalyst "passivation" is fully described in TGCU Shutdown Procedures Section these guidelines. The catalyst activity should be monitored regularly so that there is forewarning of catalyst deactivation. Shell Global Solutions recommends using a gas chromatograph to analyze the gas downstream of the TGCU Reactor (TGCU Contactor overhead gas, for instance) for CO, H2, and COS. The CO/H2 ratio (PPM CO divided by vol % H2) and the COS PPM can then be plotted versus time. When the CO/H2 ratio and/or the COS PPM rise rapidly, preparations should be made to replace the TGCU catalyst within a few months.
11.6.5
TGCU Start-Up Blower Operation Prior to introducing SRU tailgas into the TGCU during startup, the equipment in the front-end of the unit must be brought up to operating temperature. This is accomplished by using the TGCU Start-Up Blower, A2-GB1560, to re-circulate gas from the outlet of the TGCU Waste Heat Reclaimer to the inlet of the TGCU Reactor Feed Heater (via the TGCU Warmup/Bypass Valve). This allows using the TGCU Reactor Feed Heater to heat the gas and thereby bring all the equipment up to operating temperature. A flow controller is provided to allow filling the front-end equipment and piping with nitrogen prior to establishing the re-circulation flow during startup. Once the tailgas from the SRU(s) is brought into the TGCU, the re-circulation from the TGCU Start-Up Blower is no longer needed, so the blower can then be shut down.
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SULFUR BLOCK 11.6.6
TGCU Quench Column Operation The operating conditions shown on the Process Flow Diagram for this system (in terms of circulation rate and water temperature) should generally be maintained. Decreasing the water circulation rate will increase the bottoms temperature (which increases the corrosion rate), while increasing the circulation rate increases the load on the pump and the coolers. The flow rate and temperatures shown are usually a good compromise between minimizing corrosion and minimizing utility costs. The quench water circulation rate is controlled by the quench water flow controller in the DCS, while the temperature is controlled by a temperature controller adjusting the speed of one of the fans on the TGCU Quench Water Cooler, A2-EC1560. Although the design values will give adequate operation, there are advantages in maintaining the quench water temperature (which controls the overhead temperature) as low as possible. These conditions will minimize the temperature and water content of the overhead gas leaving the TGCU Quench Column and thus minimize the load on the TGCU Contactor. The bottoms temperature of the TGCU Quench Column is not critical except for controlling corrosion; this temperature depends on the gas feed rate and the temperature and flow rate of the circulating quench water. However, operating the quench water at a lower or higher temperature than the TGCU lean amine can cause the TGCU amine system to be out of water balance. Normally, both the quench water and the TGCU amine should operate at roughly the same temperature to minimize the impact on the amine system water balance. A portion of the quench water is sent to SWS Flash Drum on level control to balance the water condensed from the process gas by the circulating quench water and maintain the bottoms level in the TGCU Quench Column. This "bleed" water rate depends on the amount of water in the SRU tailgas, and the amount of water contained in the gas leaving the column. The TGCU Quench Water Filter removes sulfur and particulates from the circulating quench water to maintain water clarity. The flow rate to the filter should be maintained at its design value to provide maximum filtration. The appearance of the circulating quench water is a good indicator of whether the TGCU Reactor is operating properly. A sight glass is
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SULFUR BLOCK provided to allow the operator to observe the condition of the water. If SO2 should escape from the TGCU Reactor, it will react with the H2S dissolved in the water to form sulfur: (1)
2 H2S + SO2
3 S + 2 H2O
This sulfur will be produced as tiny particles of solid sulfur, forming a colloidal suspension in the water and giving the water a milky appearance. The SO2 may also remain dissolved in the water and form a weak solution of sulfurous acid: (2)
H2O + SO2
H2SO3
If sufficient acid is formed to drop the pH of the quench water below 7, the acid will often scour the iron sulfide film (which normally protects the steel from corrosion) from the carbon steel equipment and piping. The iron sulfide particles will turn the quench water black (or green). Either color change (milky or black/green) is a symptom of SO2 "break-through" from the TGCU Reactor, meaning that inadequate reducing gas is being supplied to the reactor. An abnormal increase in the pressure drop across the TGCU Quench Water Filter is also a good indication of SO2 break-through, as the sulfur and/or iron sulfide particles collect on the filter elements. Should any of these events occur, immediately observe the readings on the air demand analyzers in the SRUs, the hydrogen analyzer in the TGCU, and the quench water pH analyzer. Make appropriate corrections to the air:acid gas ratio in the SRU(s), the hydrogen rate to the TGCU Reactor Feed Mixer, or both to eliminate the SO2 breakthrough. Also, begin (or increase) caustic injection into the quench water to raise the pH and minimize the corrosion to the system. Failure to maintain the proper pH (generally 8.0-9.5) will quickly damage the quench water equipment and piping due to acid corrosion, and may allow SO2 to reach the TGCU Contactor and form heat-stable salts with the amine. Heat-stable salts can cause accelerated corrosion in the TGCU amine system. If a large SO2 deviation occurs (very low pH, very dirty quench water, rapid plugging of the TGCU Quench Water Filter, etc.), it may be desirable to dilute the quench water with fresh condensate makeup. This accomplishes two things to facilitate cleanup of the quench water system: the fresh makeup will dilute the SO2 and help raise the pH, and the makeup will raise the level in the TGCU Quench Column and cause the quench water column level controller to increase the "bleed" rate of
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SULFUR BLOCK quench water to the Sour Water Stripping Unit. The rate at which condensate is added to the system must be regulated to keep the temperature to the circulating pump low enough that the pump does not cavitate. Experience will show how quickly condensate can be added without causing pumping problems. In this fashion, the TGCU Quench Column serves as a good scrubber preceding the TGCU Contactor to prevent minor upsets in the SRUs or the TGCU Reactor from degrading the TGCU amine with SO2. Nevertheless, the hydrogen and pH analyzers in the TGCU should be carefully observed and properly maintained to minimize the number and duration of pH excursions in the quench water system. This will maximize the service life of the quench water system and minimize the degradation of the amine. In addition, consider diverting the process gas from the TGCU Reactor to the Thermal Oxidizer before it enters the TGCU Quench Column during periods of large upsets when SO2 may break through the reactor, before SO2 gets into the quench water and causes problems. Taking this preventative measure will cause higher SO2 emissions from the Thermal Oxidizer and put it out of compliance, but it will allow the TGCU to be brought back to normal operation much more quickly by avoiding a pH excursion in the quench system and the water cleanup operation that often results (i.e., numerous filter changes in the TGCU Quench Water Filter). When the TGCU is operating in "normal" mode, the TGCU Reactor effluent can be diverted directly to the Thermal Oxidizer simply by reducing the output on the Quench Column bypass hand controller in the DCS to 0%. This will open the TGCU Quench Column bypass valve, and close the TGCU Quench Column inlet valve. Since the TGCU Start-Up Blower bypass valve is open when the blower is not operating, this gives the process gas a path to flow to the Thermal Oxidizer. The TGCU Reactor effluent will then be diverted to the Thermal Oxidizer and cannot cause problems in the TGCU columns if SO2 escapes from the reactor. Once the upset has been corrected and gas flow into the columns can be re-initiated by increasing the output on the Quench Column bypass hand controller in the DCS to 100% output to restore flow to the columns. These changes should be performed slowly enough to minimize the "bobbles" on the air:acid gas ratio control in the SRUs, as the operating pressures in the units will change as the valves are
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SULFUR BLOCK repositioned. Operator judgment should be used to determine whether the process upset or the diversion of the process gas will have the worse impact on TGCU operation and the duration of non-compliance due to SO2 emissions from the Thermal Oxidizer.
11.6.7
TGCU Contactor Operation The main requirement for the TGCU Contactor is to consistently produce a vent gas for incineration which contains a low level of residual H2S. Secondarily, a good degree of CO2 "slip" (rejection) to the vent gas is desirable to minimize CO2 buildup due to the recycle of acid gas to the upstream Claus sulfur plant. The important parameters for controlling the H2S content of the TGCU Contactor vent gas, assuming the amine is adequately stripped, are amine temperature, amine flow rate, and contact time. The design values for amine temperature and flow rate shown on the Process Flow Diagram should give satisfactory operation, but it is possible to adjust these values either to maximize the capacity of the system to tolerate upsets, or to optimize the "slipping" of CO2 to the vent gas. The following discussion should be helpful if improving plant operations is desired. The single most important factor determining the H2S-absorbing capacity of the amine is its temperature. The lower the temperature of the amine, the more favorable is its selectivity for absorbing H2S over CO2. In fact, lowering the amine temperature has a two-fold effect on improving its ability to absorb H2S. First, at lower temperature the partial pressure of H2S in the amine is lower, allowing the amine to treat the gas to a lower H2S content (since the vent gas approaches equilibrium with the amine in the top of the TGCU Contactor). Second, the higher selectivity at the lower temperature means the amine picks up less CO2, resulting in less heat of reaction and less temperature rise in the column, increasing the ability of the amine to pick up H2S. Thus, the best possible operation results when both the gas and the amine fed to the TGCU Contactor are as cool as possible. For this reason, many operators leave the quench water and amine coolers at full capacity so that the coolers provide maximum cooling year-round. As would be expected, keeping the amine circulation rate at its maximum value gives the amine system the highest capacity to handle H2S "peaks" due to upsets in the upstream systems. It may not be immediately apparent, however, that high circulation rates are detrimental to amine
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SULFUR BLOCK performance when plant throughput is lower. Circulating more amine than necessary increases the amount of CO2 absorbed by the amine by increasing the contact time in the TGCU Contactor. This increase in CO2 pickup reduces the ability of the amine to pick up H2S. In general, most companies favor operating TGCU amine systems to provide maximum ability to tolerate upsets without going out of compliance. These companies adhere to the following guidelines: (1)
Circulate amine at maximum capacity.
(2)
Cool the quench water and amine as much as possible.
The amine strength should be monitored and the amine content of the circulating amine should be maintained close to the 45% (by weight) design value. Should the amine concentration decrease (normally due to blowdown and other amine losses), it will be necessary to add fresh amine to compensate. Laboratory procedures for analyzing TGCU amine are given in Section 11.10 of these guidelines. The amine should also be checked periodically for heat-stable salt content. Heat-stable salts form when the amine in the amine (a base) reacts with strong acids to form salts that do not decompose at the normal amine regeneration temperature. The most common heat-stable salts encountered in TGCU amine systems are SO2 salts, although oxygen contamination of the amine is another common culprit for heat-stable salts in these systems. Heat-stable salts increase the corrosivity of the amine (particularly at higher temperatures, like in the TGCU Stripper Reboiler) and increase the foaming tendencies of the amine. (Interestingly, heat-stable salts sometimes improve the H2S-removal capability of the amine, but the higher corrosion rate caused by the salt far outweighs this advantage.) A heat-stable salt content of 2 wt % or lower is desirable. Salt contents in the 5-20 wt % range can be corrosive and should be avoided if possible. The only way to reduce the heat-stable salt content of the amine is by dilution, blowing down some of the circulating amine and making up with fresh amine. There is no means for regenerating heat-stable salt from the amine while it is in the TGCU, as vacuum distillation is required. (In recent years, however, several companies have successfully reclaimed amine on-line using ion exchange on a slipstream of the amine.) There are firms that specialize in reclaiming amine (usually off-site), and it may be economical to use such a firm if a large amount of amine has been
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SULFUR BLOCK contaminated with heat-stable salts. The best practice, however, is to avoid forming heat-stable salt in the first place by proper operation of the SRU and TGCU to avoid SO2 breakthrough from the TGCU Reactor, and gas-blanketing the fresh amine to avoid oxygen contamination. The H2/H2S analyzer on the TGCU Contactor overhead, measures the concentrations of both H2 and H2S in the vent gas leaving the TGCU Contactor. As such, it is an extremely useful troubleshooting and optimizing tool for the TGCU. This analyzer should be maintained and calibrated at appropriate intervals so that it will be on-line and available to the operators. The H2S concentration is particularly useful when trying to pinpoint the cause of high SO2 emissions from the Thermal Oxidizer, as the TGCU Contactor is not the only possible source of high emissions. There are several valves in the SRU and the TGCU that can allow process gases with high sulfur content to reach the Thermal Oxidizer if the valves leak or are not fully closed. If the SO2 emissions from the Thermal Oxidizer are high but the analyzer shows low H2S content in the TGCU Contactor overhead, then a leaking valve is the most likely source of the excessive sulfur reaching the Thermal Oxidizer. In particular, the automated bypass valves in the TGCU may open slightly if their positioners or actuators are not properly adjusted, or if sudden changes in ambient conditions cause the positioners to move the valves slightly. If this situation occurs, it is suggested (as the first step in troubleshooting the problem) that the following valves be "stroked" slightly (in the order given below) to be sure that they are fully closed:
Issued 30 August 2011
(1)
A2-NV15800
The TGCU Warmup/Bypass Valve can leak SRU tailgas directly to the Thermal Oxidizer.
(2)
A2-HV15851
If the TGCU Start-Up Blower is not operating and A2-HV15853 is open ("normal" mode operation), the TGCU Quench Column Bypass Valve can leak TGCU Reactor effluent directly to the Thermal Oxidizer.
(3)
A2-HV15457 A2-HV15657
The Tailgas Valve to the TTO can leak SRU tailgas directly to the Thermal Oxidizer.
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SULFUR BLOCK (4)
A2-HV15441/641 A2-HV15454/654
The SRU Warmup Bypass Valves to the TTO can leak SRU process gas directly to the Thermal Oxidizer if the nitrogen purge fails or is inadequate.
Check the SO2 emissions after stroking each valve. If the emissions are still high after checking all the valves, then verify that both the H2S analyzer and the SO2 analyzer are calibrated properly. If these valves are not leaking, there is usually no obvious reason why these two analyzers should show a discrepancy in the sulfur content of the TGCU effluent. In such cases, a systematic sampling program is usually required to isolate the source of the sulfur entering the Thermal Oxidizer. This sampling program need not be elaborate, as gas detector tubes for H2S and SO2 (such as Dräger tubes) are often sufficient for this purpose. The main point is to start at the TGCU Contactor overhead and work toward the Thermal Oxidizer, taking gas samples at each spot where gas may enter the line, in order to determine when the sulfur content goes up and isolate the source of the sulfur. Some detective work may still be necessary, however, as there may not be sample points available at every location. If so, and if there are several episodes of high emissions requiring this type of sampling, consideration should be given to installing additional sample points during the next plant turnaround.
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SULFUR BLOCK 11.6.8
TGCU Stripper Operation The lean amine must remain comparatively free of H2S and CO2 to assure attainment of the vent gas specification. These acid gases are removed from the rich amine in the TGCU Stripper by stripping them out with steam. The stripping steam supplies heat to reverse the acid-base reaction between the H2S/CO2 and the amine, and also reduces the H2S/CO2 partial pressure in the vapor phase inside the column to promote mass transfer from the liquid. The stripping steam is produced by vaporizing some of the water in the amine in the TGCU Stripper Reboiler, using LP (3.5-4.2 kg/cm2(g)) steam for the heat input. The steam rate to the reboiler (and, hence, the amine stripping rate) is controlled by the steam flow controller. Adjust this steam rate as needed to keep the H2S and CO2 loading in the lean amine low, i.e., below about 0.005 mole/mole or lower. For a given column operating pressure, the overhead temperature is a direct indication of the stripping rate: the higher the temperature, the more stripping. Column bottoms temperature should not be used as a guideline for degree of stripping, as it is a function only of amine concentration and column pressure.
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SULFUR BLOCK
CAUTION THE DESIGN STRIPPING STEAM RATE SHOWN ON THE PROCESS FLOW DIAGRAM SHOULD BE CLOSE TO OPTIMUM. ALTHOUGH IT MAY BE POSSIBLE TO REDUCE THIS SOMEWHAT WITHOUT GOING OUT OF COMPLIANCE (I.E., WITH LITTLE CHANGE IN THE H2S LOADING OF THE LEAN AMINE), REDUCING THE STRIPPING STEAM RATE SIGNIFICANTLY CAN CAUSE ACCELERATED CORROSION DUE TO HIGH CO2 LOADINGS IN THE LEAN AMINE. SEVERAL PLANTS HAVE REPORTED UNEXPECTEDLY HIGH CORROSION RATES IN THE HOT, HIGH VELOCITY AREAS OF THE LEAN AMINE SYSTEM, SUCH AS THE OUTLET ENDS OF THE REBOILER TUBES AND THE LEAN AMINE PUMPS, AFTER REDUCING THE REBOILER STEAM. IF IT IS NECESSARY TO OPTIMIZE THE STEAM TO THE TGCU STRIPPER REBOILER, REDUCE THE STEAM BY SMALL INCREMENTS AND CHECK THE LEAN AMINE LOADINGS (BOTH H2S AND CO2) AFTER EACH CHANGE. DO NOT REDUCE THE STEAM FURTHER IF EITHER LOADING BEGINS TO RISE SIGNIFICANTLY, AND BE PREPARED TO PERFORM MORE EXTENSIVE CORROSION MONITORING WHEN OPERATING THE TGCU STRIPPER IN THIS MANNER. REFER TO SECTION 11.10 OF THESE GUIDELINES FOR THE PROCEDURES TO BE USED TO DETERMINE THE LEAN AMINE LOADINGS. The withdrawal of lean amine from the bottom of the TGCU Stripper is on flow control to the TGCU Contactor. As a result, the level in the bottom of the TGCU Stripper, which serves as the "surge" for the system, will usually indicate if adjustments of water makeup to the amine system (or water "bleed" from the system) are required to maintain the proper water balance. Even if water must be bled from the system by diverting some of the column reflux to The SWS Flash Drum, the amine content of that waste stream should be low and only infrequent makeup of fresh amine should be required. It may also be necessary to "purge" ammonia from the reflux water periodically by routing some of the reflux water to the Sour Water Stripper.
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SULFUR BLOCK Although the two-zone Reactor Furnaces in the SRUs will normally destroy almost all of the ammonia entering with the SWS gas, PPM levels of ammonia will typically leave the furnace and enter the TGCU with the sulfur plant tailgas. This ammonia is usually removed by the circulating water in the TGCU Quench Column, where it has the beneficial effect of helping maintain a high pH in the quench water. In fact, ammonia (rather than caustic) is used for pH control in many TGCUs. Over a period of time, however, some of the ammonia may carry over into the TGCU Contactor and dissolve in the TGCU amine. When this ammonia-containing amine reaches the TGCU Stripper, the ammonia becomes "trapped" because it is too light (volatile) to leave in the column bottoms and too heavy to leave in the overhead (the acid gas). As a result, the ammonia will become concentrated in the reflux water, to the point where it exceeds its solubility limits and begins to cause plugging problems. If this problem is suspected, simply "bleed" a small amount of the reflux water to the disposal header to purge the ammonia from the system, while monitoring the reflux flow rate to ensure that adequate reflux is maintained to the TGCU Stripper. Operating experience will show how often (and how much) the reflux must be purged in this manner to prevent excessive ammonia concentrations for a particular plant. Due to the moderate temperatures and fluid velocities typical for this section of the plant, wet H2S-NH3 corrosion is usually not a concern. There is full-flow of rich amine through the TGCU Rich Amine Filter, and a slipstream of lean amine flow through the TGCU Lean Amine Filter, the TGCU Amine Carbon Filter, and the TGCU Amine After-Filter. These four filters will remove solids and organic contaminants from the circulating amine, such as degradation or corrosion products. The flow rate through the lean amine filters should be maintained at the design value, and the filter elements should be changed as soon as the "change" pressure drop is reached, to remove as many solids from the amine as possible. Finely divided solids can cause foaming and thereby limit column capacity. While it is possible to reduce foaming to some extent with anti-foam agents, the presence of such agents may also reduce H2S/CO2 selectivity in the TGCU Contactor, so it is preferable that they not be used as an alternative to regular conscientious filter maintenance
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SULFUR BLOCK 11.6.9
TGCU Amine Water Balance The water content of the circulating amine in a TGCU is determined by the following factors: A.
The water content of the feed gas to the TGCU Contactor (the overhead from the TGCU Quench Column).
B.
The water content of the vent gas leaving the TGCU Contactor.
C.
The water content of the TGCU recycle gas leaving the TGCU Stripper Reflux Accumulator.
D.
The amount of water makeup to (or water "bleed" from) the amine system.
For given operating pressures, the water content of each gas stream will be determined by the temperature at the top of the respective vessel (TGCU Quench Column, TGCU Contactor, and TGCU Stripper Reflux Accumulator, respectively), and will increase as the temperature increases. Since the TGCU Contactor inlet gas is at a slightly higher pressure than the outlet (vent) gas, the inlet gas will normally contain less water than is contained in the outlet gas (if both gas streams are at the same temperature), thus requiring water makeup to maintain the proper water content of the amine. This situation will be reversed if the TGCU Contactor overhead temperature is lower than the TGCU Quench Column overhead temperature, requiring a "bleed" of water to maintain water balance. Since the lean amine to the TGCU Contactor is on flow control and withdrawal of the rich amine from the bottom of the TGCU Contactor is on level control, a net gain or loss in the amine water balance will be reflected by an increase or decrease, respectively, of the liquid level in the bottom of the TGCU Stripper. Observation of this liquid level can thus guide adjustment of water makeup/bleed rate or operating conditions to maintain the desired water concentration of the circulating amine. Since the degree of H2S removal can depend on the amine concentration of the amine, the concentration should be maintained close to the design value (45 wt %) by appropriate maintenance of water concentration. It is usually possible to control the water balance without adding fresh water or "bleeding" water to the Sour Water Stripping Unit by adjusting the operating temperatures in the unit, as discussed in the following paragraphs. Following the steps outlined below will allow controlling the water balance with minimum
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SULFUR BLOCK usage of treated makeup water and minimum impact on the sour water system. A persistently increasing liquid level in the bottom of the TGCU Stripper at constant flow rates and conditions for TGCU Contactor feed gas and amine indicates a gain in the amine water content. To reduce the water content of the amine, the preferred sequence of gradual adjustments is: A.
Reduce or terminate water makeup to the amine. Makeup water is steam condensate, added at the TGCU Stripper Reflux Accumulator. (1)
Decrease the TGCU Contactor feed gas temperature by lowering the quench water temperature on the quench water temperature controller and/or increasing the quench water flow rate on the quench water flow controller. This will reduce the amount of water entering the TGCU Contactor, but the magnitude of adjustment available from this step will generally be limited by the capacity of the aerial and trim water coolers.
(2)
Begin "bleeding" water (or increase the "bleed" water rate) from the amine system with the flow controller on the discharge line of the TGCU Stripper Reflux Pump. Be careful, however, not to starve the TGCU Stripper for reflux by withdrawing too much water. Use the DCS flow indicator for the reflux water to monitor the operation so that adequate reflux is maintained to the TGCU Stripper when bleeding water from the amine system.
CAUTION
UNDER NORMAL CONDITIONS, THE REFLUX WATER CONTAINS LITTLE OR NO AMINE BECAUSE OF THE "WASH WATER" TRAYS ABOVE THE SOLVENT FEED TRAY IN THE TGCU STRIPPER. HOWEVER, IF THE TGCU STRIPPER IS FLOODING OR FOAMING (AS INDICATED BY HIGH OR ERRATIC COLUMN DIFFERENTIAL PRESSURE), THE REFLUX CAN CONTAIN LARGE AMOUNTS OF AMINE.
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SULFUR BLOCK IF THE "BLEED" WATER LINE IS IN USE AT SUCH TIMES, A SIGNIFICANT QUANTITY OF SOLVENT CAN BE LOST TO THE SOUR WATER SYSTEM, AND WILL HAVE TO BE REPLACED WITH FRESH AMINE FROM THE STORAGE TANK. FOR THIS REASON, THE "BLEED" WATER SYSTEM SHOULD BE BLOCKED-IN DURING UPSETS IN THE TGCU STRIPPER. (3)
Increase the TGCU Contactor overhead temperature by raising the setpoint of the lean solvent temperature controller to increase the lean solvent temperature. This will increase the amount of water leaving in the vent gas, but it will also reduce the H2S-removal capability of the solvent. An increase in solvent flow rate will probably be needed to maintain the same H2S content in the vent gas, increasing the load on the TGCU Stripper and the other process equipment associated with the circulating solvent. Additionally, some impairment of the CO2 "slip" by the solvent would be expected as a result of both the higher contact temperatures in the TGCU Contactor and the higher solvent circulation. This will increase the CO2 recycled to the sulfur plants and increase the CO2 content of the tailgas to the TGCU, further hampering the H2S-removal capability of the solvent.
(4)
Increase the TGCU recycle gas temperature by increasing the temperature setpoint of the reflux temperature controller to raise the outlet temperature from the TGCU Stripper Reflux Condenser. Although this will increase the water content of this stream and reduce the water in the solvent, the effect will be small because the quantity of recycle gas is small relative to the vent gas, and the pressure of the recycle gas is considerably higher. This adjustment is the least effective and would not normally be considered during routine operations.
(5)
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Should the solvent inventory be difficult to control due to continuing problems with an excessive amount of water in the solvent, the steam-heated TGCU Stripper Reboiler should be checked for tube leaks.
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SULFUR BLOCK B.
Conversely, a persistently decreasing liquid level in the bottom of the TGCU Stripper indicates a loss in the solvent water content. To increase the water content of the solvent, the preferred sequence of gradual adjustments is: 1.
Reduce or terminate the "bleed" water from the TGCU Stripper Reflux Accumulator.
2.
Decrease the TGCU Contactor overhead temperature by lowering the lean solvent temperature with the lean solvent temperature controller to reduce the amount of water leaving in the vent gas.
3.
Decrease the TGCU recycle gas temperature with the aerial cooling from the TGCU Stripper Reflux Condenser to reduce the water loss in the stream as much as possible.
4.
Begin water makeup (or increase the makeup water rate) to the solvent system using the make-up flow controller to add condensate to the TGCU Stripper Reflux Accumulator. The TGCU Stripper Reflux Pump will then send the makeup water to the TGCU Stripper, increasing the water content of the TGCU solvent. Be careful, however, to regulate the makeup rate so that the temperature to the pump does not become hot enough to cause cavitation. Also, make sure that the makeup water rate is not so high that the pump cannot keep up, which would cause high level in the TGCU Stripper Reflux Accumulator. Experience will show how quickly condensate can be added without causing pumping or level problems.
5.
Increase the TGCU Contactor feed temperature by increasing the temperature of the quench water feeding the TGCU Quench Column by raising the setpoint of the quench water temperature controller. This will increase the water content of the gas entering the TGCU Contactor, but it also increases the vapor load and hampers H2S removal, so this step should not be taken to extremes.
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SULFUR BLOCK 11.6.10 TGCU Amine Loss At the low process temperatures and low amine loadings normally prevailing in the TGCU process, the loss of MDEA by chemical degradation is expected to be negligible. Amine degradation can occur, however, under abnormal operating conditions. Amine degradation can occur via reaction with SO2, which can enter the TGCU Contactor during periods when insufficient reducing gas is fed to the TGCU Reactor. During such periods, most of the SO2 "breaking through" the TGCU Reactor should be scrubbed out in the TGCU Quench Column. However, any traces of SO2 entering the TGCU Contactor will react with the MDEA to form a thermally non-regenerable complex (i.e., heat-stable salt). If present in sufficient quantity, this salt can alter the H2S-amine equilibrium and prevent removal of H2S to the desired level in the TGCU Contactor overhead. Heat-stable salts also increase the corrosivity of the TGCU amine. Amine quality can be restored by treatment with an amount of caustic equivalent to the non-regenerable salt present but, if repeated caustic treatments are necessary due to repeated mal-operation, the potential for salt deposition in the system may rise. The equipment in the TGCU, including the seals of pumps and blowers, should be operated at positive pressure to minimize the potential for oxygen (air) ingress into the amine. Oxygen will react with the amine to produce carboxylic acids that cause the solution to be corrosive. For this same reason, it is important to maintain an inert gas "blanket" on the MDEA storage tank to prevent oxygen contamination of the fresh amine. Amine losses due to entrainment in the vent gas or the recycle gas can be minimized by proper process operation (avoidance of column overloading, foaming, etc.) and routine inspection of the vessel internals. Amine losses in the water "bleed" from the TGCU Stripper reflux should be negligible if the rectifying trays (the "wash water" trays above the amine feed point) in the TGCU Stripper are operating properly (no flooding or foaming, no mechanical damage). The primary source of amine loss will likely be the mechanical losses from pump drips, cleaning of filters, etc. Good housekeeping practices, including prompt replacement or repair of leaking pumps, together with proper collection of amine drips for reuse will minimize the mechanical loss of amine.
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SULFUR BLOCK 11.6.11 Operation at Low Flow Rates As discussed in the Sulfur Recovery Unit section of these guidelines, operating the SRUs at low flow rates (below about 20-25% of design load) can lead to several operating problems in the sulfur plant. It can also cause poor column performance in the TGCU. The TGCU contains three columns: the TGCU Quench Column and the TGCU Contactor, which contain structured packing; and the TGCU Stripper, which contains valve trays. In general, the liquid feed rate to packed towers can decrease in proportion with the gas flow rate down to about 50% of design gas flow rate. Below this point, the liquid rate cannot be allowed to drop any further without risking poor column performance due to uneven liquid distribution and wetting of the packing. Trayed towers typically offer somewhat better turndown, allowing the liquid rate to drop to 30-40% of design before "weeping" of the trays begins to significantly affect performance. At a total acid gas feed rate of 14 MT/D (of contained sulfur) to the SRUs, the gas flow rates to the TGCU Quench Column and the TGCU Contactor will be about 40% of design. In the case of the TGCU Quench Column, simply setting the quench water flow rate to the column at about 50% of design should maintain adequate performance. (It should be noted, however, that there is really no detrimental effect if the quench water circulation is simply left at the design value at all times. The only drawback is slightly higher power consumption by the pump and aerial cooler.) In the packed TGCU Contactor, circulating more amine relative to the gas flow rate should maintain performance. The liquid flow rate should be maintained at a minimum of about 50%. This higher amine circulation also has the advantage of absorbing more CO2 from the TGCU Contactor feed, which is subsequently stripped from the amine and recycled back to the SRUs. While TGCUs are normally operated to minimize CO2 pickup, increasing the CO2 pickup in this situation is advantageous. It raises the mass flow rate in the SRUs and the TGCU, minimizing the operating problems throughout the SRU/TGCU systems by preventing sulfur fog formation in the Sulfur Condensers. A higher circulation rate also means the TGCU has more capacity to remove H2S from the amine, making it less likely that SRU upsets will cause SO2
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SULFUR BLOCK emissions to exceed permit limits. It will also keep the TGCU Stripper trays well above their minimum operating rate.
11.6.12 Pressure Drop Surveys A commonly encountered problem in TGCUs (and sulfur plants and Thermal Oxidizers) is a flow restriction due to high pressure drop. High pressure drop is typically caused by a restriction at one point in the equipment or piping, due to: 1.
Accumulation of liquid (sulfur, etc.) in equipment or piping
2.
Partial plugging of a catalyst bed (soot, carbon, polymers, etc.)
3.
Partial plugging of a mist eliminator (sulfur, soot, catalyst, etc.)
4.
Partial plugging of the packing and/or trays in a column
5.
Flooding or foaming in a column
The first step in identifying the cause of the high pressure drop is to determine which equipment pass or section of piping contains the restriction. (It is unusual to have more than one area of high pressure drop.) This is best accomplished by making a pressure survey of the process side of the TGCU (and the SRUs and Thermal Oxidizer, if necessary). Due to the low operating pressure in the TGCU (generally 0.3 kg/cm2(g) or less) and the low pressure drop in each equipment pass (generally 0.00-0.04 kg/cm2 per pass), a single pressure gauge must be used to make the pressure survey in order to get meaningful results. The gauge should be a low pressure gauge for best results (a -1 - 0 - +1.5 kg/cm2 gauge is recommended). Beginning at the front end of the TGCU, use the pressure tap valves on the inlet and outlet lines from each equipment pass to measure the pressure at each point in the process. Proceed toward the back end of the process until the pass with the high pressure drop is found. Note that some of the pressure tap valves may be plugged with solid sulfur. Rod-out the sample valves as necessary to obtain an accurate pressure reading.
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SULFUR BLOCK
WARNING ALWAYS OBSERVE PROPER PROCEDURES AND PRECAUTIONS WHEN USING THE PRESSURE TAP VALVES, PARTICULARLY IF THE VALVES ARE PLUGGED AND MUST BE CLEARED. ALTHOUGH THE VALVES ARE ORIENTED TO MINIMIZE THE POSSIBILITY OF FILLING WITH MOLTEN SULFUR, HOT SULFUR MAY SUDDENLY BE EXPELLED FROM A VALVE WHEN THE PLUG IS CLEARED. RELEASE OF TOXIC GASES (H2S AND SO2, IN PARTICULAR) IS ALSO A POSSIBILITY. THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES SHOULD BE CONSULTED IF THERE IS ANY DOUBT ABOUT HOW TO WORK SAFELY WHEN H2S, SO2, OR MOLTEN SULFUR MAY BE PRESENT. When troubleshooting problems of this nature, it is very helpful to have pressure survey information taken previously when the unit was operating properly. It is recommended that one or more pressure surveys be performed early in the operating life of the plant, for comparison purposes later if problems are encountered. Since the pressure drop of the TGCU is a function of plant throughput (pressure drop is roughly proportional to flow rate squared), it is even more helpful for troubleshooting purposes if the early pressure surveys are performed at different plant throughput rates. It is also important to record the gas flow rates to the SRUs (amine acid gas, SWS gas, process air) and the TGCU (reducing gas) during the pressure survey, since pressure drop depends so strongly on plant throughput.
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SULFUR BLOCK 11.6.13 Boiler Water Treatment SAMSUNG TOTAL PETROCHEMICALS CO., LTD. IS RESPONSIBLE FOR ESTABLISHING AND MONITORING THE BOILER AND WATER CHEMICAL TREATMENT PROGRAM. Proper boiler water chemical treatment is essential to achieving long service life for the TGCU Waste Heat Reclaimer. Without good day-to-day control of the water quality, solids buildup, corrosion, and attack by the treating chemicals themselves can occur. It is Samsung Total Petrochemicals Co., Ltd.'s responsibility to see that a proper chemical treating program is initiated prior to startup and that the program is properly monitored and refined throughout the service life of the plant. There are many qualified boiler and water treatment companies that can advise the owner/operator on chemical treatment testing and controls. It is recommend that only those companies that have local technicians with extensive experience specifically in boiler water treatment be selected to assist with Samsung Total Petrochemicals Co., Ltd.'s program. The design details incorporated in the TGCU Waste Heat Reclaimer have proven to be very reliable when combined with good operator practice regarding water treatment. However, even properly designed equipment can be severely damaged during a short period of operation if the water treatment program is inadequate or improper. The TGCU Waste Heat Reclaimer is equipped with a continuous blowdown valve to remove suspended and dissolved solids from the water inside the boiler. In addition, this boiler is equipped with an intermittent blowdown valve. The intermittent blowdown valve should be used on a regular basis to give the boiler a good "blow" to prevent sludge from accumulating in the bottom of its shell. Prior to using the intermittent blowdown valve, use the level controller in the DCS to raise the water level in the boiler up to the high level alarm point. Then open the intermittent blowdown valve until the level drops back to the normal liquid level. Watch the boiler level in the sight glass throughout this operation to ensure that the level is not lost (which would activate the TGCU ESD and shut the TGCU down). Remember to reset the level controller at the conclusion of this procedure.
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SULFUR BLOCK
11.7 Precommissioning Procedures Prior to the initial startup, there are a number of precommissioning activities that are necessary to ensure that the newly constructed plant is ready to be placed in service. The activities outlined below should serve as a guide, but there may be others required as a part of your normal plant procedures.
11.7.1
Preliminary Check-out Check all equipment to ensure that it is properly installed. This will probably require consulting Manufacturer's literature as well as construction drawings.
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A.
Check and lubricate all equipment, in accordance with the Manufacturer's recommendations.
B.
Check the rotation of the TGCU Start-Up Blower by operating it for a short period (20 seconds or less) with its suction and discharge valves closed:
C.
Check the rotation of the following pumps by "bumping" them: (1) (2)
TGCU Quench Water Pump. TGCU Rich Amine Pump.
(3) (4)
TGCU Stripper Reflux Pump. TGCU Lean Amine Pump.
D.
Check the rotation of the fans on the TGCU Quench Water Cooler, the TGCU Lean Amine Cooler, and the TGCU Stripper Reflux Condenser, by operating each fan for a short period.
E.
Check all piping and equipment to be sure that all blinds have been removed and that no valves are vented to atmosphere.
F.
Place the Instrument Air System in service to all instruments and check the action of controllers and control valves.
G.
Turn on the steam supplies to all of the steam-jacketed sulfur vapor valves and use the vent valves on each jacket section to vent the air from the jackets. Manually "stroke" each valve and check to be sure each move freely.
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SULFUR BLOCK 11.7.2
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Shutdown System Check-out A.
Fill the TGCU Waste Heat Reclaimer with treated boiler feed water up to the high level alarm point. As the level rises, check the level transmitters and the high level alarms for proper operation.
B.
Use the quick-opening blowdown valve to lower the water level in the boiler and check for proper operation of the level transmitters, the low level alarms, and the low-low level shutdowns.
C.
Fill the boiler with treated boiler feed water back up to the normal liquid level.
D.
Physically check all shutdown activating devices to ensure that they activate the TGCU ESD system.
E.
Physically check all devices activated by the TGCU ESD system to ensure that they operate properly.
F.
Check all relief valves to ensure that they are installed in the proper locations and set for the correct relieving pressures.
G.
The low-low level shutdowns for the pumps in the quench water and amine systems will be tested while washing these systems as described in the following sections.
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SULFUR BLOCK 11.7.3
Commissioning Nitrogen and Utility Air to the Process The nitrogen and utility air supplies to the process side of the TGCU must be made ready for use prior to starting up the TGCU using the procedures in Section 11.8 of these guidelines. This requires blowing down each section of piping to ensure that there are no liquids and/or construction debris in the headers and supply lines. The procedure below can be used to make sure that these gas utility systems are ready for service.
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A.
Place the utility air controller in the DCS in "manual" and set its output to 0%.
B.
Place the nitrogen controller in the DCS in "manual" and set its output to 0%.
C.
Confirm that the following nitrogen and utility air valves are closed: (1)
The upstream block valve, flow control valve, and the downstream block valve in the nitrogen supply line.
(2)
The upstream block valve, flow control valve, and the downstream block valve in the utility air supply line.
(3)
The automated block valves, and the steam-jacketed block valve in the common nitrogen / air line.
(4)
The block valve in the HP nitrogen supply line located near the TGCU Reactor.
(5)
The gate valves upstream and the ball valves downstream of the flow indicators in the purges to the sensing lines for the TGCU Reactor d/P transmitter.
(6)
The ball valves in the sensing lines for the TGCU Reactor d/P transmitter.
(7)
The gate and ball valves in the purge line to the shaft seal on the TGCU Start-Up Blower.
(8)
The gate valve in the LP nitrogen supply line, and the ball valve downstream of the flow indicator in the purge line to the TGCU Start-Up Blower discharge line.
(9)
The gate valve upstream of the flow indicator in the supply line to the sample switching valve for the H2/H2S analyzer.
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SULFUR BLOCK (10) The block valves in the nitrogen supply line to the TGCU Stripper Reflux Accumulator.
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D.
Confirm that all of the manual vent/drain valves in the nitrogen and utility air piping are closed.
E.
If the orifice plate has already been installed in the utility air flow meter, remove it for now
F.
If the orifice plate has already been installed in the nitrogen flow meter, remove it for now
G.
Disconnect the nitrogen and utility air from the tailgas line by performing the following steps: (1)
Unbolt the flanged connections at the steam jacketed block valve and "drop out" this valve.
(2)
Isolate and, if necessary, disconnect the steam supply and condensate return connections for this valve.
(3)
Cover the open end of the piping to prevent debris from entering when the upstream piping is blown down.
H.
Confirm that the H.P. nitrogen, L.P. nitrogen, and Utility Air supply headers have been placed in service, with the pressure regulators set properly and the safety relief valves in service, and with the main supply header piping blown down and drained.
I.
Rotate the spectacle blind in the utility air line to the "open" position.
J.
Remove the following pressure regulators, then cover the downstream piping to prevent debris from entering when the upstream piping is blown down: (1)
The utility air supply regulator.
(2)
The nitrogen supply regulator.
K.
"Force" the PLC to open the two nitrogen blocks, and close the nitrogen vent valve.
L.
Confirm that these automated valves have moved to the proper positions.
M.
"Crack" the upstream block valve in the main utility air supply line and allow air to blow through the piping until it is clear. Then close
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SULFUR BLOCK the block valve, reinstall the utility air supply pressure regulator, and reopen the block valve.
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N.
Using the utility air supply pressure regulator and the vent valve downstream of the pressure control valve, adjust the utility air regulator to the setpoint specified on the P&IDs.
O.
"Crack" the block valve in the main nitrogen supply line and allow nitrogen to blow through the piping until it is clear. Then close the gate valve, reinstall the nitrogen supply pressure regulator, and reopen the gate valve.
P.
Using the pressure gauge and the vent valve downstream of the nitrogen supply pressure regulator, adjust the nitrogen regulator to its specified setpoint.
Q.
Open the flow valve in the utility air line by setting the output of the flow controller to 100% in the DCS, then use the downstream drain valve to blow out this section of piping. Close the drain valve when the piping is clear.
R.
Open the flow valve in the nitrogen line by setting the output of the flow controller to 100% in the DCS, then use the downstream drain valve to blow out this section of piping. Close the drain valve when the piping is clear.
S.
"Crack" the block valve downstream of the flow valve and allow air to blow through the piping until it is clear. Then close the bock valve.
T.
Close the flow valve in the utility air line by setting the output of the flow controller to 0% in the DCS
U.
"Crack" the block valve downstream of nitrogen control valve and allow nitrogen to blow through the piping until it is clear. Then close the block valve.
V.
Close the control valve in the nitrogen line by setting the output of the flow controller to 0% in the DCS
W.
Remove the "forces" from the PLC and confirm that both of the automated block valves close and the automated vent valve opens.
X.
Close the upstream block valve in the utility air supply line.
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SULFUR BLOCK Y.
Rotate the spectacle blind in the utility air line to the "closed" position.
Z.
Close the upstream block valve in the nitrogen supply line until the TGCU unit is ready for startup.
AA. Reconnect the nitrogen / air piping by performing the following steps: (1)
Reinstall the steam jacketed block valve and bolt the flanged connections back together.
(2)
Reinstate the steam supply and condensate return piping.
(3)
If the steam system is already in service, establish steam flow into the jacket by opening the steam supply valve. Open the vent valve on the steam jacket long enough to vent the air from the jacket.
(4)
Reinstall the orifice plate in the utility air flow meter.
(5)
Reinstall the orifice plate in the nitrogen flow meter.
BB. Open the block valve in the utility nitrogen supply line located near the TGCU Reactor until the line is clear. CC. The TGCU Reactor d/P transmitter has low pressure purges for both of its sensing lines, each with a rotameter near where it connects to the sensing line. Disconnect the upstream fitting at each rotameter and briefly open its upstream gate valve to blow any liquids or debris from its purge line. Reconnect each rotameter, disconnect the fitting where each purge connects to the sensing line, open the upstream gate valve, and open the ball valve downstream of each rotameter briefly to blow any liquids or debris from the purge lines. Then reconnect each purge to the sensing line and open its valve to place it in service. DD. Disconnect the fitting where each sensing line connects to its process line, and open the ball valve in each sensing line briefly to blow any liquids or debris from the lines. Then reconnect each sensing line to its process line and open its ball valve to place it in service. NOTE: The two rotameters must be adjusted to the same flow rate so that the pressure drop of the purge gas in the sensing lines does not affect the reading of the d/P transmitter. One
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SULFUR BLOCK way to do this is to confirm that the equalizing valve on the d/P transmitter manifold is closed, set the rotameter on the upstream sensing line to a small flow rate (~0.8-1.6 Nm3/H), and then adjust the flow rate of the other rotameter until the meter reads zero d/P. EE. Disconnect the upstream fitting (in the purge line to the shaft seal on the TGCU Start-Up Blower) and open the upstream gate and ball valves briefly to blow any liquids or debris from the purge line. Reconnect the rotameter and disconnect the fitting where the purge connects to the shaft seal. Open the upstream gate valve, open the ball valve briefly to blow any liquids or debris from the purge line, then reconnect the purge to the shaft seal and open the ball valve to place it in service. FF. The nitrogen purge valve for the blower casing should already be open. Disconnect the upstream fitting (in the purge line to the TGCU Start-Up Blower discharge line) and open the upstream gate valve briefly to blow any liquids or debris from the purge line. Reconnect the rotameter and disconnect the fitting where the purge connects to the discharge line on the TGCU Start-Up Blower. Open the upstream gate valve, open the downstream ball valve briefly to blow any liquids or debris from the purge line, then reconnect the purge to the discharge line. GG. Re-open the ball valve downstream of the nitrogen purge valve and allow the nitrogen to pressurize the TGCU Start-Up Blower and the piping inside the suction and discharge block valves. Check all of the blower and piping connections for visible or audible signs of leakage (by applying masking tape or "Snoop" to the flanges, listening for other leaks, etc.). When done, leave the ball valve open so that the purge is in service. HH. Disconnect the upstream fitting (in the nitrogen supply line to the sample switching valves) and open the upstream gate valve briefly to blow any liquids or debris from the purge line. Reconnect the rotameter and disconnect the fitting where the purge connects to the sample selector valve on the H2/H2S analyzer. "Crack" the gate valve to blow nitrogen through the piping until it is clear. Then close the gate valve, reconnect the piping, and reopen the gate valve. II.
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Remove the nitrogen supply regulator to the Reflux Accumulator.
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SULFUR BLOCK JJ.
"Crack" the upstream block valve in the nitrogen supply line and allow nitrogen to blow through the piping until it is clear. Then close the block valve, reinstall the nitrogen supply pressure regulator, and reopen the block valve.
KK. Using the nitrogen supply pressure regulator and the vent valve downstream of the regulator, adjust the nitrogen regulator to the setpoint specified on the P&IDs
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SULFUR BLOCK 11.7.4
Commissioning Hydrogen to the Process The external hydrogen supply must be made ready for use prior to starting up the TGCU using the procedures in Section 11.8 of these guidelines. This requires blowing down each section of piping to ensure that there are no liquids and/or construction debris in the headers and supply lines. Because of the fire hazard associated with venting high-purity hydrogen, nitrogen should be used for the initial flushing of the hydrogen piping and for setting the pressure regulator. Once this is completed, hydrogen can then be used to check the setting of the pressure regulator by venting the hydrogen to a safe location using the bypass valve.
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A.
Place the hydrogen controller in the DCS in "manual" and set its output to 0%.
B.
Confirm that the following valves are closed: (1)
The two block valves upstream of the pressure regulator.
(2)
The reducing gas supply line automated block valves, the flow control valve, the isolation valve downstream of the control valve and the bypass valve around the control valve.
C.
Confirm that all of the manual vent/drain valves in the hydrogen piping are closed.
D.
If the orifice plate has already been installed in the hydrogen flow meter, remove it for now.
E.
Rotate the spectacle blind in the hydrogen supply line to the "closed" position.
F.
Disconnect the hydrogen piping from the line going to the TGCU Reactor Feed Mixer by performing the following steps: (1)
Unbolt the flanged connections at the steam jacketed block valve and "drop out" this valve.
(2)
Isolate and, if necessary, disconnect the steam supply and condensate return connections for this valve.
(3)
Cover the open end of the piping to prevent debris from entering when the upstream piping is blown down.
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SULFUR BLOCK
Issued 30 August 2011
G.
Remove the pressure regulator, then cover the downstream piping to prevent debris from entering when the upstream piping is blown down.
H.
"Force" the PLC to open the block valves in the hydrogen supply line, and close the vent valve.
I.
Confirm that these automated valves have moved to the proper positions.
J.
Use a temporary "jumper" to connect a nitrogen supply to the drain valve upstream of the pressure regulator.
K.
"Crack" the gate valve upstream of the pressure regulator and allow nitrogen to blow through the piping until it is clear. Then close the gate valve, reinstall the pressure regulator and reopen the gate valve.
L.
Using the pressure gauge and the vent valve downstream of the pressure regulator, adjust the hydrogen regulator to the setpoint specified on the P&IDs.
M.
Open the reducing gas supply line control valve by setting the output of the hydrogen controller to 100% in the DCS, then use the downstream drain valve to blow out this section of piping. Close the drain valve when the piping is clear.
N.
"Crack" the gate valve downstream of the reducing gas supply line control valve and allow nitrogen to blow through the piping until it is clear. Then close the gate valve.
O.
Close the reducing gas supply line control valve by setting the output of the hydrogen controller to 0% in the DCS.
P.
Briefly open the bypass valve around the control valve and allow nitrogen to blow through the piping until it is clean. Then close the bypass valve.
Q.
Remove the "forces" from the PLC and confirm that both of the automated block valves close and the automated vent valve opens.
R.
Close the gate valve where the nitrogen "jumper" is connected to stop the flow of nitrogen, and disconnect the nitrogen jumper.
S.
Reconnect the hydrogen piping by performing the following steps:
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SULFUR BLOCK
T.
Issued 30 August 2011
(1)
Reinstall the steam jacketed block valve and bolt the flanged connections back together.
(2)
Reinstate the steam supply and condensate return piping.
(3)
If the steam system is already in service, establish steam flow into the jacket by opening the steam supply valve. Open the vent valve on the steam jacket long enough to vent the air from the jacket.
(4)
Reinstall the orifice plate in the hydrogen flow meter.
(5)
Rotate the spectacle blind in the hydrogen supply line to the "open" position.
Confirm that the hydrogen pressure regulator is properly adjusted: (1)
Open the two gate valves upstream of the pressure regulator.
(2)
"Crack" the bypass valve to vent hydrogen to the flare. Adjust the pressure regulator if necessary to maintain its setpoint, observing the pressure on the pressure gauge.
(3)
Close the bypass valve, and the gate valve immediately upstream of the pressure regulator.
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SULFUR BLOCK 11.7.5
Leak Testing the Process Piping and Equipment
CAUTION
THE LOW PRESSURE PROCESS PIPING (PROCESS GAS AND SULFUR VAPOR) AND LOW PRESSURE PROCESS EQUIPMENT IN THE TGCU ARE NOT DESIGNED TO BE HYDROSTATICALLY TESTED. ONLY THE PIPING AND EQUIPMENT DOWNSTREAM OF THE TGCU CONTACTOR (THE SOLVENT AND STRIPPER SYSTEMS) ARE DESIGNED TO BE HYDROTESTED. USE THE FOLLOWING PROCEDURE TO LEAK-TEST THE REST OF THE TGCU. The process piping and equipment in the TGCU can be checked for leaks by using nitrogen to pressurize the process side of the equipment and piping to about 0.6-0.7 kg/cm2(g), then checking flanges, etc. for leaks (usually by applying masking tape or "Snoop" to the flanges, and by listening for other leaks). In order to pressurize the TGCU with nitrogen, it is necessary to block-in the unit by closing the outlet valve. This procedure requires some special preparations to operate in this manner, as detailed below. The Complete Flowpath Interlock (see Section 11.5.5.1 of these guidelines) must be temporarily disabled in order to operate the TGCU in this manner. The Leak Test toggle switch in the DCS is used to direct the PLC to bypass most of the unit shutdowns and to enable the on/off selector switch for the nitrogen. This means that "jumpers" on the limits switches or "forces" in the PLC are not necessary to perform this test. It also means that it is not necessary to have water in the TGCU Waste Heat Reclaimer during the test since the low-low water level S/D is also bypassed. This same procedure can be used to leak test the TGCU following maintenance, before restarting the unit. Whenever plant maintenance requires opening one or more of the flanged connections in the TGCU, it is good practice to leak test the unit before returning it to service. This allows detecting any leaking connections that may have resulted from the maintenance operations before tailgas is reintroduced into the unit.
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK To perform leak testing in a TGCU, proceed as follows: A.
Confirm that the nitrogen flow controller in the DCS is set to 0% output and that the control valve in the nitrogen supply line is closed.
B.
Confirm that the Quench Column inlet hand control in the DCS is set to 0% output so that the TGCU Quench Column Bypass Valve will open later in Step F when the Startup/Run selector switch is switched to "STARTUP".
C.
Confirm that the TGCU Quench Column is isolated from the quench water circulation loop by confirming that the following valves are all closed:
D.
Issued 30 August 2011
(1)
The bypass valve and downstream block valve at the quench water flow control valve.
(2)
The block valve downstream of the pH analyzer.
(3)
The suction valves at the TGCU Quench Water Pumps.
(4)
The drain valve on the suction line to the pumps.
(5)
The block valve in the caustic supply line at the tie-in to the suction line.
(6)
The block valve in the condensate fill line at the tie-in to the suction line.
(7)
The bypass valve and downstream block valve at the filtered quench water flow control valve.
Confirm that the TGCU Contactor is isolated from the solvent circulation loop by confirming that the following valves are all closed: (1)
The bypass valve and downstream block valve at the lean solvent flow control valve.
(2)
The suction valves at the TGCU Rich Amine Pumps.
(3)
The drain valve on the suction line to pumps.
(4)
The block valves in the solvent makeup line at the tie-in to the suction line.
(5)
The block valve and globe valve in the condensate makeup line at the tie-in to the suction line.
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SULFUR BLOCK E.
Confirm that the spectacle blind in the utility air supply line is in the "closed" position.
F.
Switch the Startup/Run selector switch, the Startup/Run selector switch, in the DCS to "STARTUP". The PLC should perform the following actions: (1)
Bypasses the SRU ESD inputs to the TGCU ESD.
(2)
Disables the Tailgas Valves transfer switches.
(3)
Opens the TGCU Quench Column Bypass Valve.
(4)
Enables the Leak Test Switch.
G.
Confirm that the SRU Tailgas Valves to the TGCU are closed.
H.
Confirm that the TGCU Start-Up Blower Bypass Valve is fully open.
I.
Confirm that the block valve(s), and the steam-jacketed block valve in the nitrogen supply line are open.
J.
Toggle the Leak Test Switch in the DCS to "ON". The PLC should perform the following actions: (1)
Bypasses the TGCU ESD to allow opening the nitrogen supply valves via the nitrogen on/off push-button.
(2)
Opens TGCU Warmup/Bypass Valve.
K.
Close the TGCU Outlet Valve.
L.
Toggle the Nitrogen On/Off switch, the nitrogen on/off push-button, in the DCS to "ON". The PLC should perform the following actions:
Issued 30 August 2011
(1)
Opens the nitrogen block valves.
(2)
Closes the nitrogen vent valve.
M.
Use the nitrogen flow controller in the DCS to open the nitrogen flow control valve and send nitrogen to the TGCU to begin pressurizing it.
N.
Slowly increase the output from the nitrogen flow controller until the pressure reaches 0.6-0.7 kg/cm2(g) as measured by the pressure indicator in the DCS.
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SULFUR BLOCK Due to the volume inside the TGCU, it will take several minutes for the pressure to build up in the unit. O.
Once the desired pressure has been achieved, set the output from the nitrogen flow controller to 0% to close the nitrogen flow control valve. Check all of the equipment and piping connections for visible or audible signs of leakage.
P.
Toggle the Nitrogen On/Off switch in the DCS to "OFF". The PLC should perform the following actions:
Q.
(1)
Closes the nitrogen block valves.
(2)
Opens the nitrogen vent valve.
Toggle the Leak Test Switch in the DCS to "OFF". The PLC will enable all of the ESDs for the TGCU again.
Issued 30 August 2011
R.
Open the TGCU Outlet Valve.
S.
Re-open valves as necessary to restore the quench water and solvent circulation loops that were isolated from the columns in Steps C and D earlier.
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SULFUR BLOCK 11.7.6
Washing the Quench Water System The following procedure is intended to remove grease, rust, scale, dirt, and trash from the equipment and piping in the quench water system before it is placed in operation. Washing of the system consists of three steps: an initial water flush to remove dirt and trash from the system; an acid wash to remove grease, rust, and scale; and a caustic wash to acclimate the equipment and piping to alkaline pH. Failure to clean the system properly prior to startup can lead to operating problems (heat exchanger fouling, rapid filter plugging, etc.).
WARNING
THIS PROCEDURE REQUIRES WORKING WITH ACIDIC AND ALKALINE CHEMICALS AND SOLUTIONS. EMPLOYEES MUST OBSERVE ALL APPLICABLE SAFETY PROCEDURES AND ENVIRONMENTAL REGULATIONS CONCERNING USAGE OF PERSONAL PROTECTIVE EQUIPMENT, HANDLING OF HAZARDOUS MATERIALS, DISPOSAL OF WASTE STREAMS, ETC.
11.7.6.1
Issued 30 August 2011
Water Flush A.
Place the quench water flow controller in the DCS in "manual" and set its output to 100% to fully open the quench water flow control valve.
B.
Place the TGCU Quench Column level controller in the DCS in "manual" and set its output to 0% to fully close the level control valve.
C.
Confirm that the Quench Column inlet hand control in the DCS is set to 0% output so that the TGCU Quench Column inlet valve is fully closed.
D.
Place the filtered quench water flow controller in the DCS in "manual" and set its output to 100% to fully open the filtered quench water flow control valve.
E.
Verify that the quench water flow control valve is fully open. Open both of its isolation block valves and its bypass valve.
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SULFUR BLOCK
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F.
Verify that the TGCU Quench Column level control valve is fully closed. Close both of its isolation block valves and its bypass valve.
G.
Verify that the TGCU Quench Column inlet valve is fully closed. (This will prevent water from entering the TGCU Reactor if the TGCU Quench Column is accidentally over-filled.)
H.
Verify that the filtered quench water flow control valve is fully open. Open both of its isolation block valves and its bypass valve.
I.
The TGCU Quench Water Filter will not be used to filter solids during this time, but the filter vessel and its piping are to be flushed and cleaned. Remove the filter elements, then bolt-up the filter. Open the inlet and outlet block valves on the filter, and open the bypass valve around the filter.
J.
Similarly, remove the elements from both pH Meter Sample Filters and reinstall the filter housings. Open the inlet and outlet block valves to the sample loop for the pH analyzer, and open the inlet and outlet block valves for both pH Meter Sample Filters.
K.
The probe on the pH analyzer, the pH analyzer, should not be installed until the quench water system has been cleaned and refilled, ready for service. Verify that a temporary plug has been screwed into the probe housing installed in the sample piping.
L.
Verify that the block valve in the caustic line is closed.
M.
Add water (steam condensate) to the bottom of the TGCU Quench Column through the condensate line.
N.
Once there is an adequate level in the column, all the way to the top of its level gauge open the suction valve on a TGCU Quench Water Pump and use its drain valve to be sure the pump is flooded with water. Start the pump, then open its discharge valve.
O.
Watch the level in the TGCU Quench Column while placing the pump in service to be sure the pump does not lose suction while filling the downstream piping and equipment. If the level
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SULFUR BLOCK disappears in the column, shut the pump down until enough condensate is added to reestablish the level, then restart the pump. P.
Once circulation is achieved and the level in the TGCU Quench Column is adequate (about halfway up in the level gauge), discontinue the addition of condensate.
Q.
Use the low point drain valves to flush out each section of the system. Leave the drain valves open until the water is clear.
R.
Briefly open the bypass valve on the TGCU Quench Column level control valve to flush this section of piping to The Sour Water Stripping Unit. Open the upstream block valve, open the TGCU Quench Column level control valve with the level controller in the DCS, and use the downstream drain valve to flush the control station. Once the flush water clears up, close the TGCU Quench Column level control valve and the upstream block valve.
S.
Circulate the water and blow down the low point drains until all of the drain water is clear. Add more condensate as necessary to maintain the level in the TGCU Quench Column. At some point during the washing procedure, the standby pump should be placed in service while the other pump is shut down. This will ensure cleaning out both pumps and their associated piping.
Issued 30 August 2011
T.
Once the drain water is clear, completely drain the system. Drain the system as quickly as possible, so that the water velocity helps to flush the solids from all parts of the system.
U.
Allow the pump to continue running while the system drains, but watch the pump closely to verify that the low-low level shutdown shuts the pump down below the shutdown setpoint. If the level drops completely out of the gauge glass before the pump shuts down, stop the pump manually and correct the problem with the low-low level shutdown before proceeding further.
V.
Verify that the caustic supply line has been flushed and is ready for service.
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SULFUR BLOCK 11.7.6.2
Acid Wash A weak (0.1 wt %) citric acid solution is used next to remove grease, rust, and scale from the equipment and piping. The citric acid will chelate with the iron in the rust and scale so that it dissolves in the solution.
11.7.6.3
A.
Use the condensate makeup line to reestablish a level in the TGCU Quench Column.
B.
Once a level is established, start a TGCU Quench Water Pump to begin circulating the water.
C.
Add concentrated citric acid to the circulating water to make a 0.1 wt % citric acid solution.
D.
After circulating for about 3 hours, start the other TGCU Quench Water Pump and shut down the first one.
E.
Circulate the solution for a total of about 6 hours, blowing down the low point drains occasionally. Add more condensate if necessary to maintain the level in the TGCU Quench Column.
F.
Briefly open the bypass valve on the TGCU Quench Column level control valve to flush this section of piping to The Sour Water Stripping Unit. Then open both block valves and use the level controller in the DCS to open the TGCU Quench Column level control valve briefly and flush the control station. Close the TGCU Quench Column level control valve and the block valves.
G.
After 6 hours, shut down the pump and completely drain the system. Drain the system as quickly as possible, so that the liquid velocity will help flush any remaining solids from the system.
Alkaline Wash The washing operation is completed by circulating a weak alkaline solution through the system. This will neutralize any citric acid left in the system, and acclimate the system to high pH operation so that no further scale is removed from the equipment and piping when the normal quench water (8.0-9.5 pH) is circulated.
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SULFUR BLOCK
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A.
Use the condensate makeup line to reestablish a level in the TGCU Quench Column.
B.
Once a level is established, start a TGCU Quench Water Pump to begin circulating the water.
C.
Adjust a TGCU Caustic Injection Pump to full stroke. Open the block valve at the tank, the suction block valve, and the discharge block valve on the pump. Start the pump, then open the block valve in the caustic line where it enters the suction line to the TGCU Quench Water Pump.
D.
Allow the pump to run for long enough to displace the water in the caustic supply piping (left from the earlier water flush procedure). Add caustic to the circulating water to make a 0.02 wt% solution. This should give a pH in the range of 11-22.
E.
Shut off the TGCU Caustic Injection Pump, and close the block valve in the caustic supply at the injection point in the quench water piping.
F.
Check the pH of the circulating water. If the pH is less than 11, add more caustic from the caustic makeup line until the pH is 11 or higher.
G.
After circulating for about 1 hour, start the other TGCU Quench Water Pump and shut down the first one.
H.
Circulate the solution for a total of about 2 hours, blowing down the low point drains occasionally. Add more condensate if necessary to maintain the level in the TGCU Quench Column.
I.
Briefly open the bypass valve on the TGCU Quench Column level control valve to flush this section of piping to the sour water header. Then open both block valves and use the level controller in the DCS to open the TGCU Quench Column level control valve briefly and flush the control station. Close the TGCU Quench Column level control valve and the block valves.
J.
After 2 hours, shut down the pump and completely drain the system. Drain the system as quickly as possible, so that the liquid velocity will help flush any remaining solids from the system.
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SULFUR BLOCK 11.7.6.4
Initial Water Fill The quench water system should now be clean and ready to place in service. All that remains is to refill the system with water and establish the proper operating conditions. This includes "pre-charging" the system with caustic to serve as a "buffer" so that the system pH does not drop suddenly when process gas is first introduced into the TGCU Quench Column and H2S from the gas dissolves in the water.
Issued 30 August 2011
A.
Close the inlet and outlet block valves on the TGCU Quench Water Filter, then install the proper element(s) in the filter. Leave the block valves closed for now.
B.
Close the inlet and outlet block valves on the pH analyzer sample loop, then install the proper elements in both pH Meter Sample Filters. Leave the block valves closed for now.
C.
Use the condensate makeup line to reestablish a level in the TGCU Quench Column.
D.
Once a level is established, start a TGCU Quench Water Pump to begin circulating the water.
E.
Place the Quench Water flow controller in the DCS in service and set its setpoint to its normal value. Close the bypass valve on the quench water flow control valve.
F.
Confirm that the TGCU Quench Column level control valve is closed, then open both of its block valves. Place the level controller in the DCS in service and set its setpoint to its normal value.
G.
Place the TGCU Quench Water Filter in service as follows: (1)
Open the vent valve on the top of the filter.
(2)
"Crack" the filter inlet block valve open slightly and allow the filter to fill with water. When the filter is full, close the vent valve.
(3)
Open the filter inlet block valve fully and open the outlet block valve, then close the filter bypass valve.
(4)
Place the filtered quench water flow controller in the DCS in service and set its setpoint to its normal value. Close
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SULFUR BLOCK the bypass valve on the filtered quench water flow control valve. H.
Adjust a TGCU Caustic Injection Pump to full stroke. Start the pump, then open the block valve in the caustic line where it enters the quench water piping.
I.
Allow the pump to run for a few minutes until the pH of the solution is in the range of 12-13.
J.
Shut off the TGCU Caustic Injection Pump and close its suction valve. Leave the block valve at the injection point in the quench water piping open.
K.
Install the pH analyzer probe in its housing in the sample loop, following the manufacturer's instructions. Place the analyzer in service by opening the block valves on one of the pH Meter Sample Filters (the block valves should be closed on the other filter) and opening the inlet and outlet valves on the sample loop. Observe the flow indicator to verify flow through the sample loop. Analyze a sample of the quench water to confirm that the pH analyzer is measuring the correct pH.
L.
Add additional caustic if necessary to adjust the pH to 11-13.
M.
Commence cooling water flow to the TGCU Quench Water Trim Cooler if it has not already been placed in service.
The quench water system is now ready for service. It can remain in this operating mode indefinitely while the rest of the TGCU is prepared for startup. Check the system periodically for indications of plugging, etc. (low flow, erratic pump discharge pressure, high filter pressure drop), as solid materials may accumulate at various points in the system over time.
11.7.7
Washing the Amine System The following procedure is intended to remove grease, rust, scale, dirt, and trash from the equipment and piping in the solvent system before it is placed in operation. Washing of the system consists of three steps: an initial water flush to remove dirt and trash from the system; an acid wash and rinse to remove grease, rust, and scale; and a weak amine wash and rinse to acclimate the equipment and piping to alkaline pH.
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SULFUR BLOCK Failure to clean the system properly prior to startup can lead to operating problems (column foaming, poor treating, heat exchanger fouling, rapid filter plugging, etc.).
WARNING
THIS PROCEDURE REQUIRES WORKING WITH ACIDIC AND ALKALINE CHEMICALS AND SOLUTIONS. EMPLOYEES MUST OBSERVE ALL APPLICABLE SAFETY PROCEDURES AND ENVIRONMENTAL REGULATIONS CONCERNING USAGE OF PERSONAL PROTECTIVE EQUIPMENT, HANDLING OF HAZARDOUS MATERIALS, DISPOSAL OF WASTE STREAMS, ETC.
11.7.7.1
Issued 30 August 2011
Water Flush A.
Place the following controllers in the DCS in "manual" with their outputs set as indicated:
(a)
Set the output from the lean solvent flow controller to 100% to fully open the lean solvent flow control valve.
(b)
Open the manual block valve upstream of the lean solvent filters.
(c)
Set the output from the TGCU Contactor level controller to 100% to fully open the TGCU Contactor level control valve.
(d)
Set the output from the TGCU Stripper Reboiler steam flow controller to 0% to fully close the steam flow control valve.
(e)
Set the output from the TGCU Stripper Reflux Accumulator level controller to 0% to fully close the TGCU Stripper Reflux Accumulator level control valve.
(f)
Set the output from the bleed water flow controller to 0% to fully close the bleed water flow control valve.
(g)
Set the output from the makeup water flow controller to 0% to fully close the makeup water flow control valve.
(h)
Set the output from the TGCU Stripper pressure controller, to 0% to fully close the pressure control valve.
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SULFUR BLOCK B.
Place the other TGCU Stripper pressure controller in "automatic" with a setpoint of 0.85 kg/cm2(g). This will open the pressure control valve to the flare if pressure builds in the TGCU Stripper during this procedure.
C.
Verify that the following control valves are fully open. Open both of the isolation block valves and the bypass valve (where applicable) at each control station.
D.
Issued 30 August 2011
(1)
The lean solvent flow control.
(2)
The lean solvent from the lean solvent filters.
(3)
The TGCU Contactor level control, (the rich solvent from the TGCU Contactor).
Verify that the following control valves are fully closed. Close both of the isolation block valves and the bypass valve at each control station. (1)
The steam flow control valve to the TGCU Stripper Reboiler.
(2)
The TGCU Stripper Reflux Accumulator level control valve.
(3)
The bleed water flow control valve from the TGCU Stripper reflux.
(4)
The makeup water flow control valve to the TGCU Stripper Reflux Accumulator.
(5)
The acid gas pressure control to the SRU.
E.
Verify that the bypass valve on the pressure control valve to the flare is closed. Open both of the isolation block valves at this control station.
F.
The TGCU solvent filters will not be used to filter solids during this time, but the filter vessels and their piping are to be flushed and cleaned. Remove the filter elements, then bolt-up the individual filters. Open the inlet and outlet block valves on each filter, and open the bypass valves for the filters.
G.
Verify that the valves in the solvent makeup line are closed.
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SULFUR BLOCK H.
Add water (steam condensate) to the bottom of the TGCU Contactor through the condensate makeup line.
I.
Once there is an adequate level in the TGCU Contactor, all the way to the top of its level gauge open the suction valve on a TGCU Rich Amine Pump and use its drain valve to be sure the pump is flooded with water. Start the pump, then open its discharge valve. Watch the level in the TGCU Contactor as the pump fills the downstream piping and begins to fill the TGCU Stripper. When the level drops to the low-low level shutdown should shut down the pump. If it does not, stop the pump manually before it loses suction and correct the problem with the low level shutdown before proceeding.
J.
Continue filling the TGCU Contactor with condensate and pumping the water to the TGCU Stripper periodically, until the level in the TGCU Stripper is all the way to the top of its level gauge.
K.
Once there is an adequate level in the TGCU Stripper, open the suction valve on a TGCU Lean Amine Pump and use its drain valve to be sure the pump is flooded with water. Start the pump, then open its discharge valve. As the pump fills the downstream piping and begins to return water to the TGCU Contactor, watch the level in the TGCU Stripper to be sure the pump does not lose suction. If the level disappears in the column, shut the pump down, add more condensate to the TGCU Contactor and pump it to the TGCU Stripper to reestablish the level, then restart the TGCU Lean Amine Pump.
Issued 30 August 2011
L.
As the level begins to rise in the TGCU Contactor, restart the TGCU Rich Amine Pump. Watch the levels in both columns, and shut a pump down if necessary to keep from emptying either column.
M.
Once the levels in both columns are adequate, discontinue the addition of condensate.
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SULFUR BLOCK N.
At this point, neither the flow into or the level of the TGCU Contactor is being controlled. Both control stations are in "manual" with the valves fully open to flush the piping as much as possible. Depending on the hydraulics of the system, it may be necessary to place either or both of these controls in "automatic" to prevent losing the level in one of the columns. If so, leave the bypass valve on the control station "cracked" so that the bypass piping gets flushed.
O.
Use the low point drain valves to flush out each section of the system. Leave the drain valves open until the water is clear.
P.
Circulate the water and blow down the low point drains until all of the drain water is clear. Add more condensate as necessary to maintain the levels in the columns. At some point during the washing procedure, the standby TGCU Rich Amine Pump and standby TGCU Lean Amine Pump should be placed in service while the other pumps are shut down. This will ensure cleaning out both pumps and their associated piping in each service.
11.7.7.2
Q.
Once the drain water is clear, shut down the TGCU Rich Amine Pump and completely drain the system. Drain the system as quickly as possible, so that the water velocity will help flush the solids from all parts of the system.
R.
Allow the TGCU Lean Amine Pump to continue running while the system drains, but watch the pump closely to verify that the low-low level shutdown shuts the pump down when the level falls to the shutdown setpoint. If the level drops completely out of the gauge glass before the pump shuts down, stop the pump manually and correct the problem with the low level shutdown before proceeding further.
S.
Confirm that the solvent transfer line (for MDEA makeup) has been flushed and is ready for service.
Acid Wash A weak (0.1 wt %) citric acid solution is used next to remove grease, rust, and scale from the equipment and piping. The citric acid will chelate with the iron in the rust and scale so that it dissolves in the solution.
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SULFUR BLOCK
Issued 30 August 2011
A.
Use the condensate makeup line to re-establish the levels in the TGCU Contactor and the TGCU Stripper as before, and establish circulation of water in the system.
B.
Add concentrated citric acid to the circulating water to make a 0.1 wt % citric acid solution.
C.
Begin steam flow to the TGCU Stripper Reboiler and gradually raise the temperature of the circulating solution. For maximum effectiveness, the solution should be 65-95°C throughout the system, so adjust the steam flow accordingly. The fans on the TGCU Lean Amine Cooler should not be operating at this time, and cooling water should not be flowing to the TGCU Lean Amine Trim Cooler.
D.
It is unlikely that any steam will leave the top of the TGCU Stripper during this operation, so the TGCU Stripper Reflux Accumulator should remain dry. If a level should develop in this vessel, drain the water from the vessel using a drain valve on one of the TGCU Stripper Reflux Pumps.
E.
After circulating for about 3 hours, start the other TGCU Rich Amine Pump and shut down the first one. Do the same with the TGCU Lean Amine Pumps.
F.
Circulate the hot solution for a total of about 6 hours, blowing down the low point drains occasionally. Add more condensate if necessary to maintain the levels in the columns.
G.
After 6 hours, shut off the steam to the TGCU Stripper Reboiler, shut down the pumps, and completely drain the system. Drain the system as quickly as possible, so that the liquid velocity will help flush any remaining solids from the system.
H.
Use the condensate makeup line to reestablish the levels in the TGCU Contactor and the TGCU Stripper as before, and establish circulation of water to flush the system.
I.
Switch to the other pumps for a few minutes, then shut down the pumps and completely drain the system.
J.
Once again, use the condensate makeup line to reestablish the levels in the TGCU Contactor and the TGCU Stripper as before, and establish circulation of water in the system.
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SULFUR BLOCK
11.7.7.3
K.
Reestablish steam flow to the TGCU Stripper Reboiler and gradually raise the temperature in the column.
L.
When the temperature begins to rise in the TGCU Stripper overhead line, start a fan on the TGCU Stripper Reflux Condenser and place the reflux temperature controller in service with a setpoint of 54°C.
M.
When a level builds in the TGCU Stripper Reflux Accumulator, drain it to the closed drain from the drain on one of the pump cases.
N.
Open the downstream block valve at the TGCU Stripper Reflux Accumulator level control valve, then use the drain valve to blow steam from the column backwards down the reflux line to remove any debris. Continue until the steam blows clear, then close the drain valve and the block valve.
O.
Continue to circulate water and apply heat in the TGCU Stripper Reboiler, until the water drained from the TGCU Stripper Reflux Accumulator is clear. During this time, blow down the low point drains occasionally and add more condensate if necessary to maintain the levels in the columns, and switch to the other TGCU Rich Amine Pump and TGCU Lean Amine Pump.
P.
Once the reflux loop has cleared up (the drain water is clear), shut off the steam to the TGCU Stripper Reboiler, shut down the pumps, and completely drain the system. Drain the system as quickly as possible, so that the liquid velocity will help flush any remaining solids from the system.
Q.
Check the pH of the water draining from the system. If necessary, repeat Steps J through P until the pH of the drain water is about the same as the pH of the condensate makeup.
Weak Amine Wash The washing operation is completed by circulating a weak amine solution through the system. This will neutralize any citric acid left in the system, and acclimate the system to alkaline pH operation so that no further scale is removed from the equipment and piping when the normal solvent is circulated.
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SULFUR BLOCK A.
Use the condensate makeup line to reestablish the levels in the TGCU Contactor and the TGCU Stripper as before, and establish circulation of water in the system.
B.
Add enough MDEA to the circulating water to reach a concentration of about 1 wt%.
C.
Begin steam flow to the TGCU Stripper Reboiler and gradually raise the temperature in the column.
D.
When the temperature begins to rise in the TGCU Stripper overhead line, check that at least one of the fans is running on the TGCU Stripper Reflux Condenser.
E.
When a level builds in the TGCU Stripper Reflux Accumulator, open the suction valve on one of the TGCU Stripper Reflux Pumps and use its drain valve to be sure the pump is flooded with water. Start the pump, open its discharge valve, then open the bypass valve on the TGCU Stripper Reflux Accumulator level control valve to pump the water back into the TGCU Stripper. Watch the level in the TGCU Stripper Reflux Accumulator while pumping it out. Shut the pump down when the vessel is empty, then close the suction and discharge valves on the pump and close the bypass valve on the TGCU Stripper Reflux Accumulator level control valve.
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F.
Continue to circulate the solution and apply heat to the TGCU Stripper Reboiler, pumping out the TGCU Stripper Reflux Accumulator as required by alternating which pump is used. During this time, blow down the low point drains occasionally and add more condensate if necessary to maintain the levels in the columns, and switch to the other TGCU Rich Amine Pump and TGCU Lean Amine Pump.
G.
During one of the pumping cycles for the TGCU Stripper Reflux Accumulator, flush out the minimum flow spill-back line by opening the manual block valve to allow circulation through this line. Then close the manual block valve.
H.
During another pumping cycle, flush out the bleed water piping by setting the output of the bleed water flow controller to 100%
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SULFUR BLOCK to fully open the bleed water flow control valve, opening its upstream and downstream block valves, and opening its bypass valve. Then close the valves and set the output of the bleed water flow control valve back to 0%.
11.7.7.4
I.
Take a sample of the circulating solution and run a foam test on it using the procedure in Section 11.10.
J.
Once the solution drained from all the low point drain valves is clear, shut off the steam to the TGCU Stripper Reboiler, shut down the pumps, and completely drain the system. Drain the system as quickly as possible, so that the liquid velocity will help flush any remaining solids from the system.
K.
Use the condensate makeup line to reestablish the levels in the TGCU Contactor and the TGCU Stripper as before, and establish circulation of water to flush the system.
L.
Switch to the other pumps for a few minutes, then shut down the pumps and completely drain the system.
M.
If the solvent sample taken in Step I was foamy, repeat Steps A through L until the solvent is not foamy.
Initial Solvent Fill The solvent system should now be clean, ready to place in service. All that remains is to fill the system with the proper solvent charge and establish the proper operating conditions. NOTE:
A.
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This procedure prepares the TGCU solvent system for operation in the shortest possible time. However, it does allow the MDEA to come in contact with oxygen that is in the TGCU Contactor. If a slightly longer TGCU startup schedule can be tolerated, this deficiency can be minimized or eliminated by deferring the procedure in this section until nitrogen has been used to purge the TGCU Quench Column and TGCU Contactor as described in the following section.
Close the inlet and outlet block valves on the four TGCU solvent filters, then install the proper elements and/or carbon in the filters. Leave the block valves closed on each filter for now.
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SULFUR BLOCK
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B.
Use the condensate makeup line to reestablish the levels in the TGCU Contactor and the TGCU Stripper as before, and establish circulation of water in the system.
C.
Add enough MDEA to the circulating water to reach a concentration of about 45 wt%.
D.
Place in service and adjust the level controller on the TGCU Contactor to maintain its normal setpoint. Stop the condensate and/or amine makeup when the TGCU Stripper level is about 50-60%.
E.
Begin steam flow to the TGCU Stripper Reboiler and gradually raise the temperature in the column. Place the steam flow controller in the DCS on "automatic" with its setpoint set to its normal value.
F.
Open the high point vent valve on the TGCU Stripper overhead line and allow the steam to purge any air from the vessel. As the pressure builds, the vent valve can be closed.
G.
Monitor the stripper pressure, and adjust the overhead pressure controller if necessary to maintain the stripper pressure at about 0.85 kg/cm2(g) as the system is heated to operating temperatures.
H.
Ensure that the fans are running on the TGCU Lean Amine Cooler and the TGCU Stripper Condenser. Commence cooling water flow to the TGCU Lean Amine Trim Cooler.
I.
Place the lean solvent temperature controller in "automatic" and set its setpoint to its normal value.
J.
When a level builds in the TGCU Stripper Reflux Accumulator, open the suction valve on one of the TGCU Stripper Reflux Pumps and use its drain valve to be sure the pump is flooded with water. Open the block valves upstream and downstream of the reflux flow control valve, place the reflux flow controller in "automatic" with its setpoint set to its normal value, then start the pump and open its discharge valve.
K.
Open the block valves on the TGCU Stripper Reflux Accumulator level control valve and place the level controller in the DCS in "automatic" with its setpoint set to its normal value.
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SULFUR BLOCK The TGCU Stripper Reflux Accumulator level control valve will now open as needed to pump water back into the TGCU Stripper and maintain the desired level in the TGCU Stripper Reflux Accumulator.
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L.
If the control loops on the TGCU solvent have not already been placed in service, do so at this time. Switch the TGCU contactor level controller and the lean solvent flow controller in the DCS to "automatic" with their setpoints set to their normal values.
M.
Place each of the four TGCU solvent filters in service as follows: (1)
Open the vent valve on the top of the filter.
(2)
"Crack" the filter inlet block valve open slightly and allow the filter to fill with solvent. When the filter is full, close its vent valve.
(3)
Open the inlet and outlet block valves on the filter.
(4)
Slowly close the valve in the bypass line around the filter.
N.
Analyze a sample of the circulating solvent using the procedure in these guidelines to determine the amine concentration. Add more fresh MDEA using the solvent transfer line if needed to bring the concentration up to the design value, 45 wt %.
O.
Flush the makeup water line by setting the output from the makeup water flow controller to 100% to fully open the makeup water flow control valve, opening its upstream block valve, then opening the downstream drain valve until the water runs clear. Then set the output of the flow controller to 0% to close the makeup water flow control valve, and open the downstream block valve.
P.
Confirm that the bleed water flow controller is in "manual' with its output set at 0% and that the bleed water flow control valve is closed, then open its upstream and downstream block valves.
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SULFUR BLOCK The solvent system is now ready for service. It can remain in this operating mode indefinitely while the rest of the TGCU is prepared for startup. Check the system periodically for indications of plugging, etc. (low flow, erratic pump discharge pressure, high filter pressure drop), as solid materials may accumulate at various points in the system over time.
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SULFUR BLOCK 11.7.8
Purging the Low Pressure TGCU Columns Prior to starting up the TGCU using the procedures in Section 11.8 of these guidelines, nitrogen should be used to purge the TGCU Quench Column and the TGCU Contactor. This will displace the air introduced into the columns while washing and filling them earlier. At this point, the following conditions should exist in the TGCU:
11.7.8.1
1.
The TGCU Start-Up Blower is not in service and is bypassed.
2.
The quench water system and perhaps the amine system have been cleaned and loaded with their respective initial fills of water and amine. (The amine system may be waiting on purging of the TGCU Contactor before the system is loaded with amine.)
Establishing Nitrogen Flow To establish nitrogen flow into the TGCU, proceed as follows:
Issued 30 August 2011
A.
Confirm that the nitrogen flow controller in the DCS is set to 0% output and that the control valve in the nitrogen supply line is closed.
B.
Confirm that the Quench Column inlet hand control in the DCS is set to 0% output so that the TGCU Quench Column Bypass Valve will open later in Step F when the Startup/Run selector switch is switched to "STARTUP".
C.
Confirm that the TGCU Quench Column is isolated from the quench water circulation loop by confirming that the following valves are all closed: (1)
The bypass valve and downstream block valve at the quench water flow control valve.
(2)
The block valve downstream of the pH analyzer.
(3)
The suction valves at the TGCU Quench Water Pumps.
(4)
The drain valve on the suction line to the pumps.
(5)
The block valve in the caustic supply line at the tie-in to the suction line.
(6)
The block valve in the condensate fill line at the tie-in to the suction line.
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SULFUR BLOCK (7)
D.
The bypass valve and downstream block valve at the filtered quench water flow control valve.
Confirm that the TGCU Contactor is isolated from the solvent circulation loop by confirming that the following valves are all closed: (1)
The bypass valve and downstream block valve at the lean solvent flow control valve.
(2)
The suction valves at the TGCU Rich Amine Pumps.
(3)
The drain valve on the suction line to pumps.
(4)
The block valves in the solvent makeup line at the tie-in to the suction line.
(5)
The block valve and globe valve in the condensate makeup line at the tie-in to the suction line.
E.
Confirm that the spectacle blind in the utility air supply line is in the "closed" position.
F.
Toggle the Startup/Run selector switch, the Startup/Run selector switch, in the DCS to "STARTUP". The PLC should perform the following actions:
Issued 30 August 2011
(1)
Bypasses the SRU ESD inputs to the TGCU ESD.
(2)
Disables the Tailgas Valves transfer switches.
(3)
Opens the TGCU Quench Column Bypass Valve.
(4)
Enables the Leak Test Switch.
G.
Confirm that the SRU Tailgas Valves to the TGCU are closed.
H.
Confirm that the TGCU Start-Up Blower Bypass Valve is fully open.
I.
Confirm that the block valve(s), and the steam-jacketed block valve in the nitrogen supply line are open.
J.
Confirm that the TGCU Outlet Valve is open.
K.
Reset the TGCU ESD by toggling the push-button in the DCS to "RESET".
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SULFUR BLOCK L.
Set the output of the hand control in the DCS to 0% to close the TGCU Warmup/Bypass Valve.
M.
Toggle the Nitrogen On/Off switch in the DCS to "ON". The PLC should perform the following actions:
11.7.8.2
(1)
Opens the nitrogen block valves.
(2)
Closes the nitrogen vent valve.
N.
Use the nitrogen flow controller in the DCS to open the nitrogen flow control valve and send nitrogen to the front end of the TGCU.
O.
Allow the nitrogen to continue flowing long enough to reduce the oxygen concentration in the equipment and piping to less than 1%. Use a portable oxygen analyzer to determine the oxygen concentration.
Purging the TGCU Start-Up Blower A.
Visually confirm that the TGCU Start-Up Blower suction block valve and the discharge block valve are closed, the bypass valve is open, the nitrogen purge to the blower seal is in service, and the local "stop" control at the bloweris set to the "RUN" position.
B.
Start the TGCU Start-Up Blower using the start/stop toggle switch in the DCS. The PLC will perform the following actions:
C.
Issued 30 August 2011
(1)
The nitrogen purge valveis closed.
(2)
The TGCU Start-Up Blower Suction Valve is opened.
(3)
The TGCU Start-Up Blower Discharge Valve is opened.
(4)
After the limit switches prove these valves open, the TGCU Start-Up Blower is started.
(5)
Once the Startup Blower is started, the TGCU Start-Up Blower Bypass Valve is closed.
As this valve is closed, the blower will start to load. As it does so, the blower will begin to "pull" nitrogen through the TGCU
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SULFUR BLOCK Reactor Feed Heater and TGCU Reactor Feed Mixer and all of the associated piping. D.
Allow the blower to continue running long enough to reduce the oxygen concentration in the piping to less than 1%. Use a portable oxygen analyzer to determine the oxygen concentration.
E.
When the oxygen concentration is below 1%, shut down the TGCU Start-Up Blower using the start/stop toggle switch in the DCS. The PLC will perform the following actions:
11.7.8.3
(1)
Open the TGCU Start-Up Blower Bypass Valve.
(2)
Prove the bypass valve open using the limit switches.
(3)
Stop the TGCU Start-Up Blower
(4)
Once the blower is stopped, the nitrogen purge valve is opened, and the suction and discharge valves are closed.
Purging the Columns All that remains is to open the vent valves on the low pressure columns and allow the inert gas to displace the air in the columns.
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A.
Open all of the vent valves on the PI and PDT taps on the TGCU Quench Column and the TGCU Contactor, and the vent valves at the tops of the columns.
B.
Increase the output from the Quench Column inlet hand control in the DCS to 100% to open the TGCU Quench Column Inlet Valve and close the TGCU Quench Column Bypass Valve.
C.
Continue to vent inert gas until no measurable oxygen escapes from the vents, then close all of the vent valves.
D.
Decrease the output from the Quench Column inlet hand control in the DCS to 0% to open the TGCU Quench Column Bypass Valve and close the TGCU Quench Column Inlet Valve.
E.
Set the output from the nitrogen flow controller to 0% to close the nitrogen flow control valve.
F.
Toggle the Nitrogen On/Off switch in the DCS to "OFF".
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SULFUR BLOCK The PLC should perform the following actions: (1)
Closes the nitrogen block valves.
(2)
Opens the nitrogen vent valve.
NOTE:
Issued 30 August 2011
If the initial solvent fill was not loaded into the solvent system earlier to avoid exposing the MDEA to oxygen, this can be accomplished now. Follow the procedure given in the previous section to fill the solvent system with its initial solvent charge.
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SULFUR BLOCK
11.8 Startup Procedures The procedure used to start up the TGCU depends on whether the catalyst in the TGCU Reactor has been pre-sulfided. This first section describes the procedure for the initial startup of the plant with a fresh catalyst charge (oxidized state), or for startups after the catalyst charge has been replaced. Subsequent startups will require a different procedure and are discussed later (Section 11.8.6 of these guidelines).
11.8.1
Initial Startup of the TGCU During the initial startup, the catalyst in the TGCU Reactor is pre-sulfided by contacting it with H2S in the presence of hydrogen. Subsequent startups will probably not require this step. Once this has been accomplished, the system can be placed into operation.
11.8.1.1
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Initial Preparations A.
Confirm that the steam pressure controller in the DCS is in "manual" with its output set to 0%, and that control valve in the HP Steam supply line to the TGCU Reactor Feed Heater is closed.
B.
Place the reactor feed temperature controller in "automatic".
C.
Confirm that reducing gas flow controller in the DCS is in "manual" with its output set to 0%, and that the control valve in the reducing gas supply line to the TGCU Reactor Feed Mixer is closed.
D.
Place the hydrogen controller in "automatic".
E.
Verify that the automated shutdown valves, the upstream block valves, and the downstream steam-jacketed block valve in the reducing gas line to the TGCU Reactor Feed Mixer are all closed.
F.
Confirm that the pre-sulfiding gas flow controller in the DCS is in "manual" with its output set to 0%, and that the control valve in the pre-sulfiding gas line to the TGCU Reactor Feed Mixer is closed.
G.
Verify that the automated shutdown valve and the upstream block valve in the pre-sulfiding gas line to the TGCU Reactor Feed Mixer are both closed.
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SULFUR BLOCK
11.8.1.2
H.
Confirm that the nitrogen flow controller in the DCS is in "manual" with its output set to 0% output, and that the control valve in the nitrogen supply line is closed.
I.
Verify that the automated shutdown valves in the nitrogen supply line are both closed, then open the upstream block valves and the downstream steam-jacketed block valve.
J.
Confirm that the Quench Column hand control in the DCS is set to 0% output, so that the TGCU Quench Column inlet valve will remain fully closed and the TGCU Quench Column bypass valve will open later when the TGCU startup/run selector switch is switched to "STARTUP".
K.
Confirm that the TGCU Waste Heat Reclaimer is filled with water up to its normal liquid level.
L.
Visually confirm that the SRU 1 Tailgas Valve to the TGCU is closed.
M.
Visually confirm that the SRU 2 Tailgas Valve to the TGCU is closed.
N.
Visually confirm that the manual TGCU Outlet Valve is fully open.
O.
Confirm that the Leak Test switch in the DCS is toggled to "OFF".
P.
Confirm that the TGCU Start-Up Blower Bypass Valve is fully open.
Q.
Verify that the local stop control for the TGCU Start-Up Blower is set to the run position.
Establishing Nitrogen Flow To establish nitrogen flow into the TGCU, proceed as follows: A.
Toggle the Startup/Run selector switch in the DCS to "STARTUP". The PLC should perform the following actions:
Issued 30 August 2011
(1)
Bypasses the SRU ESD inputs to the TGCU ESD.
(2)
Disables the Tailgas Valve transfer switchs.
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SULFUR BLOCK (3)
Opens the TGCU Quench Column Bypass Valve.
B.
Reset the TGCU ESD by toggling the switch in the DCS to "RESET".
C.
Set the output of the TGCU Warmup/Bypass Valve hand control in the DCS to 0% to close the TGCU Warmup/Bypass Valve and visually confirm that the valve is closed.
D.
Toggle the Nitrogen On/Off switch in the DCS to "ON". The PLC should perform the following actions:
11.8.1.3
(1)
Opens the nitrogen block valves.
(2)
Closes the nitrogen vent valve.
E.
Increase the output of the flow controller to 100% in the DCS to open the control valve and send nitrogen to the front-end of the TGCU.
F.
Allow the nitrogen to purge the front-end of the TGCU for 15 minutes before proceeding to the next step.
Establishing Re-circulation Flow Prior to pre-sulfiding the catalyst in the TGCU Reactor, it is necessary to heat the reactor and catalyst up to 150-175°C. To do this, nitrogen is re-circulated through the TGCU Reactor Feed Heater with the TGCU Start-Up Blower. This re-circulating gas is heated using HP steam in the TGCU Reactor Feed Heater, then flows through the TGCU Reactor Feed Mixer, the TGCU Reactor, and the TGCU Waste Heat Reclaimer bringing the reactor, catalyst, and process heat exchange surfaces up to operating temperature. A.
Visually confirm that the TGCU Start-Up Blower suction block valve and the discharge block valve are closed, the bypass valve is open, the nitrogen purge to the blower seal is in service, and the local "stop" control at the blower is set to the run position.
B.
Start the TGCU Start-Up Blower using the start/stop toggle switch in the DCS. The PLC will perform the following actions: (1)
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SULFUR BLOCK (2)
The TGCU Start-Up Blower Suction Valve is opened.
(3)
The TGCU Start-Up Blower Discharge Valve is opened.
(4)
After the limit switches prove these valves open, the TGCU Start-Up Blower is started.
(5)
Once the Startup Blower is started, the TGCU Start-Up Blower Bypass Valve is closed.
As this valve is closed, the blower will start to load. As it does so, the blower will begin to "pull" nitrogen through the front-end TGCU equipment and all of the associated piping. C.
Once the blower is running, open the TGCU Warmup/Bypass Valve by increasing the output from the hand control to 100%. As the TGCU Warmup/Bypass Valve opens, the TGCU Start-Up Blower will begin re-circulating gas from the outlet of the TGCU Waste Heat Reclaimer back to the TGCU Reactor Feed Heater (via the TGCU Contactor overhead line).
D.
Once re-circulation has been established, place the nitrogen flow controller in "automatic" and reduce its setpoint to about 5-10% of maximum flow.
E.
Slowly begin to increase the setpoint of the steam pressure controller in the DCS to establish steam flow to the TGCU Reactor Feed Heater and increase the temperature of the re-circulating gas stream to 150-175°C.
F.
Open the vent valve on the TGCU Waste Heat Reclaimer to vent air from the steam section.
G.
Confirm that the BFW level controller and control valve to the TGCU Waste Heat Reclaimer are in service and functioning properly.
H.
Place the reactor feed temperature cascade control in service as follows: (1)
Issued 30 August 2011
Confirm that the remote setpoint that the reactor feed temperature controller is supplying to the pressure controller matches the current setting on the pressure controller.
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SULFUR BLOCK
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(2)
Confirm that the reactor feed temperature controller is in "automatic" and its setpoint is tracking its current reading.
(3)
Switch the steam pressure controller to "cascade" so that the temperature controller can now adjust the setpoint on the pressure controller.
(4)
If necessary, slowly adjust the setpoint of the reactor feed temperature controller to 175°C.
(5)
Verify that the steam pressure controller is adjusting the HP steam pressure as needed to control the desired temperature setting on the reactor feed temperature controller.
I.
As the equipment and piping heat up, inspect all of the equipment and piping for the effects of thermal expansion.
J.
As the steam pressure builds in the TGCU Waste Heat Reclaimer, close the vent valve on the steam space. The steam pressure inside the boiler will now be "floating" on the LP steam header.
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SULFUR BLOCK 11.8.2
Pre-Sulfiding the TGCU Catalyst Before introducing sulfur plant tailgas into the TGCU, the catalyst in the TGCU Reactor must be "pre-sulfided" to convert the metals (cobalt and molybdenum) from their inactive oxide state to their active sulfide state. Once the catalyst has been pre-sulfided, it will remain in its active state and will not require pre-sulfiding on subsequent startups. Only when the catalyst is replaced will this pre-sulfiding procedure have to be repeated. The catalyst is pre-sulfided by contacting it with H2S in the presence of hydrogen. The amount of H2S must be controlled at a low concentration to limit the temperature rise as the catalyst reacts with the sulfur, so that excessively high temperatures are not created that could damage the catalyst or the equipment. The catalyst will end up containing about 6 wt % sulfur at the conclusion of this procedure. Before beginning, the following conditions should exist in the TGCU: 1.
The outlet temperature from the TGCU Reactor Feed Heater is on automatic control, maintaining about 175°C.
2.
The nitrogen flow controller is in "automatic" with its set point set at 5-10% of maximum flow to add a small amount of fresh nitrogen to the system.
3.
The TGCU Start-Up Blower is in service, re-circulating nitrogen to the TGCU Reactor Feed Heater.
4.
The Amine Regeneration Unit is operating and producing acid gas. The H2S in this acid gas will be used to pre-sulfide the TGCU catalyst.
Also, ensure that there is an adequate supply on hand (one or two boxes) of gas detector tubes for measuring the H2S concentration into and out of the TGCU Reactor. Sections 9.10.8 and 11.10.7 of these guidelines describe how Dräger tubes can be used to measure the H2S concentration of a gas stream. The H2S concentration will probably be in the range of 1-2%, so Dräger Catalog No. CH 281 01 gas detector tubes are appropriate.
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SULFUR BLOCK 11.8.2.1
Establishing Reducing Gas Flow Before introducing H2S into the TGCU Reactor, reducing gas must be added to the re-circulating gas stream. A.
Confirm that the reducing gas controller in the DCS is set to 0% output and that the control valve in the reducing gas supply line is closed.
B.
Prior to placing the H2/H2S analyzer in service, be sure that its sample line does not contain any water, etc.:
C.
Issued 30 August 2011
(1)
Close the sample valve on the TGCU Waste Heat Reclaimer outlet channel.
(2)
Disconnect the sample line from the sample valve and from the 2-way analyzer sample switching valve. Drain any water from the line and check that it is not plugged, then reinstall the sample line.
(3)
Repeat Step (2) for the other sample line (connected to the sample valve on the TGCU Contactor overhead line).
(4)
Switch the sample selector valve in the analyzer enclosure so that the H2/H2S analyzer takes its sample from the TGCU Contactor overhead line, and use the zero and span gas to confirm the calibration of the analyzer. Make any necessary adjustments to the analyzer per the manufacturer's instructions.
(5)
Switch the sample selector valve in the analyzer enclosure so that the H2/H2S analyzer takes its sample from the outlet of the TGCU Waste Heat Reclaimer, then open the sample valve. The hydrogen analyzer will now be sampling the process gas, as indicated by the reading on the hydrogen controller in the DCS, while the other sample line on the TGCU Contactor overhead line is now being back-purged with nitrogen.
Open the upstream manual block valves and the steam-jacketed block valve in the reducing gas supply line to the TGCU Reactor Feed Mixer.
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SULFUR BLOCK D.
To begin introducing reducing gas into the circulating gas stream, toggle the Reducing Gas On/Off switch in the DCS to "ON". The PLC should perform the following actions:
E.
(1)
Opens the reducing gas block valves.
(2)
Closes the reducing gas vent valve.
Switch the reducing gas controller to "automatic" and slowly begin to increase its setpoint to open the control valve and begin introducing reducing gas into the re-circulating stream. As the reducing gas flow rate increases, the hydrogen concentration displayed on the hydrogen controller will increase.
F.
The reducing gas concentration should be 0.5-5% while pre-sulfiding. If necessary, adjust the setpoint on the reducing gas controller to control the reading in this range. NOTE:
Issued 30 August 2011
It is important to control the hydrogen concentration within this range while pre-sulfiding the catalyst. A hydrogen reading lower than this could mean that a reducing atmosphere is not being maintained inside the TGCU Reactor to insure that the H2S properly sulfides the catalyst. Conversely, too much hydrogen can damage the catalyst by reacting with the cobalt and molybdenum to form inactive metal hydrides.
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SULFUR BLOCK
CAUTION
DO NOT ALLOW HYDROGEN TO CONTACT THE TGCU CATALYST AT TEMPERATURES ABOVE 200°C IN THE ABSENCE OF H2S. IF THERE IS NO H2S PRESENT, THE HYDROGEN WILL REACT IRREVERSIBLY WITH THE CATALYST TO FORM INACTIVE METAL HYDRIDES. IF ANY DELAYS ARE ENCOUNTERED IN INTRODUCING H2S, STOP THE FLOW OF REDUCING GAS UNTIL READY TO RESUME. G.
H.
Issued 30 August 2011
As described in previous sections of these guidelines, the hydrogen controller can adjust the flow of hydrogen to the TGCU Reactor Feed Mixer to control the hydrogen concentration, via the limit relay. Place the hydrogen concentration cascade control in service as follows: (1)
Confirm that the remote setpoint that the hydrogen controller is supplying to the reducing gas flow controller in the DCS matches the current setting on the flow controller.
(2)
Confirm that the hydrogen controller is in "automatic" and its setpoint is tracking its current reading.
(3)
Switch the reducing gas controller to "cascade" so that the concentration controller can now adjust the setpoint of the flow controller.
(4)
If necessary, slowly adjust the setpoint of the hydrogen controller to 2%.
Periodically check that the hydrogen controller and the reducing gas controller maintain the hydrogen concentration in the proper range (0.5-5%) throughout the pre-sulfiding operation.
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SULFUR BLOCK 11.8.2.2
Pre-Sulfiding the Catalyst The sulfur for pre-sulfiding the TGCU catalyst comes from H2S in the amine acid gas produced by the Amine Regeneration Unit. The amount of acid gas entering the TGCU Reactor Feed Mixer is to be adjusted to give an H2S concentration of about 1-2% going into the TGCU Reactor. Gas detector tubes can be used to measure the H2S concentration in the inlet and outlet from the TGCU Reactor. When the outlet H2S concentration is essentially the same as the inlet concentration, then the catalyst has absorbed all the sulfur that it can and pre-sulfiding is complete at that temperature level. A.
Confirm that the pre-sulfiding gas flow controller in the DCS is set to 0% output, and that the control valve in the pre-sulfiding gas supply line is closed.
B.
Verify that the automated shutdown valve, and the manual block valves in the pre-sulfiding gas supply line are closed. Rotate the spectacle blind to the open position, then briefly open the drain valve to verify that there are no liquids in the line between the control valve and the shutdown valve.
C.
Open the manual block valves in the pre-sulfiding gas line.
D.
Toggle the Pre-sulfiding Gas On/Off switch in the DCS to "ON". The PLC should open the automated pre-sulfiding gas block valve.
E.
Place the pre-sulfiding gas flow controller in "automatic" and increase its setpoint to slowly open the control valve and allow a small flow of acid gas into the TGCU Reactor Feed Mixer. Adjust the setpoint as necessary to give an H2S concentration of 1-2% (measured with the gas detector tubes) in the inlet to the TGCU Reactor.
F.
Using the reactor feed temperature controller in the DCS, slowly raise the TGCU Reactor inlet temperature stepwise to 200°C while maintaining the H2S concentration in the inlet at 1-2% and the hydrogen concentration indicated on the hydrogen controller at 0.5-5%. Look for signs that the H2S has begun to react with the catalyst (i.e. the temperatures in the reactor begin to rise). If no
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SULFUR BLOCK temperature rise is seen in the TGCU Reactor, proceed to Step I.
CAUTION
IF EXCESSIVE CATALYST BED TEMPERATURES OCCUR AT ANY TIME ON THE REACTOR BED TEMPERATURE INDICATORS IN THE DCS, REDUCE THE AMOUNT OF H2S IN THE REACTOR INLET. THE TEMPERATURE RISE IN THE REACTOR IS DUE TO THE HEAT OF REACTION FROM H2S REACTING WITH THE CATALYST. REDUCING THE H2S CONCENTRATION WILL REDUCE THE REACTION RATE AND REDUCE THE TEMPERATURE RISE ACCORDINGLY. DO NOT REDUCE THE H2S CONCENTRATION TO ZERO, HOWEVER. THIS WOULD ALLOW HYDROGEN TO REACT WITH THE CATALYST AND DAMAGE IT AS DISCUSSED PREVIOUSLY.
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G.
Once the TGCU Reactor inlet temperature reaches 200°C, maintain this temperature while sampling the H2S concentration in the inlet and outlet of the reactor.
H.
When the outlet H2S concentration is approximately equal to the inlet concentration, pre-sulfiding is complete at this temperature level.
I.
Increase the inlet temperature stepwise to 230°C with the reactor feed temperature controller.
J.
Once the TGCU Reactor inlet temperature reaches 230°C, maintain this temperature while sampling the H2S concentration in the inlet and outlet of the reactor. When the outlet H2S concentration is approximately equal to the inlet concentration, pre-sulfiding is complete at this temperature level.
K.
Increase the inlet temperature stepwise to 260°C with the reactor feed temperature controller.
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SULFUR BLOCK After the entire bed reaches 260°C, hold it at this temperature for 4 hours. Monitor the catalyst bed temperatures and the TGCU Reactor outlet temperature through the temperature indicators in the DCS carefully as the reaction front moves through the bed. Do not allow any of these temperatures to exceed 340°C, by reducing the inlet temperature and/or the inlet H2S concentration as necessary. L.
At the conclusion of the 4 hour heat soak at 260°C, the H2S concentration should be the same in the outlet gas as it is in the inlet gas. If not, continue to hold the inlet at 260°C until the concentrations are equal.
M.
The catalyst is now in its active state. Discontinue the flow of pre-sulfiding gas by reducing the setpoint of the pre-sulfiding gas flow controller to 0%. Toggle the Pre-sulfiding Gas On/Off switch in the DCS to "OFF" to close the block valve and visually confirm that the valve is closed.
N.
Close the manual block valves in the pre-sulfiding gas supply line. THE PRE-SULFIDING LINE WILL NOT BE USED AGAIN UNTIL THE CATALYST IN THE TGCU REACTOR IS REPLACED AND A FRESH CHARGE CATALYST MUST BE PRE-SULFIDED. TO MINIMIZE THE CHANCE OF INADVERTENTLY SENDING AMINE ACID GAS TO THE TGCU REACTOR FEED HEATER, IT IS RECOMMENDED THAT THE SPECTACLE BLIND BE ROTATED BACK TO THE CLOSED POSITION AT THIS TIME.
O.
Slowly lower the TGCU Reactor inlet temperature to its normal value by adjusting the setpoint of the reactor feed temperature controller.
P.
Slowly adjust the setpoint of the hydrogen controller to its normal values (3%). Verify that the reducing gas flow controller is adjusting the rate accordingly. The TGCU can continue operating in this manner indefinitely until ready to bring SRU tailgas into the unit. During this time, observe the temperatures in the TGCU Reactor and the
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SULFUR BLOCK hydrogen concentration on the hydrogen controller to be sure that these control loops are operating properly. Also, continue to observe the operation of the TGCU Waste Heat Reclaimer to ensure that no problems develop in this boiler, and monitor the operation of the TGCU Start-Up Blower.
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SULFUR BLOCK 11.8.3
Routing SRU Tailgas to the TGCU The TGCU is now ready to accept tailgas from the SRUs. At first, the tailgas will be routed through just the front-end of the TGCU (TGCU Reactor Feed Heater, TGCU Reactor Feed Mixer, TGCU Reactor, and TGCU Waste Heat Reclaimer). Then, once this part of the process has “lined out”, the process gas will be switched into the TGCU Quench Column and the TGCU Contactor. Before beginning, the following conditions should exist in the TGCU: 1.
The Reactor Feed Heater is operating smoothly and the inlet temperature to the TGCU Reactor is being controlled at 230-240°C.
2.
The TGCU Reactor is up to normal operating temperature and its catalyst has been pre-sulfided.
3.
The TGCU Start-Up Blower is in service, re-circulating nitrogen to the TGCU Reactor Feed Heater.
4.
The H2/H2S analyzer has been calibrated and is sampling the process gas leaving the TGCU Waste Heat Reclaimer.
5.
The hydrogen controller is controlling the hydrogen at or above the normal setpoint
6.
One or both SRUs are operating smoothly on amine acid gas, or amine acid gas and SWS gas, and the air demand indicated on the air control is +2.0% or lower. (If the air demand is higher than this, the tailgas from the SRU contains excessive amounts of SO2 and could cause overheating of the TGCU Reactor.)
If any of these conditions are not true, do not attempt to bring SRU tailgas into the TGCU. In particular, do not attempt switching tailgas into the TGCU when the SRU(s) is(are) experiencing an upset. The result will be multiple upset units to deal with. Instead, focus your attention on stabilizing the operation of the SRU(s) first (usually by correcting a problem in the upstream Amine Regeneration and/or Sour Water Stripper units), and then use the procedure that follows to establish tailgas flow into the TGCU.
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SULFUR BLOCK 11.8.3.1
Introducing SRU Tailgas into the TGCU — Scenario 1 The first scenario to consider for introducing tailgas into the TGCU is a normal startup of the SRUs and the TGCU. Before being routed to the TGCU, the tailgas from both SRUs is sent to the TTO while the TGCU uses the TGCU Startup Blower to re-circulate gas to the TGCU Reactor Feed Heater via the TGCU Warmup/Bypass Valve. Once the TGCU is warmed up and ready to accept tailgas, the Train 1 and Train 2 SRUs can be routed to the TGCU as follows (using the Train 1 SRU for this procedure).
A.
Confirm that the hydrogen controller is in "automatic" and controlling the hydrogen concentration at or above its normal setpoint, (3%).
B.
Toggle the SRU 1 "fast" transfer switch in the DCS, to "TRANSFER TO TGCU". The PLC will perform the following actions: (1)
The SRU 1 Tailgas Valve to the TGCU is opened.
(2)
After the limit switches prove this valve open, the SRU 1 Tailgas Valve to the TTO is closed.
Visually confirm that these valves have moved to the proper positions. At this point, the tailgas from SRU 1 can flow to the TTO via either of two routes:
C.
(1)
Through the SRU 1 Tailgas Valve to the TGCU and then through the TGCU Warmup/Bypass Valve.
(2)
Through the SRU 1 Tailgas Valve to the TGCU and then through the TGCU Reactor Feed Heater, the TGCU Reactor, the TGCU Waste Heat Reclaimer, and the TGCU Start-Up Blower.
If the second SRU (Train 2) is also ready to send its tailgas to the TGCU, toggle the SRU 2 "fast" transfer switch in the DCS to repeat these actions for the other SRU. For this scenario, the opening and closing of Tailgas Valves to the TGCU and the Tailgas Valves to the TTO in Steps B and C can occur rapidly with no impact on either the SRU or the TGCU. This is because the TGCU Warmup/Bypass Valve will still be open at this
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SULFUR BLOCK time, so there will be very little differential pressure across the Tailgas Valves to the TGCU and there will not be an abrupt change in pressure when the Tailgas Valves to the TGCU are opened or when the Tailgas Valves to the TTO are closed. Note:
The “fast” transfer switches can also be used to take the Train 1 SRU and/or Train 2 SRU tailgas out of the TGCU. Every other toggle of these selector switches will take the opposite action to open the tailgas valve to the TTO and then close the tailgas valve to the TGCU.
In the next step, the TGCU Warmup/Bypass Valve is closed to force the process gas to take the second path, so that the TGCU Start-Up Blower can be shut down. D.
Slowly reduce the output from the hand control to 0% to close the TGCU Warmup/Bypass Valve. Now all of the SRU tailgas must flow through the TGCU Reactor Feed Heater, etc. as this is the only open flowpath to the TTO.
E.
With the SRU tailgas flowing through the TGCU Reactor Feed Heater, the re-circulation from the TGCU Start-Up Blower is no longer needed. Shut down the TGCU Start-Up Blower using the start/stop selector switch in the DCS. The PLC will perform the following actions: (1)
The TGCU Start-Up Blower bypass valve is opened and proved open.
(2)
The TGCU Start-Up Blower is stopped.
(3)
The nitrogen purge valve is opened.
(4)
The TGCU Start-Up Blower Suction Valve and the TGCU Start-Up Blower Discharge Valve are closed.
Confirm that these valves have moved to the proper positions and that the blower has stopped. F.
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Place the nitrogen flow controller in "manual" and set its output to 0% to close the control valve and stop the flow of nitrogen into the TGCU.
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SULFUR BLOCK G.
Toggle the Nitrogen On/Off switch in the DCS to "OFF". The PLC should perform the following actions: (1)
Closes nitrogen blocks.
(2)
Opens nitrogen vent valve.
H.
Close the downstream steam-jacketed block valve in the nitrogen supply line where it joins the tailgas line to the TGCU Reactor Feed Mixer.
I.
Allow the TGCU to operate in this fashion until all operating conditions are stable. In particular, observe the operation of the reactor feed temperature controller and the hydrogen controller to ensure that the TGCU Reactor inlet temperature remains under control and there is adequate hydrogen (2% or higher) in the TGCU Reactor outlet. At this point, all of the tailgas from both SRUs is flowing into the TGCU Reactor Feed Heater, mixing with the external reducing gas in the TGCU Reactor Feed Mixer, entering the TGCU Reactor to convert all of the sulfur compounds to H2S, being cooled in the TGCU Waste Heat Reclaimer, and flowing through the TGCU Quench Column Bypass Valve and the TGCU Start-Up Blower Bypass Valve to the Thermal Oxidizer via the TGCU Contactor overhead line and the TGCU Outlet Valve. Once the operation of the TGCU front-end has stabilized, the process gas can be introduced into the TGCU columns as described in Section 11.8.5 of these guidelines. If the columns are not ready the front-end of the TGCU can operate indefinitely in this manner until ready to switch the process gas to the columns.
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SULFUR BLOCK 11.8.3.2
Introducing SRU Tailgas into the TGCU — Scenario 2 The second startup scenario to consider is when the TGCU is already processing tailgas from one SRU, and the tailgas from the second SRU needs to be introduced into the TGCU. Assume that the Train 2 SRU is currently feeding the TGCU. Due to the back-pressure from the TGCU, the pressure downstream of SRU 1 Tailgas Valve to the TGCU will be about 0.07 kg/cm2(g), while the pressure upstream of this valve will be close to kg/cm2(g) (since the SRU 1 Tailgas Valve to the TTO will be open to the TTO at this time). If the Train 1 tailgas was quickly switched into the TGCU in the same manner as described above for the first scenario, a major upset would result in both SRUs and in the TGCU: As soon as the SRU 1 Tailgas Valve to the TGCU started to open, tailgas from the Train 2 SRU would begin to back-flow through the SRU 1 Tailgas Valve to the TGCU and flow to the TTO, since the pressure downstream of the SRU 1 Tailgas Valve to the TGCU at that moment would be higher than the pressure upstream of the SRU 1 Tailgas Valve to the TGCU. Since the SRU 1 Tailgas Valve to the TGCU is a more direct path to the TTO for the tailgas from the Train 2 SRU, most of the Train 2 tailgas would flow through the SRU 1 Tailgas Valve to the TGCU as it opens rather than flow through the TGCU. The outlet temperature from the TGCU Reactor Feed Heater in the TGCU would begin to rise (due to the drop in tailgas flow) while the controls began reducing the steam flow rate to the heater. Once the SRU 1 Tailgas Valve to the TGCU was fully open, all of the Train 1 tailgas and most of the Train 2 tailgas would be flowing directly to the TTO. The TGCU controls would continue reducing the steam flow rate to the TGCU Reactor Feed Heater to try to keep its outlet temperature under control. Then, once the SRU 1 Tailgas Valve to the TGCU was fully open, the SRU 1 Tailgas Valve to the TTO would begin to close. This would begin forcing all of the Train 1 tailgas and Train 2 tailgas into the TGCU Reactor Feed Heater. The outlet temperature from it would begin to drop while the controls began increasing the steam flow rate to the heater. Once the SRU 1 Tailgas Valve to the TTO was fully closed, all of the Train 1 and Train 2 tailgas would be flowing to the TGCU Reactor Feed Heater, causing an abrupt increase in its operating pressure from about 0.07 kg/cm2(g) to about 0.3 kg/cm2(g).
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SULFUR BLOCK This would cause the air and acid gas flow rates to the SRUs to suddenly drop, possibly causing the SRUs to flame-out. If so, the SRUs and the TGCU would shut down and the operators would have to start over again. If the SRUs and TGCU did manage to stay on-line, the TGCU Reactor Feed Heater would only be supplying about half as much heating as needed until the controls recover and bring the steam flow rate up to the new requirements. Until the controls recover, the inlet temperature to the TGCU Reactor would be low, possibly causing incomplete conversion of SO2 in the reactor and allowing SO2 to reach the quench water system and foul it. The reducing gas flow rate might also require time to adjust to the higher tailgas flow rate, further compounding the problems with conversion in the reactor. So, the best that could be expected if the second SRU is routed to the TGCU in the same manner as under the first scenario is an upset in both SRUs, the TGCU Reactor Feed Heater, the TGCU Reactor, and the quench water system. Depending on how quickly the SRUs respond to sudden changes in operating pressure, the SRU burners might flame-out. In this worst case, a complete restart of the SRUs and the TGCU would then be required. Instead of introducing the tailgas from the second SRU into the TGCU in an abrupt manner, what is needed is a slow, controlled redirection of the tailgas from the TTO to the TGCU. This can be accomplished by the DCS operator using the hand controls for the SRU 1 Tailgas Valve to the TTO and the SRU 1 Tailgas Valve to the TGCU. Under this scenario, the TGCU is already processing tailgas from the Train 2 SRU. This means that the TGCU warmup/bypass valve is already closed. This signals the PLC to disable the "fast" transfer switches in the DCS, so that the rapid switching sequence (scenario 1) cannot be activated inadvertently. A.
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Initiate the over-ride for the Train 1 tailgas valves by toggling the Train 1 "slow" transfer switch in the DCS, to "OVER-RIDE". The PLC temporarily removes the limit switches on the SRU 1 Tailgas Valve to the TTO and the SRU 1 Tailgas Valve to the TGCU from the "complete flowpath interlock" for the Train 1 SRU alarms and deactivates the "valve malfunction" alarms on these two valves, then
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SULFUR BLOCK directs the DCS to release control of the hand controls for these valves to the operator. B.
Use the hand control to slowly begin throttling the tailgas flow with the SRU 1 Tailgas Valve to the TTO, so that the pressure at the front-end of Train 1 is slightly higher than at the front-end of the Train 2 SRU. Monitor the flows and pressure in the Train 1 SRU and adjust the hand control accordingly.
C.
Once the SRU 1 Tailgas Valve to the TTO is throttling, use the other hand control to slowly open the SRU 1 Tailgas Valve to the TGCU. Some of the Train 1 tailgas may begin to flow into the TGCU at this time, but most of it will still flow through the SRU 1 Tailgas Valve directly to the TTO. Monitor the flows and pressures in the Train 1 SRU and the TGCU, and adjust the rate at which he opens the SRU 1 Tailgas Valve to the TGCU accordingly.
D.
Once the SRU 1 Tailgas Valve to the TGCU is fully open, use the hand control to slowly close the SRU 1 Tailgas Valve to the TTO the rest of the way and send all of the Train 1 tailgas to the TGCU. Monitor the flow rates and temperatures in the TGCU, and adjust the rate at which he closes the SRU 1 Tailgas Valve to the TTO as needed to allow time for the controls in the TGCU to respond.
E.
Once the SRU 1 Tailgas Valve to the TTO is fully closed, the Train 1 SRU is flowing to the TGCU along with the Train 2 SRU, and the TGCU is fully on-line. Once both valves have moved into position, the PLC will automatically restore the limit switches on the SRU 1 Tailgas Valve to the TTO and the SRU 1 Tailgas Valve to the TGCU to the "complete flowpath interlock" in the SRU alarms, restore the malfunction alarms for these valves to their normal configurations, and reset the "slow" transfer switch in the DCS, back to "NORMAL" and remove the over-ride. One further point to note is that the "slow" transfer over-ride switches can also be used to "back" tailgas out of the TGCU. If the operator wants to shut down the TGCU in a controlled fashion, this can be accomplished by using the TGCU Startup Blower to circulate gas through the TGCU Reactor Feed Heater while slowly "backing" the SRU tailgas out of the TGCU. The steps to perform this are essentially the same as those listed above (but in reverse order).
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SULFUR BLOCK 11.8.4
Quench Water and Amine Systems Before switching process gas into the TGCU Quench Column and the TGCU Contactor, the quench water and amine systems should be operating and ready to accept gas. The operating conditions described below should have been established previously at the conclusion of the washing operations, but are repeated below to serve as a "checklist" before introducing process gas to the columns as described in Section 11.8.5 that follows.
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A.
The quench water system should be charged with its initial fill of water, so that the level in the TGCU Quench Column is at the normal setpoint for the Quench Column level controller.
B.
Quench water should be circulating to the TGCU Quench Column at the normal setpoint for the quench water flow controller.
C.
Cooling water should be flowing to the TGCU Quench Water Trim Cooler and the TGCU Lean Amine Trim Cooler.
D.
The fans should be operating on the TGCU Quench Water Cooler, with the temperature controller on the quench water controlling at its normal setpoint or lower.
E.
The TGCU Quench Water Filter should be in service with the filtered quench water flow controller controlling at its normal setpoint.
F.
The quench water pH analyzer should be in service (with one pH Meter Sample Filter in service, and the other blocked-in for use as a spare) with the quench water pH analyzer in the DCS showing a pH of 11 or higher. Add caustic to the quench water if necessary to raise the pH to this level.
G.
The amine system should be charged with its initial fill of amine, with the level control in the DCS controlling the level in the TGCU Contactor at its normal setpoint.
H.
The MDEA concentration in the amine should be close to its design value (45 wt %). Add more fresh MDEA if necessary to bring the amine to this strength.
I.
Amine should be circulating through the TGCU Stripper, the TGCU Lean/Rich Exchanger, the TGCU Lean Amine Cooler, and the TGCU Lean Amine Trim Cooler to the distributor tray at the top of the TGCU Contactor at the normal setpoint for the flow controller.
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SULFUR BLOCK J.
The fans should be operating on the TGCU Lean Amine Cooler, with the temperature controller on the lean amine controlling at its normal setpoint or lower.
K.
The TGCU Rich Amine Filter should be in service.
L.
The TGCU lean amine filters should be in service.
M.
Steam should be flowing to the TGCU Stripper Reboiler at the normal setpoint for the flow control.
N.
The overhead temperature from the TGCU Stripper should be above the low temperature alarm point for the temperature indicator.
O.
The fans should be operating on the TGCU Stripper Reflux Condenser with the temperature controller on the outlet from the TGCU Stripper Reflux Condenser controlling at its normal setpoint or lower.
P.
The TGCU Stripper pressure controller to the SRU, should be in "manual" with its output set to 0% so that the pressure control valve is fully closed.
Q.
The TGCU Stripper pressure controller to the flare should be in "automatic" with its setpoint set at its normal value.
R.
The level in the TGCU Stripper Reflux Accumulator should be at the normal setpoint for the level control.
S.
A TGCU Stripper Reflux Pump should be operating with the minimum flow lined up to allow reflux to spill back into the TGCU Stripper Reflux Accumulator whenever the level valve back to the TGCU Stripper is closed.
With these operating conditions established, the back-end of the TGCU is ready to accept the process gas from the front-end of the unit and begin treating it.
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SULFUR BLOCK 11.8.5
Process Gas Flow to the TGCU Columns The last step in the startup of the TGCU is to bring the process gas from the front-end of the TGCU into the TGCU Quench Column and the TGCU Contactor. The TGCU will then remove the H2S from the gas before sending it to the TTO. The H2S removed will be stripped from the amine and sent to the flare initially. Once operation of the amine system stabilizes, this acid gas will be recycled back to the SRUs. Before introducing process gas into the TGCU columns, confirm that the following conditions are all true: 1.
The front-end of the TGCU is processing SRU tailgas and is operating smoothly on automatic control.
2.
The hydrogen controller is controlling the hydrogen concentration in the outlet of the TGCU Reactor at or above its setpoint.
3.
The proper operating conditions have been established for the quench water and amine systems (see Section 11.8.4).
If any of these conditions are not true, do not proceed until correcting the problem(s). Once all of these conditions are satisfied, complete the startup of the TGCU as follows: A.
Confirm that the Quench Column hand control in the DCS is set to 0% output with the TGCU Quench Column Inlet Valve closed and the TGCU Quench Column Bypass Valve open.
B.
Use the drain valve downstream of the TGCU Waste Heat Reclaimer to drain any liquids that may have accumulated in the TGCU Quench Column inlet line.
C.
Slowly increase the output from the Quench Column hand control to 100%, which will open the Quench Column inlet valve and admit process gas to the TGCU Quench Column, then close the TGCU Quench Column Bypass Valve to prevent gas from bypassing to the Thermal Oxidizer. Note that the pressure drop through the TGCU Quench Column and the TGCU Contactor will raise the operating pressures of the SRU and the TGCU and can affect the process gas flow rates, so allow time for the flow and flow-ratio control loops to respond.
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SULFUR BLOCK D.
When the output of the Quench Column hand control reaches 100%, the Quench Column inlet valve should be fully open and the TGCU Quench Column Bypass Valve fully closed to send all of the process gas into the TGCU Quench Column. Visually confirm that these valves are properly positioned.
E.
As process gas flows into the columns, watch the operation of the quench water system carefully. It is typical to see a slow decrease in the quench water pH as H2S in the process gas dissolves into the water, but a rapid decline in pH could indicate SO2 in the process gas from incomplete reaction in the TGCU Reactor. Be ready to add caustic if needed to keep the pH above 7. NOTE:
The quench water will probably turn black or green on this first introduction of H2S into the system (due to small particles of iron sulfide in the water). The TGCU Quench Water Filter should clear up the water in a few hours.
F.
If the quench water pH drops drastically or there is a sudden drop in the hydrogen concentration on the hydrogen controller, the process gas can be "backed" out of the columns by reducing the output of the Quench Column hand control back to 0%. This will open the TGCU Quench Column Bypass Valve to divert the gas to the TTO and close the Quench Column inlet valve to stop gas from flowing into the TGCU Quench Column. Once the operating problem is corrected and the hydrogen controller is once again showing adequate hydrogen, use the Quench Column hand control to re-initiate gas flow to the columns.
G.
Once the columns are operating stably, switch the H2/H2S analyzer to take its sample from the TGCU Contactor overhead line by checking that the sample line is clear of liquid, confirming that the sample valve on the overhead line is open, and switching the sample selector valve in the analyzer enclosure to sample from the TGCU Contactor overhead line. (Note that the sample line on the outlet from the TGCU Waste Heat Reclaimer is now being back-purged with nitrogen.) The gas stream from the TGCU Contactor is "cleaner" than the one leaving the TGCU Waste Heat Reclaimer and is less likely to cause problems in the hydrogen analyzer. However, if the Quench Column hand control is used to divert gas to the TTO during an upset as
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SULFUR BLOCK described in the previous step, the analyzer must be switched back to the outlet of the TGCU Waste Heat Reclaimer to get a good reading, as gas will no longer be flowing in the TGCU Contactor overhead line. H.
Once the operation of the TGCU Stripper has stabilized, route its acid gas, which is presently going to the flare through a pressure valve, back to the SRUs as follows: (1)
Confirm that the TGCU Stripper pressure controller to the SRUs in the DCS is in "manual" with its output set to 0%.
(2)
Confirm that the setpoint of the TGCU Stripper pressure controller to the SRUs is tracking its current reading, then place it in "automatic".
(3)
Slowly raise the setpoint of the TGCU Stripper pressure controller to the flare to 1.0 kg/cm2(g).
(4)
If, necessary, adjust the setpoint of the TGCU Stripper pressure controller to the SRU to its normal setpoint.
The TGCU Stripper pressure controller will now take over control of the TGCU Stripper pressure by opening the pressure valve to send the acid gas to the Acid Gas Knock-Out Drums in the SRUs. The TGCU Stripper pressure controller to the flare will close the acid gas pressure valve and stop the flow of acid gas to the flare. If the SRUs shut down (or some other upset causes the TGCU Stripper pressure to rise), the TGCU Stripper pressure controller to the flare will act as an over-ride and divert the acid gas to the flare. I.
If desired, the quench water and amine systems can be optimized at this time for more efficient operation, or for more capacity to handle upsets. Section 11.6 offers suggestions and guidelines for these systems. If maximizing the capacity to handle process upsets without going out of compliance is desired, consider the following suggestions: (1)
Issued 30 August 2011
Lower the setpoint of the temperature controller on the quench water to maximize the aerial cooling. This will cool the feed gas to the TGCU Contactor as much as possible to minimize the load on the column and improve amine selectivity and treating ability.
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SULFUR BLOCK (2)
Lower the setpoint of the temperature control on the lean amine to maximize the aerial cooling. This will cool the amine to the TGCU Contactor as much as possible to maximize the amine selectivity and treating ability.
(3)
Lower the setpoint of the temperature controller on the outlet from the TGCU Stripper Reflux Condenser as much as possible. This will minimize the water content of the TGCU acid gas returning to the sulfur plant and improve the recovery there.
The aerial coolers and trim coolers will not be able to maintain these temperatures when the ambient conditions are very warm, of course. However, setting the controllers this way will keep the fan speed high to maximize cooling at all times. J.
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The TGCU is now fully on-stream. Before directing your attention away from the TGCU, be sure that: (1)
Both SRU Tailgas Valves to the TTO and the TGCU Warmup/Bypass Valve are fully closed (to prevent leakage of SRU tailgas to the Thermal Oxidizer that would cause high SO2 emissions and the resulting permit violation).
(2)
The TGCU Quench Column Bypass Valve is fully closed (to prevent leakage of TGCU Reactor effluent to the Thermal Oxidizer that would cause high SO2 emissions and the resulting permit violation).
(3)
All controllers are functioning properly.
(4)
The steam heating systems are in service on the jacketed sulfur vapor valves and the steam traps are functioning properly.
(5)
The Thermal Oxidizer is functioning properly.
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SULFUR BLOCK 11.8.6
Normal Startup of the TGCU The procedure for startup of the TGCU after it has been shut down will be very similar to the procedure for the initial startup, Sections 11.8.1 through 11.8.5 of these guidelines, except that the catalyst will not require pre-sulfiding. For ease of reference, the steps to be performed are written in this Section to serve as a "check list" that can be easily followed on subsequent startups. Refer to the previous Sections for the reasons and details pertaining to the different steps performed. Prior to commencing TGCU startup:
11.8.6.1
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(1)
Check for the completion of all maintenance work (connecting lines, removing blinds, etc.) if such work was performed.
(2)
If any of the flanged connections in the TGCU were opened for maintenance or other purposes while the TGCU was off-line, it is good practice to leak test the TGCU before returning it to service. Refer to Section 11.7.5 of these guidelines for a suggested procedure to accomplish this.
(3)
Place all the steam heating systems on the sulfur vapor valve jackets in service. Check all steam traps for proper operation, and use the vent valves to sweep non-condensibles out of the steam spaces.
(4)
Physically check all shutdown activating devices to ensure that they activate the TGCU ESD system.
(5)
Physically check all devices activated by the TGCU ESD system to ensure that they operate properly.
Initial Preparations A.
Confirm that steam pressure controller in the DCS is in "manual" with its output set to 0%, and that control valve in the HP Steam supply line to the TGCU Reactor Feed Heater is closed.
B.
Place the reactor feed temperature controller in "automatic".
C.
Confirm that reducing gas flow controller in the DCS is in "manual" with its output set to 0%, and that the control valve in the reducing gas supply line to the TGCU Reactor Feed Mixer is closed.
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SULFUR BLOCK
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D.
Place the hydrogen controller in "automatic".
E.
Verify that the automated shutdown valves, the block valves, and the downstream steam-jacketed block valve in the reducing gas line to the TGCU Reactor Feed Mixer are all closed.
F.
Confirm that pre-sulfiding gas flow controller in the DCS is in "manual" with its output set to 0%, and that the control valve in the pre-sulfiding gas line to the TGCU Reactor Feed Mixer is closed.
G.
Verify that the automated shutdown valve and the upstream block valves in the pre-sulfiding gas line to the TGCU Reactor Feed Mixer are both closed.
H.
Confirm that the nitrogen flow controller in the DCS is in "manual" with its output set to 0% output, and that the control valve in the nitrogen supply line is closed.
I.
Verify that the shutdown valves are closed in the nitrogen supply line, and the upstream block valves are open. Open the downstream steam-jacketed block valve.
J.
Confirm that the Quench Column hand control in the DCS is set to 0% output, so that the TGCU Quench Column inlet valve will remain fully closed and the TGCU Quench Column bypass valve will open later in when the TGCU startup/run selector switch is switched to "STARTUP".
K.
Confirm that the TGCU Waste Heat Reclaimer is filled with water up to its normal liquid level.
L.
Visually confirm that both SRU Tailgas Valves to the TGCU are closed.
M.
Visually confirm that the manual TGCU Outlet Valve is fully open.
N.
Confirm that the Leak Test switch in the DCS is toggled to "OFF".
O.
Confirm that the TGCU Start-Up Blower Bypass Valve is fully open.
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SULFUR BLOCK P.
Verify that the local stop control for the TGCU Start-Up Blower is set to the "RUN" position.
Q.
Check that the sample line from the outlet of the TGCU Waste Heat Reclaimer to the hydrogen analyzer is clear of liquids. Confirm that sample valve on the outlet channel of the boiler is open, then switch the sample selector valve in the analyzer enclosure to sample from the outlet of the TGCU Waste Heat Reclaimer. Note that the other sample line on the TGCU Contactor overhead line is now being back-purged with nitrogen.
11.8.6.2
Purging the Low Pressure TGCU Columns Unless the water or the amine was drained from the low pressure TGCU columns (the TGCU Quench Column and the TGCU Contactor, respectively), or either column was opened for maintenance during the prior shutdown, the columns will not contain air and so will not require purging before proceeding with startup. However, if the activities prior to this startup did allow air to enter either or both columns, this air should be purged from the system before proceeding so that a combustible mixture cannot form in the columns as process gas is introduced. If purging of the columns is required, nitrogen can be introduced using the nitrogen flow controller to purge the air from the columns. This procedure is given in Section 11.7.8 of these guidelines. Refer to and follow this procedure to purge the columns before continuing with Section 11.8.6.3 that follows.
11.8.6.3
Establishing Nitrogen Flow To establish nitrogen flow into the TGCU, proceed as follows: A.
Toggle the Startup/Run selector switch in the DCS to "STARTUP". The PLC should perform the following actions: (a) Bypasses both SRU ESD inputs to the TGCU ESD. (b) Disables the Tailgas Valve toggle switches. (c) Opens the TGCU Quench Column Bypass Valve.
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SULFUR BLOCK B.
Reset the TGCU ESD by toggling the switch in the DCS to "RESET".
C.
Set the output of the hand control in the DCS to 0% to close the TGCU Warmup/Bypass Valve and visually confirm that the valve is closed.
D.
Toggle the Nitrogen On/Off switch in the DCS to "ON". The PLC should perform the following actions:
11.8.6.4
(1)
Opens the nitrogen block valves.
(2)
Closes the nitrogen vent valve.
E.
Increase the output of the nitrogen flow controller to 100% in the DCS to open the control valve and send nitrogen to the front-end of the TGCU.
F.
Allow the nitrogen to purge that front-end of the TGCU for 15 minutes before proceeding to the next step.
Establishing Re-circulation Flow A.
Start the TGCU Start-Up Blower using the start/stop toggle switch in the DCS. The PLC will perform the following actions: (1)
The nitrogen purge valve is closed.
(2)
The TGCU Start-Up Blower Suction Valve is opened.
(3)
The TGCU Start-Up Blower Discharge Valve is opened.
(4)
After the limit switches prove these valves open, the TGCU Start-Up Blower is started.
(5)
Once the Startup Blower is started, the TGCU Start-Up Blower Bypass Valve is closed.
As this valve is closed, the blower will start to load. As it does so, the blower will begin to "pull" nitrogen through the front-end TGCU equipment and all of the associated piping. B.
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Once the blower is running, open the TGCU Warmup/Bypass Valve by increasing the output from the hand control to 100%.
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SULFUR BLOCK As the TGCU Warmup/Bypass Valve opens, the TGCU Start-Up Blower will begin re-circulating gas from the outlet of the TGCU Waste Heat Reclaimer back to the TGCU Reactor Feed Heater (via the TGCU Contactor overhead line).
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C.
Once re-circulation has been established, place the nitrogen flow controller in "automatic" and reduce its setpoint to about 5-10% of maximum flow.
D.
Slowly begin to increase the setpoint of the steam pressure controller in the DCS to establish steam flow to the TGCU Reactor Feed Heater and increase the temperature of the re-circulating gas stream to 150-175°C.
E.
Open the vent valve on the TGCU Waste Heat Reclaimer to vent air from the steam section.
F.
Confirm that the BFW level controller and control valve to the TGCU Waste Heat Reclaimer are in service and functioning properly.
G.
Place the reactor feed temperature cascade control in service as follows: (1)
Confirm that the remote setpoint that the reactor feed temperature controller is supplying to the pressure controller matches the current setting on the pressure controller.
(2)
Confirm that the reactor feed temperature controller is in "automatic" and its setpoint is tracking its current reading.
(3)
Switch the steam pressure controller to "cascade" so that the temperature controller can now adjust the setpoint on the pressure controller.
(4)
If necessary, slowly adjust the setpoint of the reactor feed temperature controller to 175°C.
(5)
Verify that the steam pressure controller is adjusting the HP steam pressure as needed to control the desired temperature setting on the reactor feed temperature controller.
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SULFUR BLOCK 11.8.6.5
Establishing Reducing Gas Flow Before introducing SRU Tailgas into the TGCU Reactor, reducing gas must be added to the re-circulating gas stream. A.
Open the upstream manual block valves and the steam-jacketed block valve in the reducing gas supply line to the TGCU Reactor Feed Mixer.
B.
Toggle the Reducing Gas On/Off switch in the DCS to "ON". The PLC should perform the following actions:
C.
(1)
Opens reducing gas block valves.
(2)
Closes reducing gas vent valve.
Place the reducing gas controller in "automatic" and slowly begin to increase its setpoint to open the control valve and begin introducing reducing gas into the re-circulating stream. As the reducing gas flow rate increases, the hydrogen concentration displayed on the hydrogen controller will increase.
D.
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Place the hydrogen concentration cascade control in service as follows: (1)
Confirm that the remote setpoint that the hydrogen controller is supplying to the reducing gas flow controller matches the current setting on the flow controller.
(2)
Confirm that the hydrogen controller is in "automatic" and its setpoint is tracking its current reading.
(3)
Switch the reducing gas controller to "cascade" so that the concentration controller can now adjust the setpoint of the flow controller.
(4)
If necessary, slowly adjust the setpoint of the hydrogen controller to its normal value.
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SULFUR BLOCK 11.8.6.6
Routing SRU Tailgas to the TGCU The TGCU is now ready to accept tailgas from the SRUs. Before beginning, the following conditions should exist in the TGCU: 1.
The Reactor Feed Heater is operating smoothly and the inlet temperature to the TGCU Reactor is being controlled at 230-240°C.
2.
The TGCU Reactor is up to normal operating temperature and its catalyst has been pre-sulfided.
3.
The TGCU Start-Up Blower is in service, re-circulating nitrogen to the TGCU Reactor Feed Heater.
4.
The H2/H2S analyzer has been calibrated and is sampling the process gas leaving the TGCU Waste Heat Reclaimer.
5.
The hydrogen controller is controlling the hydrogen at or above the normal setpoint
6.
One or both SRUs are operating smoothly on amine acid gas, or amine acid gas and SWS gas, and the air demand indicated on the air control is +2.0% or lower. (If the air demand is higher than this, the tailgas from the SRU contains excessive amounts of SO2 and could cause overheating of the TGCU Reactor.)
If any of these conditions are not true, do not attempt to bring SRU tailgas into the TGCU. In particular, do not attempt switching tailgas into the TGCU when the SRU(s) is(are) experiencing an upset. The result will be multiple upset units to deal with. Instead, focus your attention on stabilizing the operation of the SRU(s) first (usually by correcting a problem in the upstream Amine Regeneration and/or Sour Water Stripper units), and then use the procedure that follows to establish tailgas flow into the TGCU.
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SULFUR BLOCK Introducing SRU Tailgas into the TGCU — Scenario 1 The first scenario to consider for introducing tailgas into the TGCU is a normal startup of the SRUs and the TGCU. Before being routed to the TGCU, the tailgas from both SRUs is sent to the TTO while the TGCU uses the TGCU Startup Blower to re-circulate gas to the TGCU Reactor Feed Heater via the TGCU Warmup/Bypass Valve. Once the TGCU is warmed up and ready to accept tailgas, the Train 1 and Train 2 SRUs can be routed to the TGCU as follows (using the Train 1 SRU for this procedure). A.
Confirm that the hydrogen controller is in "automatic" and controlling the hydrogen concentration at or above its normal setpoint, (3%).
B.
Toggle the SRU 1 "fast" transfer switch in the DCS, to "TRANSFER TO TGCU". The PLC will perform the following actions: (1)
The SRU 1 Tailgas Valve to the TGCU is opened.
(2)
After the limit switches prove this valve open, the SRU 1 Tailgas Valve to the TTO is closed.
Visually confirm that these valves have moved to the proper positions. C.
If the second SRU (Train 2) is also ready to send its tailgas to the TGCU, toggle the SRU 2 "fast" transfer switch in the DCS to repeat these actions for the other SRU. For this scenario, the opening and closing of Tailgas Valves to the TGCU and the Tailgas Valves to the TTO in Steps B and C can occur rapidly with no impact on either the SRU or the TGCU. This is because the TGCU Warmup/Bypass Valve will still be open at this time, so there will be very little differential pressure across the Tailgas Valves to the TGCU and there will not be an abrupt change in pressure when the Tailgas Valves to the TGCU are opened or when the Tailgas Valves to the TTO are closed. Note:
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The “fast” transfer switches can also be used to take the Train 1 SRU and/or Train 2 SRU tailgas out of the TGCU. Every other toggle of these selector switches will take the
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SULFUR BLOCK opposite action to open the tailgas valve to the TTO and then close the tailgas valve to the TGCU. D.
Slowly reduce the output from the hand control to 0% to close the TGCU Warmup/Bypass Valve. Now all of the SRU tailgas must flow through the TGCU Reactor Feed Heater, etc. as this is the only open flowpath to the TTO.
E.
Shut down the TGCU Start-Up Blower using the start/stop selector switch in the DCS. The PLC will perform the following actions: (1)
The TGCU Start-Up Blower bypass valve is opened and proved open.
(2)
The TGCU Start-Up Blower is stopped.
(3)
The nitrogen purge valve is opened.
(4)
The TGCU Start-Up Blower Suction Valve and the TGCU Start-Up Blower Discharge Valve are closed.
Confirm that these valves have moved to the proper positions and that the blower has stopped. F.
Place the nitrogen flow controller in "manual" and set its output to 0% to close the control valve and stop the flow of nitrogen into the TGCU.
G.
Toggle the Nitrogen On/Off switch in the DCS to "OFF". The PLC should perform the following actions:
Issued 30 August 2011
(1)
Closes nitrogen blocks.
(2)
Opens nitrogen vent valve.
H.
Close the downstream steam-jacketed block valve in the nitrogen supply line where it joins the tailgas line to the TGCU Reactor Feed Mixer.
I.
Allow the TGCU to operate in this fashion until all operating conditions are stable. In particular, observe the operation of the reactor feed temperature controller and the hydrogen controller to ensure that the TGCU Reactor inlet temperature remains under
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SULFUR BLOCK control and there is adequate hydrogen (2% or higher) in the TGCU Reactor outlet. At this point, all of the tailgas from both SRUs is flowing into the TGCU Reactor Feed Heater, mixing with the external reducing gas in the TGCU Reactor Feed Mixer, entering the TGCU Reactor to convert all of the sulfur compounds to H2S, being cooled in the TGCU Waste Heat Reclaimer, and flowing through the TGCU Quench Column Bypass Valve and the TGCU Start-Up Blower Bypass Valve to the Thermal Oxidizer via the TGCU Contactor overhead line and the TGCU Outlet Valve. Once the operation of the TGCU front-end has stabilized, the process gas can be introduced into the TGCU columns.
Introducing SRU Tailgas into the TGCU — Scenario 2 The second startup scenario to consider is when the TGCU is already processing tailgas from one SRU, and the tailgas from the second SRU needs to be introduced into the TGCU. Under this scenario, the TGCU is already processing tailgas from the Train 2 SRU. This means that the TGCU warmup/bypass valve is already closed. This signals the PLC to disable the "fast" transfer switches in the DCS, so that the rapid switching sequence (scenario 1) cannot be activated inadvertently.
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A.
Initiate the over-ride for the Train 1 tailgas valves by toggling the Train 1 "slow" transfer switch in the DCS, to "OVER-RIDE". The PLC temporarily removes the limit switches on the SRU 1 Tailgas Valve to the TTO and the SRU 1 Tailgas Valve to the TGCU from the "complete flowpath interlock" for the Train 1 SRU alarms and deactivates the "valve malfunction" alarms on these two valves, then directs the DCS to release control of the hand controls for these valves to the operator.
B.
Use the hand control to slowly begin throttling the tailgas flow with the SRU 1 Tailgas Valve to the TTO, so that the pressure at the front-end of Train 1 is slightly higher than at the front-end of the Train 2 SRU. Monitor the flows and pressure in the Train 1 SRU and adjust the hand control accordingly.
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SULFUR BLOCK C.
Once the SRU 1 Tailgas Valve to the TTO is throttling, use the other hand control to slowly open the SRU 1 Tailgas Valve to the TGCU. Some of the Train 1 tailgas may begin to flow into the TGCU at this time, but most of it will still flow through the SRU 1 Tailgas Valve directly to the TTO. Monitor the flows and pressures in the Train 1 SRU and the TGCU, and adjust the rate at which he opens the SRU 1 Tailgas Valve to the TGCU accordingly.
D.
Once the SRU 1 Tailgas Valve to the TGCU is fully open, use the hand control to slowly close the SRU 1 Tailgas Valve to the TTO the rest of the way and send all of the Train 1 tailgas to the TGCU. Monitor the flow rates and temperatures in the TGCU, and adjust the rate at which the SRU 1 Tailgas Valve to the TTO is closed to allow time for the controls in the TGCU to respond.
E.
Once the SRU 1 Tailgas Valve to the TTO is fully closed, the Train 1 SRU is flowing to the TGCU along with the Train 2 SRU, and the TGCU is fully on-line. Once both valve have moved into position, the PLC will automatically restore the limit switches on the SRU 1 Tailgas Valve to the TTO and the SRU 1 Tailgas Valve to the TGCU to the "complete flowpath interlock" in the SRU alarms, restore the malfunction alarms for these valves to their normal configurations, and reset the "slow" transfer switch in the DCS, back to "NORMAL" and remove the over-ride.
11.8.6.7
Quench Water and Amine Systems Before switching process gas into the TGCU Quench Column and the TGCU Contactor, the quench water and amine systems should be operating and ready to accept the process gas.
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A.
The quench water system should be filled with water, so that the level in the TGCU Quench Column is at the normal setpoint for the Quench Column level controller.
B.
Quench water should be circulating to the TGCU Quench Column at the normal setpoint for the quench water flow controller.
C.
Cooling water should be flowing to the TGCU Quench Water Trim Cooler and the TGCU Lean Amine Trim Cooler.
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SULFUR BLOCK
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D.
The fans should be operating on the TGCU Quench Water Cooler, with the temperature controller on the quench water controlling at its normal setpoint or lower.
E.
The TGCU Quench Water Filter should be in service with the filtered quench water flow controller controlling at its normal setpoint.
F.
The quench water pH analyzer should be in service (with one pH Meter Sample Filter in service, and the other blocked-in for use as a spare) with the quench water pH analyzer in the DCS showing a pH of 11 or higher. Add caustic to the quench water if necessary to raise the pH to this level.
G.
The amine system should be filled with amine, with the level control in the DCS controlling the level in the TGCU Contactor at its normal setpoint.
H.
The MDEA concentration in the amine should be close to its design value (45 wt %). Add more fresh MDEA if necessary to bring the amine to this strength.
I.
Amine should be circulating through the TGCU Stripper, the TGCU Lean/Rich Exchanger, the TGCU Lean Amine Cooler, and the TGCU Lean Amine Trim Cooler to the distributor tray at the top of the TGCU Contactor at the normal setpoint for the flow controller.
J.
The fans should be operating on the TGCU Lean Amine Cooler, with the temperature controller on the lean amine controlling at its normal setpoint or lower.
K.
The TGCU Rich Amine Filter should be in service.
L.
The TGCU lean amine filters should be in service, with the flow controller controlling at its normal setpoint.
M.
Steam should be flowing to the TGCU Stripper Reboiler at the normal setpoint for the flow controller.
N.
The overhead temperature from the TGCU Stripper should be above the low temperature alarm point for the temperature indicator.
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SULFUR BLOCK O.
The fans should be operating on the TGCU Stripper Reflux Condenser with the temperature controller on the outlet from the TGCU Stripper Reflux Condenser controlling at its normal setpoint or lower.
P.
The TGCU Stripper pressure controller to the SRU should be in "manual" with its output set to 0% so that the pressure valve is fully closed.
Q.
The TGCU Stripper pressure controller to the flare should be in "automatic" with its setpoint set to its normal value.
R.
The level in the TGCU Stripper Reflux Accumulator should be at the normal setpoint for the level control.
S.
A TGCU Stripper Reflux Pump should be operating with the minimum flow lined up to allow reflux to spill back into the TGCU Stripper Reflux Accumulator whenever the level valve back to the TGCU Stripper is closed.
With these operating conditions established, the back-end of the TGCU is ready to accept the process gas from the front-end of the unit and begin treating it. 11.8.6.8
Process Gas Flow to the TGCU Columns The startup of the TGCU can now be completed by switching the process gas to flow into the columns. Before introducing process gas into the TGCU columns, confirm that the following conditions are all true: 1.
The front-end of the TGCU is processing SRU tailgas and is operating smoothly on automatic control.
2.
The hydrogen controller is controlling the hydrogen concentration in the outlet of the TGCU Reactor at or above its setpoint.
3.
The proper operating conditions have been established for the quench water and amine systems.
If any of these conditions are not true, do not proceed until correcting the problem(s). Once all of these conditions are satisfied, complete the startup of the TGCU as follows:
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SULFUR BLOCK A.
Confirm that the Quench Column hand control in the DCS is set to 0% output with the TGCU Quench Column Inlet Valve closed and the TGCU Quench Column Bypass Valve open.
B.
Use the drain valve downstream of the TGCU Waste Heat Reclaimer to drain any liquids that may have accumulated in the TGCU Quench Column inlet line.
C.
Slowly increase the output from the Quench Column hand control to 100%, which will open the Quench Column inlet valve and admit process gas to the TGCU Quench Column, then close the TGCU Quench Column Bypass Valve to prevent gas from bypassing to the Thermal Oxidizer. Note that the pressure drop through the TGCU Quench Column and the TGCU Contactor will raise the operating pressures of the SRU and the TGCU and can affect the process gas flow rates, so allow time for the flow and flow-ratio control loops to respond.
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D.
When the output of the Quench Column hand control reaches 100%, the Quench Column inlet valve should be fully open and the TGCU Quench Column Bypass Valve fully closed to send all of the process gas into the TGCU Quench Column. Visually confirm that these valves are properly positioned.
E.
As process gas flows into the columns, watch the operation of the quench water system carefully. A sudden drop in pH usually indicates SO2 in the process gas from incomplete reaction in the TGCU Reactor. Be ready to add caustic if needed to keep the pH above 7.
F.
If the quench water pH drops drastically or there is a sudden drop in the hydrogen concentration on the hydrogen controller, the process gas can be "backed" out of the columns by reducing the output of the Quench Column hand control back to 0%. This will open the TGCU Quench Column Bypass Valve to divert the gas to the TTO and close the Quench Column inlet valve to stop gas from flowing into the TGCU Quench Column. Once the operating problem is corrected and the hydrogen controller is once again showing adequate hydrogen, use the Quench Column hand control to re-initiate gas flow to the columns. Tailgas Cleanup
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SULFUR BLOCK G.
Once the columns are operating stably, switch the H2/H2S analyzer to take its sample from the TGCU Contactor overhead line by checking that the sample line is clear of liquid, confirming that the sample valve on the overhead line is open, and switching the sample selector valve in the analyzer enclosure to sample from the TGCU Contactor overhead line. (Note that the sample line on the outlet from the TGCU Waste Heat Reclaimer is now being back-purged with nitrogen.)
H.
Once the operation of the TGCU Stripper has stabilized, route its acid gas, which is presently going to the flare through the pressure valve, back to the SRU as follows: (1)
Confirm that the TGCU Stripper pressure controller to the SRU in the DCS is in "manual" with its output set to 0%.
(2)
Confirm that the setpoint of the TGCU Stripper pressure controller is tracking its current reading, then place it in "automatic".
(3)
Slowly raise the setpoint of the TGCU Stripper pressure controller to the flare to 1.0 kg/cm2(g).
(4)
If necessary, adjust the setpoint of the TGCU Stripper pressure controller to its normal setpoint.
The TGCU Stripper pressure controller will now take over control of the TGCU Stripper pressure by opening the pressure valve to send the acid gas to the Acid Gas Knock-Out Drum in the SRU. The TGCU Stripper pressure controller to the flare will close the next pressure valve and stop the flow of acid gas to the flare. If the SRU shuts down (or some other upset causes the TGCU Stripper pressure to rise), the TGCU Stripper pressure controller to the flare will act as an over-ride and divert the acid gas to the flare.
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I.
If desired, the quench water and amine systems can be optimized at this time for more efficient operation, or for more capacity to handle upsets.
J.
The TGCU is now fully on-stream. Before directing your attention away from the TGCU, be sure that:
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SULFUR BLOCK
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(1)
The SRU Tailgas Valve to the TTO and the TGCU Warmup/Bypass Valve are fully closed (to prevent leakage of SRU tailgas to the Thermal Oxidizer that would cause high SO2 emissions and the resulting permit violation).
(2)
The TGCU Quench Column Bypass Valve is fully closed (to prevent leakage of TGCU Reactor effluent to the Thermal Oxidizer that would cause high SO2 emissions and the resulting permit violation).
(3)
All controllers are functioning properly.
(4)
The steam heating systems are in service on the jacketed sulfur vapor valves and the steam traps are functioning properly.
(5)
The Thermal Oxidizer is functioning properly.
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SULFUR BLOCK
11.9 Shutdown Procedures The procedures to be used in performing a planned shutdown of the TGCU will vary depending on the extent and type of work to be performed in and around the unit during the downtime period. If there are no plans for opening the TGCU such that air would be allowed entry to the catalyst bed in the TGCU Reactor, few special procedures are required in performing the shutdown. In general, unless there is a suspected problem in the TGCU Reactor or the catalyst is to be replaced, there is no benefit to be gained from opening up the TGCU Reactor. If the TGCU Reactor does not need to be opened (or exposed to significant air entry during some other maintenance procedure), there is no need to passivate the TGCU Reactor catalyst. This greatly simplifies and shortens the shutdown procedure. Section 11.9.1 that follows is an example of such a procedure. If the catalyst is to be replaced, if the TGCU Reactor must be entered, or if maintenance on some other portion of the plant will allow a significant amount of air to enter the TGCU Reactor, then more extensive and lengthy procedures must be followed to accomplish a satisfactory shutdown and minimize the time required for performance of the desired maintenance work. Section 11.9.2 that follows is an example of a procedure for this circumstance. There are a couple of special circumstances related to shutdown procedures that are also discussed. Section 11.9.3 discusses considerations for the shutdown procedure when the tubes in the TGCU Waste Heat Reclaimer are leaking. Special precautions to observe while the TGCU is shut down are discussed in Section 11.9.4. Section 11.9.5 is a discussion of emergency shutdown situations. A guide to troubleshooting the causes of unplanned shutdowns is presented to assist in quickly identifying and correcting the problem so the TGCU can be put back on-line in a minimum amount of time. The TGCU is affected directly and indirectly by shutdowns and outages that occur in other systems within the Sulfur Block. The more important aspects of the effects these other systems can have on the TGCU are discussed in Section 11.9.6. Typical shutdown procedures are outlined and discussed in the sections that follow for the more common cases. Your existing company procedures and common sense operational judgment should be used to modify these
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SULFUR BLOCK procedures as needed to serve the purpose of any given planned shutdown situation.
11.9.1
Planned Shutdown - No Reactor Entry When there are no plans to open up the TGCU Reactor, there is no need to passivate the catalyst during the shutdown procedure. Even when entry to other parts of the TGCU is planned, this can normally be accomplished without exposing the catalyst bed to significant amounts of air by using slip-blinds to isolate the TGCU Reactor prior to purging, etc. Under these circumstances, the shutdown procedure given in this section may be used as a guide. Any equipment to be opened should be properly blinded and purged with inert gas before admission of air, to avoid exposure to potentially toxic gases or the formation of flammable vapor mixtures. It is particularly important to isolate the TGCU from the reducing gas and pre-sulfiding gas supply lines. Any equipment containing amine solution that is to be opened or entered should be drained completely, then flushed with condensate or steamed out to avoid the possibility of skin or eye irritation. It is always best, but not absolutely necessary, to purge the sulfur-bearing gases from as much of the TGCU as possible prior to shutting the TGCU down. This minimizes the chance of sulfur plugging in the piping or equipment during the subsequent restart, and minimizes the purging and cleaning required prior to vessel entry. This is accomplished by diverting the SRU tailgas to the Thermal Oxidizer, then using nitrogen to purge the front-end of the TGCU to the Thermal Oxidizer. It is generally preferable to shut down the TGCU in a controlled fashion, particularly if the SRUs are to remain on-line, to minimize the impact on the other process units. If time does not allow performing a controlled shutdown, however, the unit can be shut down by simply activating the TGCU ESD system (using the manual shutdown switch). This will automatically block the feeds into the TGCU (SRU tailgas, reducing gas, pre-sulfiding gas, and nitrogen/utility air) and divert the SRU tailgas to the Thermal Oxidizer, although it results in a much bigger "bobble" to the SRUs.
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SULFUR BLOCK To shut the TGCU down in a controlled fashion and purge the sulfur-bearing gases from the front-end of the unit, proceed as follows: A.
Check that the sample line from the outlet of the TGCU Waste Heat Reclaimer to the H2/H2S analyzer is clear of liquids. Confirm that sample valve on the outlet channel of the boiler is open, then switch the sample selector valve in the analyzer enclosure to the "START-UP" position (taking sample from the outlet of the TGCU Waste Heat Reclaimer).
B.
Visually confirm that the TGCU Start-Up Blower Bypass Valve is fully open and that the DCS indicates that the valve is open.
C.
Slowly reduce the output from the Quench Column hand control in the DCS to divert the process gas from the TGCU columns and send it to the Thermal Oxidizer. The Quench Column hand control will open the TGCU Quench Column Bypass Valve, then close the TGCU Quench Column Inlet Valve.
D.
When the output of the Quench Column hand control reaches 0%, the TGCU Quench Column Bypass Valve should be fully open and the Quench Column inlet valve fully closed to send all of the process gas to the Thermal Oxidizer via the TGCU Start-Up Blower Bypass Valve. Visually confirm that these valves are properly positioned. Confirm that the DCS indicates that the TGCU Quench Column Bypass Valve is open, and that the TGCU Quench Column Inlet Valve is closed.
E.
Toggle the Nitrogen On/Off switch in the DCS to "ON". The PLC should perform the following actions:
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(1)
Opens nitrogen block.
(2)
Closes nitrogen vent valve.
F.
Open the downstream steam-jacketed block valve in the nitrogen supply line where it joins the tailgas line to the TGCU Reactor Feed Mixer.
G.
Increase the output of the nitrogen flow controller to 100% in the DCS to fully open the control valve and send nitrogen to the front-end of the TGCU.
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SULFUR BLOCK H.
Slowly increase the output from the TGCU Warmup/Bypass Valve hand control in the DCS to 100% to fully open the TGCU Warmup/Bypass Valve. Some of the SRU tailgas will continue to flow through the TGCU Reactor Feed Heater, etc. to the TTO through the TGCU Start-Up Blower Bypass Valve, but most of the tailgas will flow instead through the TGCU Warmup/Bypass Valve to the TTO.
I.
Toggle the fast transfer switch for SRU 1 in the DCS to "CLOSE". The PLC will open the SRU 1 Tailgas Valve to the TTO then close the SRU 1 Tailgas Valve to the TGCU. All of the SRU 1 tailgas is now flowing directly to the TTO via the SRU 1 Tailgas Valve, and none of the tailgas is entering the TGCU. Visually confirm that these valves have moved to the proper positions. Verify that the DCS indicates that the SRU 1 Tailgas Valve to the TTO is open and that the SRU 1 Tailgas Valve to the TGCU is closed.
J.
Toggle the fast transfer switch for SRU 2 in the DCS to "CLOSE". The PLC will open the SRU 2 Tailgas Valve to the TTO then close the SRU 2 Tailgas Valve to the TGCU. All of the SRU 2 tailgas is now flowing directly to the TTO via the SRU 2 Tailgas Valve, and none of the tailgas is entering the TGCU. Visually confirm that these valves have moved to the proper positions. Verify that the DCS indicates that the SRU 2 Tailgas Valve to the TTO is open and that the SRU 2 Tailgas Valve to the TGCU is closed. NOTE: If a status does not change, or if a valve malfunction alarm is activated, it means that the limit switches on the associated valve never confirmed that the valve moved to the proper position. If this problem cannot be corrected, it will not be possible to continue with this procedure to shut down the TGCU in a controlled fashion. Instead, use the S/D button to activated the TGCU ESD system and shut down the TGCU immediately.
K.
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Toggle the Reducing Gas On/Off switch in the DCS to "OFF".
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SULFUR BLOCK The PLC will close the reducing gas block valves, open the vent valve, and force the control valve to "manual" and 0% output. Confirm that the DCS indicates that these valves have moved to the proper position. L.
Close the steam-jacketed block valve in the reducing gas supply line.
M.
Reduce the output from the hand control in the DCS to 0% to close the TGCU Warmup/Bypass Valve. Visually confirm that the valve is closed.
N.
Now that the reducing gas has been isolated and the tailgas from the SRU has been switched to the Thermal Oxidizer, allow the front-end of the TGCU to operate in this fashion for about 15 minutes to purge the process gas out to the Thermal Oxidizer.
O.
Place the HP steam pressure controller for the TGCU Reactor Feed Heater in "manual" and set its output to 0% to close control valve.
P.
Activate the TGCU ESD system using the S/D button.
Q.
Close the steam-jacketed valve in the nitrogen supply line where it joins the tailgas line to the TGCU Reactor Feed Mixer.
R.
Close the manual TGCU Outlet Valve.
WARNING
THE OVER-PRESSURE PROTECTION FOR THE TGCU IS THROUGH THE THERMAL OXIDIZER VENT STACK. HOWEVER, IF THE TGCU OUTLET VALVE IS CLOSED WHILE THE TGCU IS SHUT DOWN, STEPS MUST BE TAKEN TO ENSURE THAT THE TGCU IS NOT COMPLETELY BLOCKED-IN BY CREATING ANOTHER OPENING FROM THE TGCU TO THE ATMOSPHERE SO THAT THE TGCU CANNOT BE OVER-PRESSURED. S.
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Visually confirm that: (1)
The SRU 1 Tailgas Valve to the TGCU is closed.
(2)
The SRU 2 Tailgas Valve to the TGCU is closed.
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SULFUR BLOCK
T.
(3)
The TGCU Outlet Valve is closed.
(4)
The nitrogen/utility air to the TGCU Reactor Feed Heater is blocked-in and bled.
(5)
The reducing gas to the TGCU Reactor Feed Mixer is blocked-in and bled.
(6)
The pre-sulfiding gas shutdown valve is closed.
(7)
The suction and discharge valves for the TGCU Startup Blower are closed and the nitrogen purge is in service.
(8)
The TGCU Quench Column inlet valve and the TGCU Quench Column Bypass valve are closed.
(9)
All steam heating services on the sulfur vapor valve jackets are still functioning and the steam traps are operating properly.
All temperatures in the front-end of the TGCU should be monitored to confirm that no air leaks into the system (due to "drafting" from the Thermal Oxidizer, for instance) and causes a fire in the catalyst bed. If desired, a small flow of nitrogen can be introduced into the front-end of the TGCU by using the Leak Test switch in the DCS to allow opening the block valves on the nitrogen supply line, then opening the control valve to establish a small flow of nitrogen. "Crack" the TGCU Outlet Valve to allow the nitrogen to escape to the Thermal Oxidizer and prevent over-pressuring the TGCU.
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U.
Allow the TGCU amine to continue to circulate with steam flowing to the TGCU Stripper Reboiler, until the all of the H2S and CO2 have been stripped from the amine. Once the H2S/CO2 content of the "rich" amine is essentially the same as the "lean" amine, the steam can be shut off to the TGCU Stripper Reboiler.
V.
Continue to circulate the TGCU amine and operate the TGCU Lean Amine Cooler, the TGCU Lean Amine Trim Cooler, and the TGCU Stripper Reflux Condenser until the amine is cool.
W.
Once the amine is cool (60°C or less throughout the system), shut down the equipment in the following order: (1)
The TGCU Quench Water Pump.
(2)
The TGCU Rich Amine Pump.
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SULFUR BLOCK
X.
(3)
The TGCU Lean Amine Pump.
(4)
The TGCU Stripper Reflux Pump.
(5)
The fans on the TGCU Quench Water Cooler, TGCU Lean Amine Cooler, and TGCU Stripper Reflux Condenser.
If the TGCU will be down for an extended period, special precautions should be taken to prevent the TGCU Waste Heat Reclaimer tubes from cooling to the point where water can condense inside them. Most of the corrosion that occurs in TGCUs is due to the acidic water that can form if the plant is allowed to get cold. Close the steam outlet valve on the boiler and open the vent valves on the boiler to de-pressure it. Make sure that the boiler level control continues to operate properly so that the water level does not drop below the tubes until they have cooled and the boiler is fully de-pressured. Once the boiler is de-pressured, block-in its BFW supply and drain the water from it. Then use a temporary "jumper" to supply LP steam to the boiler shell. Drain the condensate from the boiler occasionally to keep the tubes safely above the water condensation temperature (100-110°C).
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SULFUR BLOCK 11.9.2
Planned Shutdown for Reactor Entry When the TGCU Reactor must be opened for maintenance or to replace the catalyst, it is normally necessary to passivate the catalyst as a part of the shutdown procedure. After the TGCU has been operating for a period of time, the catalyst becomes pyrophoric due to the presence of iron sulfide, FeS. Exposing catalyst containing pyrophoric FeS to air may result in uncontrolled burning of the FeS to form H2S and/or SO2, which obviously will prevent the entrance of personnel into the vessel. For this reason, controlled oxidation ("passivation") of the FeS in the catalyst is carried out at low temperature (~150°C) by admitting a small air flow into the circulating gas. This converts the FeS into non-pyrophoric iron oxide, Fe2O3, while leaving the catalyst in its sulfided state. The only SO2 produced during passivation should come from the FeS present. Pre-sulfiding of the catalyst will not be required during the next startup (assuming the catalyst is not replaced). This procedure requires an ample supply of a suitable inert gas (nitrogen, etc.) to circulate through the TGCU Reactor and cool it. Make sure a supply of inert gas is available and ready to use before beginning this procedure. Utility air is used for passivating the catalyst. In an emergency, or if the catalyst is to be replaced, it can be handled in a pyrophoric state if it is kept under water or nitrogen. Soaking the catalyst in water will, however, weaken the catalyst substrate and make the catalyst more susceptible to crumbling and attrition. For this reason, and due to the corrosive nature of liquid water on the TGCU Reactor vessel and piping, this practice is not recommended. There are service companies, however, that can unload the TGCU catalyst bed after it has been cooled to near ambient temperature using nitrogen. The service company then performs all necessary work relating to removing and replacing the catalyst under a nitrogen "blanket". This eliminates the need to passivate the catalyst, reducing the time required to replace the TGCU catalyst. Some refineries and gas plants also purchase pre-sulfided replacement catalyst, resulting in less time for the subsequent startup. The procedure in this section is used to make the TGCU catalyst safe for atmospheric air replacement.
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SULFUR BLOCK A.
Follow the procedure given previously in Section 11.9.1 to purge the front-end of the TGCU, to shut down the quench water system, and to strip, cool, and shut down the amine system, but do not Activate the TGCU ESD system using the S/D button, or isolate the nitrogen supply, or close the TGCU outlet Valve (Steps P-R) in Section 11.9.1). NOTE:
B.
Do not drain the water from the TGCU Waste Heat Reclaimer (Step X in Section 11.9.1). The boiler and its BFW controls must remain in service until the completion of the catalyst passivation procedure.
Confirm that the TGCU Outlet Valve is open and start a small nitrogen purge into the bottom of the TGCU Quench Column. (This is typically done by hooking up a temporary jumper to a connection on one of the level bridles.) This will purge through both the TGCU Quench Column and the TGCU Contactor and ensure that the SO2 formed during passivation does not contaminate the quench water or the amine.
C.
If the H2/H2S analyzer is not already switched to sample from the outlet of the TGCU Waste Heat Reclaimer, check that the sample line from the outlet of the TGCU Waste Heat Reclaimer to the analyzer is clear of liquids, confirm that the sample valve on the outlet channel of the boiler is open, then switch the sample selector valve in the analyzer enclosure to the "STARTUP" position.
D.
Visually confirm that the TGCU Start-Up Blower suction block valve and discharge block valve are closed, the bypass valve is open, the nitrogen purge to the blower seal is in service, and the local "stop" control at the blower is set to the run position.
E.
Start the TGCU Start-Up Blower using the start/stop toggle switch in the DCS. The PLC will perform the following actions:
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(1)
The nitrogen purge valve is closed.
(2)
The TGCU Start-Up Blower Suction Valve is opened.
(3)
The TGCU Start-Up Blower Discharge Valve is opened.
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SULFUR BLOCK (4)
After the limit switches prove these valves open, the TGCU Start-Up Blower is started.
(5)
Once the Startup Blower is started, the TGCU Start-Up Blower Bypass Valve is closed.
As this valve is closed, the blower will start to load. As it does so, the blower will begin to "pull" nitrogen through the TGCU Reactor Feed Heater and TGCU Reactor Feed Mixer and all of the associated piping. F.
Once the blower operation has stabilized, open the TGCU Warmup/Bypass Valve by increasing the output from its hand control to 100%. As the TGCU Warmup/Bypass Valve opens, the TGCU Start-Up Blower will begin re-circulating gas from the outlet of the TGCU Waste Heat Reclaimer back to the TGCU Reactor Feed Heater (via the TGCU Contactor overhead line).
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G.
Once re-circulation has been established, place nitrogen flow controller in "automatic" and adjust its setpoint to 5-10% of maximum flow.
H.
Allow the front-end of the TGCU to operate in this manner until the following conditions are both satisfied: (1)
The hydrogen controller shows 0.5% or less hydrogen concentration in the circulating gas.
(2)
The catalyst bed in the TGCU Reactor has been cooled below 150°C per the temperatures indicated in the DCS for the catalyst bed and for the reactor outlet.
I.
Verify that the utility air flow controller is in "manual" and set to 0% output.
J.
Verify that flow control valve, the upstream block valve, and the downstream block valve are all closed in the utility air supply line.
K.
Rotate the spectacle blind in the utility air line to the "open" position, then open the upstream block valve and the downstream block valve.
L.
Slowly increase the output from the flow controller to open the flow valve and admit a small amount of utility air into the circulating gas and begin passivating the catalyst. A maximum oxygen
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SULFUR BLOCK concentration in the range of 0.5-1.0% will probably be required during the initial stages of passivation.
CAUTION THE AMOUNT OF AIR ADDED MUST BE LIMITED INITIALLY TO AVOID EXCESSIVE TEMPERATURE RISE ACROSS THE TGCU REACTOR AS THE FeS IN THE CATALYST IS OXIDIZED. TEMPERATURES IN EXCESS OF 175°C MAY CAUSE THE SULFIDED CATALYST TO REACT WITH THE OXYGEN. IF THIS OCCURS, THE CATALYST WILL HAVE TO BE PRE-SULFIDED DURING THE NEXT STARTUP. ALSO, CATALYST DAMAGE MAY OCCUR IF LOCAL CATALYST TEMPERATURES BECOME EXCESSIVE. DO NOT ALLOW THE CATALYST BED TEMPERATURES TO EXCEED 150°C. REDUCE THE UTILITY AIR FLOW AS NECESSARY TO KEEP THE REACTOR BED TEMPERATURES AND THE OUTLET TEMPERATURE AT 150°C OR BELOW. M.
As the temperature rise across the reactor starts to decrease, the oxygen concentration in the circulating gas may be increased by using the flow controller to open the flow valve further and increase the air flow into the circulating stream.
N.
When there is no longer any temperature rise across the reactor, the passivation of the catalyst is complete. Discontinue the flow of nitrogen to the front-end of the TGCU by placing the nitrogen flow controller in "manual" and setting its output to 0% to close the control valve. Observe the TGCU Reactor temperatures to ensure that no further reaction occurs (leave the nitrogen flowing to the TGCU Quench Column). If the catalyst bed temperatures start to rise when the nitrogen flow is discontinued, re-establish nitrogen flow until the bed cools again, then stop the nitrogen flow. Repeat this step as necessary until there is no temperature rise in the reactor with the nitrogen flow shut off.
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SULFUR BLOCK O.
Once the nitrogen flow has been discontinued, the TGCU Start-Up Blower is no longer needed for re-circulation. Shut down the blower as follows: (1)
Reduce the output from the hand control to 0% to close the TGCU Warmup/Bypass Valve and stop the recycle flow to the TGCU Reactor Feed Heater. Verify that the valve has closed, and that the DCS indicates that this valve has closed.
(2)
Shut down the blower using the start/stop selector switch in the DCS. The PLC will open the TGCU Blower Bypass Valve, stop the blower, turn on the nitrogen purge, and close its suction and discharge valves. Verify that the DCS indicates each valve has moved to the proper position.
P.
Use the flow controller to raise the utility air flow to 80% or more and allow air to cool the TGCU Reactor. Continue the air flow until the temperature leaving the TGCU Reactor is about the same temperature as the air entering the TGCU Reactor.
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Q.
At the completion of the cooling operation, activate the TGCU ESD using the S/D button to shut down and isolate the utility air.
R.
Close the upstream block valve and the downstream block valve in the utility air supply line, then rotate the spectacle blind to the "closed" position. Close the steam-jacketed block valve at the junction with the tailgas line to the TGCU Reactor Feed Heater.
S.
Discontinue the flow of nitrogen to the TGCU Quench Column, then close the TGCU Outlet Valve.
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SULFUR BLOCK
WARNING
THE OVER-PRESSURE PROTECTION FOR THE TGCU IS THROUGH THE THERMAL OXIDIZER VENT STACK. HOWEVER, IF THE TGCU OUTLET VALVE IS CLOSED WHILE THE TGCU IS SHUT DOWN, STEPS MUST BE TAKEN TO ENSURE THAT THE TGCU IS NOT COMPLETELY BLOCKED-IN BY CREATING ANOTHER OPENING FROM THE TGCU TO THE ATMOSPHERE SO THAT THE TGCU CANNOT BE OVER-PRESSURED. T.
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Visually confirm that: (1)
The SRU 1 Tailgas Valve to the TGCU is closed.
(2)
The SRU 2 Tailgas Valve to the TGCU is closed.
(3)
The TGCU Outlet Valve is closed.
(4)
The nitrogen to the TGCU Reactor and the TGCU Quench Column is positively isolated from the TGCU.
(5)
The pre-sulfiding gas shutdown valve is closed.
(6)
The TGCU Start-Up Blower is shut down, with its suction and discharge valves closed and the nitrogen purge in service.
(7)
The TGCU Quench Column inlet valve and the TGCU Quench Column bypass valve are closed.
(8)
All steam heating services on the sulfur vapor valve jackets are still functioning and the steam traps are operating properly.
U.
The TGCU catalyst is now passivated and cooled, and can be safely handled. The TGCU is now ready to be isolated and made safe for entry.
V.
If the TGCU will be down for an extended period, special precautions should be taken to prevent the TGCU Waste Heat Reclaimer tubes from cooling to the point where water can condense inside them. Most of the corrosion that occurs in TGCUs is due to the acidic water that can form if the plant is allowed to get cold.
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SULFUR BLOCK Close the steam outlet valve on the boiler and open the vent valves on the boiler to de-pressure it. Make sure that the boiler level control continues to operate properly so that the water level does not drop below the tubes until they have cooled and the boiler is fully de-pressured. Once the boiler is de-pressured, block-in its BFW supply and drain the water from it. Then use a temporary "jumper" to supply LP steam to the boiler shell. Drain the condensate from the boiler occasionally to keep the tubes safely above the water condensation temperature (100-110°C).
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SULFUR BLOCK 11.9.3
Shutting Down When Boiler Tubes Are Leaking One special circumstance that merits discussion is shutting down the TGCU when there are tube leaks in the TGCU Waste Heat Reclaimer. While the plant is running, minor tube leaks usually cause little damage because the hot process gas vaporizes the boiler feed water before it has a chance to form acid and cause rapid corrosion. When the TGCU is shut down, however, several problems can develop: 1.
Liquid water may accumulate in the equipment or piping and form a variety of acids (sulfurous, polythionic, etc.) that will rapidly corrode the steel.
2.
Water and/or steam may reach the TGCU Reactor catalyst and weaken or damage it.
If a boiler tube leak is suspected, a shutdown procedure similar to the following may be appropriate:
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A.
Switch the SRU tailgas from the TGCU to the Thermal Oxidizer.
B.
Activate the TGCU ESD system using the S/D button.
C.
Close the TGCU Outlet Valve.
D.
De-pressure the TGCU Waste Heat Reclaimer, taking care to reduce the pressure slowly enough to avoid over-stressing the boiler.
E.
Maintain a visible water level in the boiler. Water must remain in the boiler until it is de-pressured to prevent overheating damage to the tubes.
F.
Once the boiler is fully de-pressured, drain the water from the boiler to prevent any further leakage into the process side of the equipment.
G.
The TGCU is now ready to be isolated and made safe for entry.
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SULFUR BLOCK 11.9.4
Special Precaution During Shutdowns
CAUTION
THE FOLLOWING PROCEDURE IS VERY IMPORTANT TO PROTECT THE TGCU DURING SHUTDOWNS. FAILURE TO OBSERVE THESE PRECAUTIONS CAN LEAD TO "STUCK" VALVES IN THE PROCESS GAS LINES, RESULTING IN AN EXTENSIVE (AND EXPENSIVE) SHUTDOWN TO REPAIR THE VALVE(S). When a TGCU is shut down for any appreciable length of time, water vapor in the process gas can condense and accumulate in the low spots. Since the process gas contains CO2, H2S, SO2, and other compounds, the condensed water can be quite acidic. As this acid water trickles over the piping, it corrodes the metal. If this water then reaches a steam-jacketed valve or pipe, the water will boil away and deposit the corrosion products on the heated surface. This occurrence can quickly cause a steam-jacketed valve to become "stuck", which usually results in an extended shutdown to repair the valve before that TGCU can be restarted. This problem can be prevented, by keeping water from accumulating near these valves during shutdowns. The valves to be protected are: TGCU Warmup/Bypass Valve TGCU Outlet Valve The most positive means for preventing condensation of water in the unit is to purge it with inert gas (nitrogen, etc.). One way to accomplish this is as follows:
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A.
Confirm that the Quench Column hand control in the DCS is set to 0% output.
B.
Confirm that the SRU Tailgas Valve to the TGCU is closed.
C.
Confirm that the Leak Test switch in the DCS is toggled to "OFF".
D.
Switch the Startup/Run selector switch in the DCS to "STARTUP".
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SULFUR BLOCK The PLC will open the TGCU Quench Column Bypass Valve. Verify that the DCS indicates that the Quench Column Bypass Valve is open. E.
Toggle the Leak Test switch to "ON".
F.
Close the TGCU Warmup/Bypass Valve by reducing the output of the hand control to 0%. Verify that the DCS indicates that the valve has closed.
G.
Verify that the TGCU Start-Up Blower Bypass Valve is open and that the DCS indicates that the valve is fully open.
H.
Open the steam-jacketed block valve in the nitrogen supply line.
I.
Toggle the Nitrogen On/Off switch in the DCS to "ON".
J.
Place the nitrogen flow controller in "manual" and adjust its output to open the control valve slightly and establish a small flow of nitrogen into the front-end of the TGCU.
K.
"Crack" the TGCU Outlet Valve open slightly to allow the nitrogen to flow to the Thermal Oxidizer. Adjust the TGCU Outlet Valve to "pinch" so that the pressure in the TGCU is slightly positive (about 0.07-0.15 kg/cm2(g)) on the pressure indicator in the DCS.
L.
With the valves arranged in this manner, the purge gas will proceed as follows: (1)
Through the TGCU Rector Feed Heater, TGCU Reactor Feed Mixer, TGCU Reactor, and TGCU Waste Heat Reclaimer.
(2)
Through the TGCU Quench Column Bypass Valve.
(3)
Through the TGCU Start-Up Blower Bypass Valve.
(4)
Through the TGCU Contactor overhead line, flowing past the TGCU Warmup/Bypass Valve.
(5)
Through the TGCU Outlet Valve and out to the Thermal Oxidizer.
This will keep purge gas sweeping through or past all of the steam-jacketed process gas valves so that condensed water will not accumulate and cause problems.
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SULFUR BLOCK If it is not possible to purge the TGCU with inert gas while it is shut down, it is possible to protect these valves by using drain valves to prevent the accumulation of water near the steam-jacketed valves. In order to accomplish this, drain valves in the following locations are used: (1)
In the bottom of the TGCU Contactor overhead line, between the TGCU Warmup/Bypass Valve and the TGCU Warmup/Bypass Valve.
(2)
In the bottom of the outlet line from the TGCU Waste Heat Reclaimer.
With these drain valves open, there should not be significant accumulation of condensed water near any of the steam-jacketed process gas block valves.
WARNING BE CERTAIN THAT THE SRU TAILGAS VALVES TO THE TGCU, AND THE TGCU OUTLET VALVE ARE CLOSED IF THE SRU IS OPERATING WHEN THE TGCU IS SHUT DOWN. LEAVING EITHER OF THESE VALVES OPEN WHILE THE SRU IS OPERATING WILL ALLOW SRU TAILGAS TO ENTER THE TGCU, RESULTING IN SOLVENT CONTAMINATION, CORROSION DAMAGE, AND POSSIBLE PERSONNEL EXPOSURE TO H2S AND SO2. MAKE CERTAIN ALL THESE DRAIN VALVES ARE CLOSED BEFORE ATTEMPTING TO RESTART THE TGCU. To use these drain valves, proceed as follows:
Issued 30 August 2011
A.
Confirm that the SRU Tailgas Valves to the TGCU are closed.
B.
Close the TGCU Outlet Valve. Make sure that this valve is closed tightly.
C.
Open the two special drain valves. Observe appropriate precautions to prevent personnel exposure to H2S and/or SO2 that may still be contained in the unit, or that may leak into the
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SULFUR BLOCK unit later. It is recommended that warning signs be posted to identify the hazard that exists near these drain valves.
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D.
Check the drain valves periodically to be sure that process gas is not escaping to the surroundings.
E.
Close the drain valves before attempting to restart the TGCU.
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SULFUR BLOCK 11.9.5
Emergency Shutdown The TGCU ESD system can be initiated by any of the actuating devices outlined in Section 11.5 of these guidelines. The operator must determine and correct the condition causing the shutdown before the TGCU can be restarted. The problems outlined below should be investigated first by the operator in his troubleshooting procedure.
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S/D Actuation Device TGCU Reactor High-High Outlet Temperature
Possible Causes 1. The sulfur plant(s) is(are) off-ratio causing the SRU tailgas stream to contain large amounts of SO2, resulting in excessive heat release in the catalyst bed. 2. Malfunction of the reactor feed heater temperature control system or control valve. 3. The utility air normally used during shutdown operations to passivate the catalyst has been left open.
TGCU Waste Heat Reclaimer Low-Low Level
1. Loss of make-up water supply pressure. 2. Make-up water line plugged, or manual block valve closed or pinched. 3. Malfunction of the level control system. 4. Manual blowdown valve left open.
Complete Flowpath Interlock
1. The TGCU outlet block valve is not fully open. 2. An automated process gas valve in the TGCU has failed to open fully as directed by the PLC. 3. Malfunction of the limit switch is causing a false indication that the valve is not open.
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SULFUR BLOCK 11.9.6
Effects of Shutdowns and Outages in Other Systems The Tailgas Cleanup system is directly or indirectly affected by shutdowns and/or outages in five other systems in the complex. These effects are described below.
11.9.6.1
Amine Regeneration Unit Outages Amine acid gas flow from the Amine Regeneration Unit(s) can be interrupted for a variety of reasons. For instance, the gas flow to the absorber in the complex can be blocked manually or automatically, the amine flow from the flash tank to the stripper can be interrupted, etc. When these events occur, the acid gas flow will not cease immediately due to the residence time in the amine distribution piping, the flash tank, and the stripper. If processing in the affected Amine Regeneration Unit is restarted within the time frame of this system residence time, the amine acid gas flow to the SRUs upstream of the TGCU will probably dip, but should not stop completely. If the interruption in the Amine Regeneration Unit is long enough, though, the amine acid gas flow can fall far enough to cause the acid gas flame(s) in the SRU(s) to become unstable, at which point the SRU ESD system will be activated by "flame failure". Section 11.9.6.3 below describes the effect of this on the TGCU.
11.9.6.2
Sour Water Stripper Outages SWS gas flow from the Sour Water Stripper can also be interrupted for a variety of reasons. However, since the loss of SWS gas flow to the SRUs generally has minimal impact, outages in this system are usually of little consequence to the SRUs or the TGCU.
11.9.6.3
Sulfur Recovery Unit ESD System The SRU ESD systems stop the flow of acid gas to the affected SRU. As a result, the tailgas flow from that SRU ceases almost immediately. If only a single SRU shuts down, the TGCU will stay online processing SRU tailgas from the remaining SRU. However, if both SRUs shutdown, then there would be no SRU tailgas flowing through the front-end of the TGCU, and consequently nothing to process. So, the TGCU is shut down whenever the both of the sulfur plants shut down.
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SULFUR BLOCK However, if the TGCU is not yet processing tailgas from either SRU, there is no reason to shut it down if the SRUs are not running. This simplifies startup of the TGCU by allowing its ESD system to be independent of the SRU ESD systems until tailgas is introduced into the TGCU. 11.9.6.4
Thermal Oxidizer ESD System A TTO ESD has no direct effect on the TGCU, as the flow of TGCU effluent to the Thermal Oxidizer will not be interrupted. However, when the TTO ESD shuts down the Thermal Oxidizer Burner, the sulfur compounds in the Thermal Oxidizer feed gas will no longer be oxidized to sulfur dioxide. This means that hydrogen sulfide will be vented to the atmosphere from the top of the Thermal Oxidizer Vent Stack. Under normal circumstances, this is not a cause for concern because the TGCU is processing the SRU tailgas. Since the H2S content of the TGCU effluent should be low and the stack is tall, dangerous ground level concentrations of H2S should not develop. However, note the warning that appears in Section 12.6.2 of these guidelines regarding high temperature in the Thermal Oxidizer if the SRU tailgas and/or TGCU effluent gas contains excessive amounts of H2S. Also, note that the operating permit for this plant may not allow venting un-incinerated gases for extended periods. Review the permit before operating in this mode for a lengthy period. If the H2S concentration in the TTO feed gas is high (above 3.0%), do not attempt to restart the Thermal Oxidizer. Instead, direct your attention to the amine or SWS unit upstream of the SRUs that is probably causing the problem and bring the SRUs back on-ratio. This will allow the TGCU to reduce the H2S concentration in the Thermal Oxidizer feed gas to an acceptable level, so that restart of the Thermal Oxidizer can proceed smoothly. Failure to correct the upstream problem(s) first will likely lead to the TTO shutting down again on high-high temperature, requiring another restart of the TTO.
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SULFUR BLOCK 11.9.6.5
Steam System Outage There are three impacts on the TGCU if the complex steam system is shut down. One of these will only create problems if the steam supply to the TGCU is unavailable for a long period of time - the heating for the steam-jacketed process gas valves will be lost, possibly leading to solid sulfur freezing in these valves. The most immediate impact on the TGCU will be the loss of LP steam to the TGCU Stripper Reboiler if the steam outage lasts long enough. As the heat input to the reboiler declines, stripping of the acid gas from the amine will decline and the H2S in the TGCU effluent gas leaving the TGCU Contactor will begin to increase. This will quickly lead to high SO2 emissions from the Thermal Oxidizer Vent Stacks as indicated in the DCS. A third impact on the TGCU will be the loss of LP steam to the stripper reboilers in the Amine Regeneration Unit if the steam outage lasts long enough. As the heat input to the reboilers declines, stripping of the acid gas from the amine will decline and the amine acid gas flow rate to the SRUs will gradually diminish. If the amine acid gas flow falls far enough to cause an acid gas flame to become unstable, the SRU ESD system will be activated by "flame failure" as described previously in the discussion about the Amine Regeneration Unit outages, with the resulting impact on the TGCU as previously described in Section 11.9.6.3.
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SULFUR BLOCK
11.10 Analytical Procedures This Section contains analytical procedures for determining: 1.
The concentrations of total amine in the TGCU solvent (Section 11.10.2).
2.
The concentrations of H2S and CO2 in the TGCU solvent (Sections 11.10.3 and 11.10.4).
3.
The foaming tendency of TGCU solvent (Section 11.10.5).
4.
The H2S content of the TGCU Contactor overhead gas (Sections 11.10.6 and 11.10.7).
5.
The performance level of the TGCU Reactor catalyst (Section 11.10.8).
11.10.1 General Procedures for Analyzing TGCU Solvent1,2 An amine solution which is to be analyzed should first be inspected visually. If conducted by an experienced person, such an inspection will often yield important clues to the identity of a number of contaminants. For example, a green color in an amine solution usually indicates finely divided iron sulfide in sub-colloidal particle size (<1 micron), whereas a finely divided black suspension indicates the presence of larger (>3 micron) iron sulfide particles. A green or blue solution can indicate the possibility of either copper or nickel, while an amber colored solution may contain suspended or dissolved iron oxide. Iron may complex with the amine an give the solution an amber or dark red color. Thermal degradation of the amine may give the solution a dark red to brown color. Amines sometimes display a red or dark brown color resulting from oxidation, particularly when combined with thermal degradation. An oil slick on the solution or an oil-like odor is indicative of hydrocarbon contamination. The presence of these contaminants, however, must be proven by analysis. The next step in analyzing an amine solution is the determination of the percent amine and the acid gas content (H2S and CO2). Both rich and lean solutions may be analyzed for these constituents, and from the analyses the extent of acid gas loading and efficiency of stripping can be ascertained. Procedures for these analyses are given in Sections 11.10.2 through 11.10.4 that follow. 1 2
The Dow Chemical Company, Gas Conditioning Fact Book, 1962, pp. 310-311. Dow Chemical U.S.A., Gas Treating from Dow, 1987, pp. 8-1-1 – 8-1-2.
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SULFUR BLOCK In addition to the procedure in Section 11.10.2, the amine concentration of the solvent can be determined by performing Kjeldahl and Van Slyke nitrogen analyses. The Kjeldahl determination indicates the total nitrogen content of the solution, including nitrogen from the amine and from amine degradation products. The Van Slyke method, on the other hand, shows amine content, but does not reveal the extent to which the original amine has been degraded or tied up as heat stable salts. The difference between the results obtained through Kjeldahl and Van Slyke analyses usually indicates the degree of amine degradation. As would be expected, little difference is obtained with initial or unused solution. These analyses are not commonly performed in plant laboratories, but are generally left to the chemical solvent supplier. Heat stable salts can also be determined by a total anion assay. The amine solution is passed through an ion exchange column containing ion exchange resin in the hydrogen form. Acid salts are thus broken down and the acids recovered in the column effluent, while the amine is absorbed in the column. The acid in the effluent is determined by potentiometric titration, and from these results plus the original amine concentration the amount of amine in the form of heat stable salts is calculated. Again, this type of analysis is commonly left for the chemical solvent supplier to perform. The foaming characteristics of an amine solution are determined empirically in a simple apparatus consisting of an air (or gas) supply, pressure regulator or gas manometer, graduated glass cylinder, and a gas dispersion tube. The amine solution is poured into the graduated cylinder and air passed through at a constant rate. After five minutes, the height of the foam is recorded, the air flow is interrupted, and the time for the foam to break is determined. The results thus obtained will indicate whether or not evaluation of anti-foam agents is desirable. Section 11.10.5 describes this procedure more completely. A water analysis can be conducted on the amine solution to obtain a material balance and serve as an approximate check on the amine concentration. This is typically determined using the Karl Fischer method of analysis, but most plant laboratories leave this procedure to the chemical solvent supplier. Ordinarily, the above analyses will provide an accurate picture of the condition of the amine plant solution. At times, however, unusual operational difficulties may be encountered in amine sweetening units
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SULFUR BLOCK because of contaminants which are not revealed by the usual analytical methods. When this occurs, infrared spectroscopic analysis may often be utilized to good advantage. Infrared spectroscopy is based on the principle that each molecule or functional group exhibits its own particular absorption characteristics when exposed to infrared light of a definite wavelength. A wide variety of functional groups can be readily detected and identified by infrared techniques. For example, it has been found that degraded or oxidized amine solutions may contain ammonia, formic acid, a di-functional acid, a carbonyl compound yielding a glyoxal dinitrophenylhydrazone derivative, and a high molecular weight material that exhibits the characteristics of a Jones polymer. Also, both mono- and di-substituted amines have been identified. Each component exhibits its own particular effects on corrosion, foaming, and acid gas absorption, effects which can be determined only by the separate evaluation of each contaminant. Once these effects are determined, a knowledge of functional groups present and their relative concentration makes it possible to anticipate which types of contaminants may be causing difficulties. The chemical solvent supplier can usually perform this type of analysis more easily than the plant laboratory. Steps should be taken to ensure that the amine solution samples taken are representative of the circulating solvent. Samples should be taken in glass or plastic containers. Metal containers will cause low results for H2S because sulfides will react with the metal walls of the container. Do not use copper tubing to withdraw the samples; the copper will contaminate the amine solution, and H2S will react with the copper and give low results. Special care should be exercised when taking samples of the rich amine solution to avoid personnel exposure to H2S. Hot, fully loaded amine solution can flash acid gas when released to atmospheric pressure, causing low acid gas loading results in addition to the dispersion of H2S to the surroundings. Take samples of the rich solution from the coolest point in the process (the TGCU Contactor outlet, usually), and cool the samples in a stainless steel coil immersed in an ice bath or cold water to prevent flashing. The solution should be allowed to flow to a drain in this fashion for several minutes before taking the sample to be sure that circulating amine is being taken.
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SULFUR BLOCK In the laboratory procedures that follow, several different reagents are used that can be harmful if proper care is not exercised. Acids, bases, and flammable substances are utilized in these procedures, so adherence to proper laboratory safety practices is necessary to ensure the safety of all personnel.
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SULFUR BLOCK 11.10.2 Determination of Amine Concentration in TGCU Solvent The amine concentration in the TGCU solvent can be determined by acid titration of the lean solution. This technique is not specific for free amine, however, as amine present in the solution as an amine-acid salt will also react during the titration. This technique will also give erroneous results if there are other basic materials in the solution, such as caustic or soda ash (sometimes used to "neutralize" heat stable salts). 1.
Reagents:
2.
Procedure:
3.
Distilled or Deionized Water 0.5 N Hydrochloric Acid (HCl) Bromophenol Blue Indicator (3',3'',5',5''-tetrabromophenolsulfonephthalein)
a.
Place about 95 ml of distilled or deionized water in a 250 ml beaker or Erlenmeyer flask.
b.
Add about 5 ml of lean amine solution to the water in the beaker via pipette, recording the actual quantity.
c.
Add 5 drops of Bromophenol Blue indicator to the solution in the beaker and stir well.
d.
Titrate the solution in the beaker with 0.5 N HCl to a faint yellow color. Alternatively, if a pH meter is available, titrate to a pH of 4.5. Record the amount of HCl used in the titration.
Chemical reaction involved: R2HN + HCl
+
R2HNH + Cl
–
where R2HN = CH3-N-(CH2-CH2-OH)2 = MDEA (methyldiethanolamine) As the hydrochloric acid is added to the solution, it reacts with the amine to form a chloride salt. Once all the amine has reacted, the continued addition of acid causes the pH of the solution to drop, until the Bromophenol Blue indicator changes from blue to yellow. Note that HCl reacts with the amine on a 1:1 molar basis.
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SULFUR BLOCK 4.
Calculation of Weight Percent Amine:
ml HCl Normality of Amine 100% Used HCl Solution Weight % Mole Amine Weight 1000 ml / l ml of Sp. Gravity of Sample Amine Sample The molecular weight of MDEA is 119.17, and the specific gravity of the solution at room temperature (20°C) is about 1.059, assuming the solution is about 45 wt% MDEA. The equation can then be simplified to:
ml HCl Normality of Used HCl Solution Weight % Amine 11.253 ml of Sample
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SULFUR BLOCK 11.10.3 Determination of Total Acid Gas Loading in TGCU Solvent The total acid gas (H2S + CO2) loading, relative to the amine concentration, in either the lean or rich TGCU solvent can be determined by base titration of the solution. This procedure does not distinguish between H2S and CO2. However, together with the procedure in Section 11.10.4, the individual concentrations of H2S and CO2 can be determined. 1.
Reagents:
2.
Procedure:
3.
Methanol (CH3OH), Anhydrous 0.5 N Potassium Hydroxide (KOH) Solution in Methanol Thymolphthalein Indicator in Methanol
a.
Place about 125 ml of methanol in a 250 ml beaker or Erlenmeyer flask.
b.
If a pH meter is available, insert the pH meter probe into the methanol in the beaker and adjust the pH of the methanol to 11.2 by titrating the methanol in the beaker with the 0.5 N KOH.
c.
If a pH meter is not available, add 5 drops of Thymolphthalein indicator to the methanol in the beaker. Titrate the solution in the beaker with 0.5 N KOH until the solution turns a faint blue color, indicating a pH of 11.2. The change to faint blue will be sudden, so add the KOH slowly (one drop at a time).
d.
Add about 20 ml of lean amine solution to the methanol in the beaker via pipette, recording the actual quantity. If rich amine solution is being tested, use about 10 ml of solution instead.
e.
Titrate the solution in the beaker with 0.5 N KOH back to a pH of 11.2 (or until the solution again turns a faint blue color when using Thymolphthalein indicator). Record the amount of KOH used in this titration.
Chemical reactions involved: +
–
H2S + KOH
K + HS + H2O
CO2 + KOH
K + HCO3
+
–
As the potassium hydroxide is added to the solution, it reacts with the H2S and CO2 to form potassium hydrosulfide and potassium
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SULFUR BLOCK hydrogen carbonate salts. Once all of the acid gas has reacted, the continued addition of base causes the pH of the solution to rise, until the Thymolphthalein indicator changes from colorless to blue. Note that KOH reacts with H2S and CO2 on a 1:1 molar basis. 4.
Calculation of Acid Gas Loading (molar basis): ml KOH Normality of Used KOH Solution Moles Acid Gas Amine 100% Mole Mole Amine Weight 1000 ml / l ml of S.G. of Wt % Amine Sample Sample in Solvent
Note that "ml KOH used" refers to the amount used in the second titration, step 2.e. The "wt % amine in solvent" can be determined using the procedure in Section 11.10.2. The molecular weight of MDEA is 119.17, and the specific gravity of the solution at room temperature (20°C) is about 1.059, assuming the solution is about 45 wt% MDEA. The equation can then be simplified to:
ml KOH Normality of Used KOH Solution Moles Acid Gas 11.253 ml of Wt % Amine Mole Amine Sample in Solvent 5.
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Special Considerations: a.
Excess moisture in the equipment will give false readings. Water may be used to clean the equipment if the equipment is thoroughly dried prior to use with the anhydrous methanol.
b.
The faint blue titration endpoint using Thymolphthalein indicator is not definite. It may best be determined by comparing the color of the solution against a reference prepared by titrating a second sample of methanol-Thymolphthalein to the same color.
c.
The KOH solution and Thymolphthalein indicator solution should be kept tightly closed to prevent loss of methanol by vaporization. Any vaporization of methanol from the KOH solution will change the normality of the solution.
d.
The Thymolphthalein indicator solution can be prepared by dissolving 5 grams of thymolphthalein in 100 ml of anhydrous methanol.
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SULFUR BLOCK 11.10.4 Determination of H2S and CO2 Loading in TGCU Solvent The H2S loading, relative to the amine concentration, in either the lean or rich TGCU solvent can be determined by titration of the solution with iodine. Since CO2 does not react with iodine, this procedure is specific for H2S. Together with the total acid gas loading determined using the procedure in Section 11.10.3, the individual concentrations of H2S and CO2 can be determined. 1.
Reagents:
Distilled or Deionized Water Concentrated Hydrochloric Acid (HCl) or Sulfuric Acid (H2SO4) Standard Starch Solution - 1% 0.1 N Iodine Solution (I2) 0.1 N Sodium Thiosulfate Solution (Na2S2O3)
2.
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Procedure: a.
Measure about 25 ml of chilled iodine solution and place it in a 250 ml beaker or Erlenmeyer flask. Record the amount of iodine solution used.
b.
Carefully add about 25 ml of concentrated acid to the beaker.
c.
Add about 5 ml of standard starch solution to the beaker, then re-chill the beaker in an ice batch for 2-3 minutes.
d.
Slowly add 10-20 ml of lean amine solution to the solution in the beaker via pipette, recording the actual quantity. If rich amine solution is being tested, use 1-2 ml of solution instead.
e.
Use about 25 ml of distilled or deionized water to rinse the inside of the beaker, then swirl the contents gently to mix the solution without splashing it.
f.
Titrate the excess iodine in the sample with the sodium thiosulfate solution until the blue color disappears. The end point is a pale yellow or clear color. The approach of the endpoint is usually indicated by a milky brown tint at the top of the liquid surface. As the endpoint nears, slow the rate of titration and use a small amount of distilled or deionized water to wash the flask. Record the amount of sodium thiosulfate solution used in this titration.
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SULFUR BLOCK g.
3.
Check the pH of the titrated solution with pH paper to be sure the solution is acidic. If the solution is not acidic, repeat the procedure but use more acid in step 2.b.
Chemical reactions involved: H2S + I2
S + 2 HI
I2 + Na2S2O3
2 S + NaI + NaIO3
When the solvent is added to the iodine solution, the H2S in the solvent reacts with the iodine to form hydrogen iodide and elemental sulfur. The solution contains an excess of iodine to ensure that all of the H2S reacts. The iodine solution is chilled prior to adding the solvent to eliminate or minimize the evolution of H2S gas. Note that H2S reacts with iodine on a 1:1 molar basis. When the sodium thiosulfate solution is added to the solution, it reacts with the remaining iodine to form sodium iodide and sodium iodate, along with more elemental sulfur. (It is this elemental sulfur that may cause the titrated solution to appear pale yellow.) Once the last bit of iodine is consumed, the starch solution loses its characteristic blue color. The amount of H2S in the solvent sample is then calculated from the difference between the total iodine and the iodine that reacts with the sodium thiosulfate. Note that sodium thiosulfate reacts with iodine on a 1:1 molar basis. The purpose of the concentrated acid is to neutralize the amine so that it will release the H2S (a weaker acid) so it can react with the iodine. If the titrated solution is not acidic in step 2.g, then the amine was not fully neutralized and the H2S determination will not be correct. 4.
Calculation of H2S Loading (Molar Basis): g - moles ml I2 Normality of 1 liter 1 g - mole I2 Used used I2 Solution 1000 ml 2 g - equivalent
g - moles ml Normality of 1 liter 1 g - mole Na2S2O3 Na2S2O3 Na2S2O3 used Solution 1000 ml 2 g - equivalent Used
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SULFUR BLOCK g - moles g - moles Amine I2 Used Na2S2O3 Used Moles H2S Mole 100 % Mole Amine Weight ml of S.G. of Wt % Amine Sample Sample in Solvent
The "wt % amine in solvent" can be determined using the procedure in Section 11.10.2. The molecular weight of MDEA is 119.17, and the specific gravity of the solution at room temperature (20°C) is about 1.059, assuming the solution is about 45 wt% MDEA. Using these values and substituting the first and second equations into the third, these equations can be simplified to: Normality Normality of ml I2 of I ml Na2S2O3 Na S O 2 2 3 2 Used Used Solution Solution Moles H2S 5.626 Mole Amine ml of Wt % Amine Sample in Solvent
5.
Calculation of CO2 Loading (Molar Basis): Using the total acid gas loading determined with the procedure in Section 11.10.3, the CO2 loading of the solvent is determined by difference:
Moles CO2 Moles Acid Gas Moles H2S Mole Amine Mole Amine Mole Amine 6.
Other Common Units: The loadings calculated above can be easily converted to other units commonly used within the industry:
Grains H2S Moles H2S Wt % Amine S.G. of 166.7 Gallon Solvent Mole Amine in Sample Sample Moles H2S Wt % Amine Wt % H2S 0.2858 in Sample Mole Amine
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SULFUR BLOCK SCF CO2 Moles CO2 Wt % Amine S.G. of 0.2653 Gallon Solvent Mole Amine in Sample Sample
Moles CO2 Wt % Amine Wt % CO2 0.3693 in Sample Mole Amine Note that these conversions are specifically for MDEA. amines require different conversion factors.
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SULFUR BLOCK 11.10.5 Determination of Foaming Tendency of TGCU Solvent The procedure described in this section is an empirical method for measuring the foaming tendency of aqueous amine solvents, universally accepted within the industry. 1.
Principle: Air is bubbled through a solvent sample at a fixed rate for five minutes, at which time the foam height is measured. The air flow is stopped and the time for the foam to disappear is measured. The foam height and "break" time are indicative of how high the foaming tendency of the solvent is.
2.
Equipment:
3.
Procedure:
4.
1000 ml Graduated Cylinder Aquarium Air Pump (or laboratory air supply) with Bubble Stone Stop Watch (or regular watch with a second hand)
a.
Pour about 200 ml of the sample solution into the graduated cylinder and insert the bubble stone into the bottom of the cylinder.
b.
Record the level of sample in the cylinder (in ml).
c.
Start the air pump or air supply to agitate the sample with oil-free air at 4 liters per minute (0.2 Nm3/H).
d.
After five minutes, record the height of the foam in the cylinder (in ml). Then turn off the air supply and measure the time in seconds for the foam to "break". For consistency, foam "break" is defined as the first clear "fish eye" in the surface of the liquid in the cylinder.
Calculation: Foam Height = Height of Foam - Initial Height of Sample (in ml)
5.
Interpretation: Considerable experience with this test has shown that if the foam height exceeds 200 ml or the "break" time exceeds 5 seconds, the plant may be experiencing a foaming problem. The higher the foam
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SULFUR BLOCK height and/or the longer it takes to "break", the more severe the problem. 6.
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Other Considerations: a.
A nitrogen cylinder with the pressure regulated to about 0.35 kg/cm2(g), equipped with a flow rotameter, may be used instead of air. Be sure to keep the tubing and fittings oil-free.
b.
This procedure can be used to evaluate the effects of anti-foam agents on the solvent. However, care must be exercised in cleaning the equipment between tests since a very small quantity of residual anti-foam agent will affect the test.
c.
Foaming is sometimes caused by contaminants in the solvent that can be removed by activated carbon treatment. The effect of activated carbon filtration can be evaluated by running foam tests on treated and untreated samples. The sample is treated by mixing it with a quantity of carbon (12-20 mesh) to remove the contaminant, then filtering the mixture through Whatman No. 41 filter paper.
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SULFUR BLOCK 11.10.6 H2S Conc. in TGCU Contactor Ovhd by the Tutweiler Method The overhead gas from the TGCU Contactor can be sampled from the sample connection near the sample line for the H2/H2S analyzer. 1.
Using a 500 ml Tutweiler apparatus, sample and titrate the treated gas leaving the TGCU Contactor as outlined in Section 7.10.1 of these guidelines.
2.
Chemical reaction involved: H2S + I2
2 HI + S
The hydrogen sulfide (H2S) is converted to small particles of elemental sulfur by the iodine during the shaking. Good shaking is required to get good contact between the hydrogen sulfide in the gas and the iodine in the liquid. When all of the hydrogen sulfide is converted, the excess iodine causes the characteristic blue color in the presence of starch. This is a universal test for starch. (Iodine causes a blue color when it contacts starchy foods, such as potato for example.) 3.
Calculation of Mole (or Volume) percent H2S (dry basis): ml Iodine Normality of 273 T 760 Mole % H2S Iodine Solution (11.85) Solution Used 289 P - V.P.
Where
T P
= =
sample temperature, °C atmospheric pressure at particular location, mm Hg
V.P
=
vapor pressure of water at sample temperature, mm Hg
The Normality of the standard iodine solution will be 0.1 N. The last three factors (which correct the actual H2S content to compensate for expansion due to temperature, pressure, and water content) can be combined and calculated as a function of temperature only. This has been done for the 500-ml gas sample and is included as the Tutweiler Factor Chart in Section 9.10 of these guidelines (Chart 2). Therefore, the equation above can be simplified to:
ml Iodine Normality Factor from PPM H2S 10,000 Solution of Iodine Tutweiler Used Solution Factor Chart
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SULFUR BLOCK 11.10.7 H2S Conc. in TGCU Contactor Ovhd Using Gas Detector Tubes As an alternative to the traditional wet-chemistry method described in the preceding Section 11.10.6 for determining the concentration of H2S in the TGCU Contactor overhead gas, gas detector tubes can be used to quickly and easily make this determination. Although the discussion that follows specifically addresses using gas detector tubes manufactured by Drägerwerk AG of West Germany, there may be suitable detector tubes available from other manufacturers. Dräger tubes can be purchased from most safety equipment supply companies. The following Dräger tubes can be used with this procedure:
11.10.7.1
H2S 5/b
Dräger Cat. No. CH 298 01
H2S 100/a
Dräger Cat. No. CH 291 01
Operating Principles
Dräger tubes and other gas detector tubes measure gas concentrations by using a sample pump to draw a specific volume of the gas to be sampled into a glass tube containing a suitable reagent. The gaseous compound of interest chemically reacts with the reagent to produce a color change. The length of the "stain" line is a direct function of the concentration of the compound in the sample gas. Some detector tubes are calibrated with measured lines to allow reading the concentration directly on the tube. Others, such as the two listed above, have reference marks on the tube that can be multiplied by a factor to compute the concentration. Dräger tubes are designed to be used with a Dräger Model 31 gas detector pump. This is a hand-operated bellows pump that will draw a 100 cc sample volume for each pump stroke. Some tubes are designed for a single sample stroke, while others may use 5, 10, or even 20 strokes. In some cases, a tube may be used for measuring different concentration ranges by using a different number of strokes. a.
Dräger Cat. No. CH 298 01, H2S 5/b This tube will measure H2S concentrations in the range of 50 PPM to 600 PPM when one sample stroke is used. If desired, the range can be reduced to 5 PPM to 60 PPM by using 10 sample strokes. Each tube contains a substrate of a white lead compound. When exposed to H2S, the lead
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SULFUR BLOCK compound is converted to brown lead sulfide. The H2S concentration in PPM can be read directly from the marks on the tube according to the length of the brown stain when using 10 sample strokes. If only one sample stroke is used, the tube reading is multiplied by 10 to give the PPM of H2S. This lead sulfide reaction is not affected by any of the other compounds normally found in the overhead gas from the TGCU Contactor. b.
Dräger Cat. No. CH 291 01, H2S 100/a This tube will measure H2S concentrations in the range of 100 PPM to 2,000 PPM when one sample stroke is used. Each tube contains a substrate of a white lead compound. When exposed to H2S, the lead compound is converted to brown lead sulfide. The H2S concentration in PPM can be read directly from the marks on the tube according to the length of the brown stain. This lead sulfide reaction is not affected by any of the other compounds normally found in the overhead gas from the TGCU Contactor.
11.10.7.2
Sampling the TGCU Contactor Overhead Gas
The overhead gas from the TGCU Contactor can be sampled from the sample connection near the sample line for the H2/H2S analyzer.
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1.
Before beginning, check the Dräger pump for leaks by inserting an unopened tube into the pump and stroking the pump. Confirm that the bellows does not re-expand. If it does, either the pump or its seal around the tube is leaking, and the test results will not be accurate.
2.
Attach a short piece of rubber tubing to the process sample valve.
3.
Break off the tips at each end of a Dräger tube and insert it into the sample pump (with the arrow on the side of the tube pointing toward the pump).
4.
Purge the rubber tubing by venting gas to the atmosphere for a few seconds. Pinch the rubber tubing closed at the end, close the gas sample valve, slip the end of the rubber tubing onto the end of the Dräger tube, and reopen the sample valve.
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SULFUR BLOCK
11.10.7.3
5.
Stroke the sample pump one time (be sure to compress the bellows until reaching the stops) and allow the pump to draw the gas sample into the detector tube. The sample stroke is complete when the metal chain on the bellows is taut.
6.
Close the sample valve and remove the rubber tubing from the end of the Dräger tube and from the sample valve.
7.
Read the length of the brown stain using the marks on the tube and record the reading.
Calculations
Mole (or Volume) PPM H2S (wet basis):
1013 Stain Tube PPM H2S Factor Length Baro. Pres., mbar The last factor corrects the measurement for pressure effects when samples are taken at elevations above sea level. Note that the average barometric pressure at the complex is 14.7 PSIA = 1013 mbar. The "Tube Factor" depends on the type of Dräger tube used and the number of sample strokes:
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Dräger Tube
Catalog No.
Sample Strokes
Tube Factor
H2S 5/b H2S 5/b H2S 100/a
CH 298 01 CH 298 01 CH 291 01
1 10 1
10 1 1
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SULFUR BLOCK 11.10.8 Monitoring the Performance Level of TGCU Catalyst The activity of the cobalt-molybdenum catalyst in the TGCU Reactor should remain adequate for years. For trouble-shooting purposes, however, its activity should be monitored at regular intervals, beginning at the initial startup, to establish its baseline performance. Two of the reactions that occur in the TGCU Reactor (refer to Section 11.6.3 of these guidelines for a complete discussion) are: CO + H2O
H2 + CO2
COS + H2O
H2S + CO2
The first reaction is the classic "water gas shift" reaction. Since this is an equilibrium reaction, an equilibrium constant for the reaction can be expressed in terms of the reactant and product concentrations: Keq
H2CO2 COH2O
This equilibrium constant is mainly a function of temperature. Since the TGCU Reactor outlet temperature for a given plant is fairly constant, as are the concentrations of CO2 and H2O in the process gas, then the ratio of CO to H2 in the TGCU Reactor effluent should remain fairly constant as long as the catalyst activity does not change. Similarly, the hydrolysis of COS to convert it to H2S is an equilibrium reaction. Its equilibrium constant can be expressed as: Keq
H2SCO2 COSH2O
Since the temperature, H2S concentration, H2O concentration, and CO2 concentration of the TGCU Reactor outlet should all be fairly constant, then the COS concentration of the gas leaving the TGCU Reactor should be fairly constant. It is for these reasons that Shell recommends using a gas chromatograph to analyze the TGCU Reactor effluent gas for H2, CO, and COS on a regular basis (once per month, for instance). Using the results of the chromatograph analyses, the CO/H2 ratio and the COS concentration can be plotted over time and allow trends to be detected in the catalyst activity.
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SULFUR BLOCK The CO/H2 ratio is usually plotted as PPM CO divided by % H2, and the COS is usually plotted as PPM. From the discussions above, it is clear that a trend upward in either value, CO/H2 ratio or COS concentration, indicates lower catalyst activity. Shell suggests planning to replace the catalyst within a few months once either value begins to rise rapidly. Note that the sample for the chromatograph can be taken from the gas leaving the TGCU Quench Column, since the H2, CO, and COS concentrations (on a dry basis) will be the same there as those leaving the TGCU Reactor. Because this gas stream is cooler and contains less water, it is often easier to sample and analyze than the TGCU Reactor effluent. As discussed in Section 11.6.3, it is also typical to find methane and/or methyl mercaptan in the TGCU Reactor effluent gas resulting from side reactions between hydrogen and the COS and CS2 produced in the Reactor Furnace in the sulfur plant. It can be informative to record the concentrations of CH4 and/or CH3SH from the chromatographic analyses as well. An increase in either component may indicate a loss in TGCU catalyst activity. However, higher CH4 and/or CH3SH concentrations leaving the TGCU Reactor may also be due to higher COS/CS2 concentrations entering the TGCU Unit due to lower catalyst activity in the sulfur plant. In order to allow determining whether such an increase is due to loss of activity in the sulfur plant or the TGCU Unit, it is helpful to analyze the TGCU Reactor inlet gas periodically with the gas chromatograph and record the amount of COS, CS2, and CO in the TGCU Reactor feed. Collecting samples of this gas is somewhat more difficult because the gas contains sulfur vapor, but the additional information provided by analyzing this stream can be extremely helpful for monitoring plant operations.
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Table of Contents 12.
TAILGAS THERMAL OXIDIZER ............................................................................ 12-2
12.1 PURPOSE OF SYSTEM ..................................................................................... 12-2 12.2 SAFETY ............................................................................................................... 12-2 12.3 PROCESS DESCRIPTION.................................................................................. 12-3 12.4 EQUIPMENT DESCRIPTION .............................................................................. 12-4 12.4.1 Thermal Oxidizer, A2-BA1570 ...................................................................... 12-4 12.4.2 Thermal Oxidizer Burner, A2-BA1571 .......................................................... 12-4 12.4.3 Steam Knock-out Drum, A2-FA1570 ............................................................ 12-4 12.4.4 Thermal Oxidizer Air Blower, A2-GB1570A/B .............................................. 12-4 12.4.5 Thermal Oxidizer Vent Stack, A2-ME1570 ................................................... 12-5 12.4.6 Refractory for Thermal Oxidizer, A2-MR1570 .............................................. 12-5 12.4.7 Thermal Oxidizer Waste Heat Boiler, A2-BF1570 ........................................ 12-5 12.5 INSTRUMENTATION AND CONTROL SYSTEMS ............................................. 12-7 12.5.1 Thermal Oxidizer Burner Management System ........................................... 12-7 12.5.2 Thermal Oxidizer Temperature Control ...................................................... 12-10 12.5.3 Thermal Oxidizer Excess Oxygen Control.................................................. 12-10 12.5.4 Boiler Low-Low Level S/D Transmitter Testing .......................................... 12-11 12.5.5 Thermal Oxidizer Shutdown System .......................................................... 12-13 12.6 PROCESS PRINCIPLES AND OPERATING TECHNIQUES ........................... 12-18 12.6.1 Equipment Damage .................................................................................... 12-18 12.6.2 Effect of Upstream Operations on the Thermal Oxidizer ............................ 12-21 12.6.3 "Swapping" Air Blowers During Operation .................................................. 12-23 12.6.4 Boiler Water Treatment .............................................................................. 12-24 12.7 PRECOMMISSIONING PROCEDURES ........................................................... 12-26 12.7.1 Preliminary Check-out ................................................................................ 12-26 12.7.2 Shutdown System Check-out ..................................................................... 12-27 12.7.3 Commissioning Fuel Gas, Pilot Gas, and I/A to the Process ..................... 12-28 12.8 STARTUP PROCEDURES................................................................................ 12-33 12.8.1 Initial Firing / Refractory Cure-out............................................................... 12-33 12.8.2 Normal Startup ........................................................................................... 12-48 12.9 SHUTDOWN PROCEDURES ........................................................................... 12-58 12.9.1 Planned Shutdown - No Entry .................................................................... 12-59 12.9.2 Planned Shutdown for Entry ....................................................................... 12-61 12.9.3 Shutting Down When Boiler Tubes Are Leaking ........................................ 12-65 12.9.4 Emergency Shutdown ................................................................................ 12-66 12.9.5 Effects of Shutdowns and Outages in Other Systems................................ 12-69
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12. TAILGAS THERMAL OXIDIZER 12.1 Purpose of System The purpose of the Tailgas Thermal Oxidation (TTO) system is to receive the tailgas from Sulfur Recovery Units (SRUs) or the Tailgas Cleanup Unit (TGCU), the vapors from the Sulfur Surge Tanks, and the spent degassing air from the Sulfur Degassing Unit (SDU), thermally incinerate all the sulfur compounds to sulfur dioxide (SO2), and disperse the effluent safely to the atmosphere. The effluent will normally contain less than 200 PPMV of SO2 on a dry, 0% oxygen basis. High-pressure superheated steam is produced by waste heat recovery from the thermal oxidation process.
12.2 Safety
WARNING ALL PIPING AND VESSELS INCLUDED IN THIS UNIT EITHER CONTAIN OR HAVE THE POTENTIAL FOR CONTAINING HAZARDOUS GASES THAT MAY CAUSE SERIOUS INJURY OR DEATH. THE TWO GASES THAT ARE MOST COMMON AND HAZARDOUS IN A TOXIC WAY ARE HYDROGEN SULFIDE AND SULFUR DIOXIDE. CLOSE ATTENTION SHOULD BE PAID TO THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES AS TO THE NATURE AND ABILITY OF THESE GASES TO CONTAMINATE OTHER ELEMENTS IN THIS UNIT. AN EMPLOYEE'S KNOWLEDGE OF THE HAZARDOUS CHEMICALS AND COMPOUNDS WITH WHICH HE WILL BE WORKING IS ONE OF THE MOST BASIC PREREQUISITES FOR HIS OWN SAFETY, THE SAFETY OF OTHERS, AND THE PROTECTION OF EQUIPMENT. ALL EMPLOYEES SHOULD REVIEW THE "GENERAL SAFETY" SECTION OCCASIONALLY TO REFRESH THEIR MEMORIES. NEW EMPLOYEES SHOULD STUDY IT UNTIL THE INFORMATION IS THOROUGHLY UNDERSTOOD. PEOPLE WHO HAVE NOT BEEN PROPERLY TRAINED SHOULD NOT BE ALLOWED TO OPERATE OR WORK IN AND AROUND THIS PLANT.
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12.3 Process Description The Systems Diagram, Material Balance and Process Flow Diagram, Dwg. Nos. 507000-7000-01, and 507000-7000-10 through -11, are contained in the "Process Flow Diagrams" Section of the Basic Engineering Package. Please refer to these drawings to follow this description of the process. When the TGCU is operating, the TGCU effluent containing H2S and COS flows to the Thermal Oxidizer, A2-BA1570, at about 39°C [102°F]. When the TGCU Unit is not in service, tailgas from each SRU containing H2S, SO2, COS, CS2, and elemental sulfur flows directly to the Thermal Oxidizer at about 156°C [313°F]. The spent degassing air from the Sulfur Degassing Unit and the sweep air streams from each Sulfur Surge Tank (both containing traces of H2S and sulfur vapor) are also routed to the Thermal Oxidizer. In the Thermal Oxidizer, essentially all of the sulfur compounds are incinerated to SO2 by the high-temperature oxidizing atmosphere created inside the Thermal Oxidizer. In addition, most of the carbon monoxide (CO) in the feed stream is oxidized to carbon dioxide, resulting in very low CO emissions from the Tailgas Thermal Oxidation system. Heat is provided to the Thermal Oxidizer by combustion of fuel gas in the Thermal Oxidizer Burner, A2-BA1571. Combustion air for the burner is supplied by the Thermal Oxidizer Air Blower, A2-GB1570A/B. The fuel gas flow rate is adjusted to maintain the furnace temperature at 816°C [1500°F] to ensure complete incineration of the sulfur compounds and carbon monoxide in the feed to the Thermal Oxidizer. The effluent from the Thermal Oxidizer flows to the Thermal Oxidizer Waste Heat Boiler, A2-BF1570. The gas is cooled to about 288°C [550°F] as it generates and superheats steam at 45.0 kg/cm2(g) [640 PSIG], which is exported to the HP steam header at about 400°C [752°F] for use as motive steam to the Sulfur Pit Ejector and for use elsewhere in the refinery. (Note that the HP steam produced in each SRU is also superheated in this boiler by combining it with the steam this boiler generates.) The cooled effluent is then dispersed to the atmosphere from the top of the Thermal Oxidizer Vent Stack, A2-ME1570.
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12.4 Equipment Description 12.4.1
Thermal Oxidizer, A2-BA1570 The Thermal Oxidizer is a non-catalytic thermal incineration chamber. The furnace shell is internally lined with refractory insulation to protect it against the extreme process temperatures inside. The maximum operating temperature is about 1000°C. Although the furnace can withstand short excursions above this temperature, prolonged operation above this temperature can damage the refractory or the downstream boiler.
12.4.2
Thermal Oxidizer Burner, A2-BA1571 This burner is specifically designed to burn fuel gas to provide the heat input for the Thermal Oxidizer. The burner assembly consists of the main fuel gas burner tip, a pilot, two flame scanners, two viewports, and specially designed air distribution baffles to effect proper combustion. This complete unit is installed in the front of the Thermal Oxidizer. The StackMatch® ignitor/pilot assembly is designed to be retracted or extracted after the main burner has been lit. If it is extracted, the block valve can be closed to isolate it from the furnace atmosphere. The assembly includes filters for the incoming fuel gas and air, which should be checked (and cleaned, if necessary) after each use so that there is no chance of a plugged filter causing delays during the next startup.
12.4.3
Steam Knock-out Drum, A2-FA1570 This vertical vessel is installed in the common HP steam line from the Waste Heat Boilers in the SRUs and the steam drum on the Thermal Oxidizer Waste Heat Boiler. Its purpose is to remove any water droplets (condensed or entrained) from the steam before it is routed to the superheater pass in the Thermal Oxidizer Waste Heat Boiler, so that the superheated steam exported to the refinery does not contain excessive amounts of solids. The water collected in this vessel is routed to the high pressure condensate header via a steam trap.
12.4.4
Thermal Oxidizer Air Blower, A2-GB1570A/B These single-stage centrifugal fans provide the combustion air required to burn fuel gas in the Thermal Oxidizer Burner. The air flow rate is controlled by throttling a valve in the common blower discharge line. The
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fans are connected to the discharge piping through flexible connectors to allow the necessary freedom for the expansion and movement that occurs during normal operation. Each blower is equipped with an inlet filter and silencer.
12.4.5
Thermal Oxidizer Vent Stack, A2-ME1570 The Thermal Oxidizer Vent Stack disperses the effluent from the Thermal Oxidizer Waste Heat Boiler safely to the atmosphere. It is a free-standing stack typically constructed of carbon steel and externally insulated to keep its metal shell safely above the acid dewpoint of the process gas flowing inside the stack.
12.4.6
Refractory for Thermal Oxidizer, A2-MR1570 The refractory lining in the firing chamber of the Thermal Oxidizer consists of a layer of fireclay firebrick, installed with high temperature air-setting mortar. The inlet plenum of the Thermal Oxidizer, exposed to the high temperatures produced by the Thermal Oxidizer Burner, is covered with a layer of castable refractory. The refractory lining inside the furnace includes a "choke ring" located about two-thirds of the way down the length of the furnace. The purpose of the choke ring is to promote mixing between the TGCU effluent gas (or SRU tailgas) and the hot combustion products from the Thermal Oxidizer Burner, ensuring efficient oxidation of the sulfur compounds and carbon monoxide that are present in the tailgas.
12.4.7
Thermal Oxidizer Waste Heat Boiler, A2-BF1570 The Thermal Oxidizer Waste Heat Boiler is a water-tube style boiler. It includes a superheater pass for the steam produced in this boiler, plus steam produced in the SRUs. The superheater consists of two sections with a desuperheater between the two sections and a desuperheater on the steam outlet. There are also two sections of boiler tubes, the screen section and the main section. Hot gas entering the boiler flows first across the screen section tubes, then across the two superheater sections, then lastly across the main section of boiler tubes. The main boiler tube section contains tubes connecting the steam drum on top of the boiler to the mud drum on the bottom of the boiler, as well as side wall tubes. The screen section contains rows of tubes also connected to the mud and steam drums. The hot gas entering the boiler
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casing boils water as it circulates in the screen and main boiler tubes, generating 48.5 kg/cm2(g) saturated steam. The saturated steam generated in the boiler tubes exits the steam drum at and is combined with saturated HP steam generated by the Waste Heat Boilers in the SRUs. The combined steam is routed to the first superheater section, then to the first desuperheater, and then to the second superheater section. The resulting superheated steam is routed to the second desuperheater and then to the HP steam header at about 45 kg/cm2(g) and 400°C.
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12.5 Instrumentation and Control Systems 12.5.1
Thermal Oxidizer Burner Management System The Thermal Oxidizer Burner Management System (BMS), controlled by a programmable logic controller (PLC), has been designed to ensure a safe firing order. It requires a certain sequence of steps before permitting ignition. The function of the various system components is described below.
12.5.1.1
Startup/Run Interlocks The "startup" and "run" interlock logic is shown on the Logic Flow Diagrams contained in the Instrumentation and Controls Diagrams section of the Basic Engineering Package. The purpose of this logic is to simplify lighting the Thermal Oxidizer Burner by automatically positioning the process gas switching valves in the proper sequence for safe operation: (1)
Before attempting ignition of the burner, any process gas from the SRUs and/or TGCU Unit should be blocked from flowing into the Thermal Oxidizer in case the process gas is combustible. Setting selector switch A2-HS15785 on the local TTO control panel to "STARTUP" will open the bypass valve, A2-HV15741, prove the valve open, then close the inlet valve, A2-HV15740, so that the process gas is diverted directly to the Thermal Oxidizer Vent Stack.
(2)
Once the pilot burner in the Thermal Oxidizer Burner has been lit, process gas can then be directed into the Thermal Oxidizer. Setting selector switch A2-HS15785 to "RUN" will automatically open the inlet valve, prove the valve open, then close the bypass valve.
These two process gas valves constitute the Complete Flowpath Interlock for the TTO. Although this interlock is not part of the TTO ESD system (since the TTO always has a direct path to its vent stack), it is a part of the Complete Flowpath Interlocks that are included in the SRU Complete Flowpath alarms and TGCU ESD system. By automating the valve switching steps and including checks of the limit switches in the logic, the chance of accidentally causing an SRU or a TGCU shutdown due to an incomplete flowpath
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK (or over-pressure resulting from an incomplete flowpath) while starting up the Thermal Oxidizer is greatly reduced. If either of the switching valves does not move to the proper position, the corresponding status light on the local TTO control panel should continue to blink. This will alert the operators to investigate the problem and take any required corrective action so that the BMS allows proceeding.
12.5.1.2
Flame Scanners The flame scanners, A2-BE15763A and A2-BE15763B, monitor the pilot and main fuel gas burners. If a scanner detects a flame, the associated flame proven signal will indicate. If neither scanner detects a flame, the TTO ESD system is activated. Since a "flame proven" signal from either scanner satisfies the system, maintenance may be performed on one flame scanner while the other remains in service. Note that a third flame scanner, A2-BE15758, is furnished with the pilot to detect its flame, but it is used only to activate its status light (A2-GL15758) on the local TTO control panel and a status indicator (A2-BL15758) in the DCS.
12.5.1.3
Purge Cycle To ensure the unit is safe for firing, a purge cycle must be completed before the pilot can be ignited. To purge the Thermal Oxidizer, a Thermal Oxidizer Air Blower is used to send a high rate of air through the Thermal Oxidizer for 45 seconds. The air flow must then be reduced to a low rate to allow ignition of the pilot.
12.5.1.4
Ignition Cycle After the purge cycle is complete, pressing the "IGNITION" push-button (A2-HPB15765) causes the BMS to initiate an attempt to ignite the pilot. The BMS closes the pilot burner purge air valve (A2-HV15782), opens the pilot air block valve (A2-NV15753), closes the vent valve in the fuel gas to the pilot (A2-NV15756), opens the pilot fuel gas block valves (A2-NV15755 and A2-NV15757), and energizes the ignition system (A2-BX15758). After a 15 second ignition trial, the ignition system is de-energized. If a pilot flame is established, one or both flame scanners will indicate "flame proven" and the block valves in the air and fuel gas supplies
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK to the pilot will remain open. Otherwise, the air and fuel gas supplies to the pilot are blocked-in and the purge cycle must be repeated.
12.5.1.5
Main Fuel Gas Firing After the pilot burner is lit, the main fuel gas supply is enabled. Pressing the "MAIN FUEL ON" push-button (A2-HPB15767) on the local TTO control panel will close the vent valve in the fuel gas to the main burner (A2-NV15747) and open the main fuel gas block valves (A2-NV15746 and A2-NV15748). The main fuel gas control valve (A2-TV15749) can then be adjusted using either A2-HIC15745 on the local TTO control panel or A2-TIC15749 in the DCS to control the firing rate of the main burner. DCS control of the firing rate of the Thermal Oxidizer is accomplished by switching A2-HS15749 from "local" to "remote" so that A2-TIC15749 in the DCS can then control the temperature in the Thermal Oxidizer. The fuel gas flow rate can be increased as necessary to heat the refractory in the Thermal Oxidizer according to the refractory warmup schedule, and to heat the water in the Thermal Oxidizer Waste Heat Boiler. Note that the main fuel gas control valve has a minimum firing rate, as set by the "minimum fire" relay in the DCS, A2-TY15749. The proper setting for A2-TY15749 will be determined during startup by finding the minimum firing rate to maintain a stable flame on the main fuel gas burner.
12.5.1.6
Pilot On/Off Switch Push-button A2-HPB15774 on the local TTO control panel is used to turn the pilot burner on and off. If the pilot burner is "on", pressing this push-button will extinguish the burner by closing the two block valves and opening the vent valve in its fuel gas supply, closing the block valve in its air supply, de-energizing its ignition system, and opening the valve to begin purging the burner with air. If the burner is "off " (and the "flame proven" is already satisfied by the main burner tip), pressing this push-button will ignite the burner by closing the valve to cease purging the burner with air, closing the vent valve and opening the two block valves in its fuel gas supply, opening the block valve in its air supply, and energizing A2-BX15758 for 15 seconds.
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12.5.2
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
Thermal Oxidizer Temperature Control The Thermal Oxidizer is designed to cause thermal incineration of all the sulfur compounds that enter with the sulfur plant tailgas stream, converting them into sulfur dioxide, SO2. This is accomplished by providing a high-temperature oxidizing atmosphere inside the Thermal Oxidizer, so that free oxygen can react with the sulfur compounds to form SO2. The Thermal Oxidizer has also been designed to provide near complete oxidation of the carbon monoxide (CO) normally found in TGCU effluent gas and sulfur plant tailgas, converting the carbon monoxide into carbon dioxide, CO2. Although a temperature of 550°C is usually adequate to ensure complete oxidation of the sulfur compounds, a temperature in excess of 760°C is normally required to achieve significant oxidation of CO. This temperature is achieved in the Thermal Oxidizer by combusting fuel gas in the Thermal Oxidizer Burner. The amount of fuel gas fed to the burner is controlled by A2-TIC15749 in the DCS, which senses the Thermal Oxidizer outlet temperature and adjusts the fuel gas flow accordingly. Since the TGCU effluent gas and/or the SRU tailgas streams contains variable amounts of combustible gases (H2S, H2, CO, etc.), the controller must respond quickly to accommodate fluctuations caused by SRU and/or TGCU operations. The design setpoint for this controller is 816°C. Actual operations may determine that a lower temperature gives satisfactory CO destruction, which would reduce the amount of fuel gas consumed by the Thermal Oxidizer Burner (but would also reduce the steam production from the Thermal Oxidizer Waste Heat Boiler).
12.5.3
Thermal Oxidizer Excess Oxygen Control As discussed earlier, the Thermal Oxidizer must maintain an oxidizing atmosphere so that there is free oxygen in the furnace to react with the sulfur compounds and the carbon monoxide. Operating the Thermal Oxidizer Burner with excess air provides this free oxygen, so that after combusting the fuel gas supplied to the burner sufficient oxygen remains to oxidize the sulfur compounds entering the Thermal Oxidizer. Sulfur plant Thermal Oxidizers are normally designed to supply at least 25% more air than stoichiometric requirements to ensure complete conversion of the sulfur compounds. There are no provisions in this plant at present for automatically controlling the amount of excess air in the Thermal Oxidizer. If optimum
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operation is desired, the oxygen analyzer that is part of the CEMS, A2-AE15153, on the Thermal Oxidizer Vent Stack can be used to measure the amount of oxygen in the stack gas, and the setpoint of the air flow controller, A2-FIC15760, can be adjusted as necessary to give the desired oxygen concentration in the Thermal Oxidizer effluent.
12.5.4
Boiler Low-Low Level S/D Transmitter Testing The Thermal Oxidizer Waste Heat Boiler has independent level transmitters, A2-LT15150A/B/C, connected to the PLC that activate the TTO ESD system before the water level can get low enough to cause boiler damage. The shutdown is activated when two out of three transmitters show a low-low level. These transmitters should be tested periodically to determine that they are functioning properly. Consider A2-LT15150A on the Thermal Oxidizer Waste Heat Boiler, for example. The procedure for testing A2-LT15150B and A2-LT15150C will be similar. The procedure for testing A2-LT15150A is as follows: (1)
The outside operator notifies the DCS operator that he is preparing to test shutdown level transmitter A2-LT15150A on the Thermal Oxidizer Waste Heat Boiler.
(2)
The DCS operator confirms that A2-LI15150B and A2-LI15150C are both indicating adequate level in the boiler, then notifies the outside operator to proceed.
CAUTION
DO NOT PROCEED UNLESS THE OTHER TWO LEVEL INDICATORS SHOW ADEQUATE LEVEL IN THE BOILER. OTHERWISE THE LOW-LOW LEVEL SHUTDOWN IN THE TTO ESD WILL BE ACTIVATED AS SOON AS THE OUTSIDE OPERATOR BEGINS DRAINING THE LEVEL TRANSMITTER IN THE NEXT STEP. (3)
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After being notified to proceed by the DCS operator, the outside operator blocks-in A2-LT15150A by closing its block valves, then
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK opens the drain valve on the bottom of the transmitter to drain the water from the instrument.
(4)
If the transmitter is operating properly, the DCS will alarm that there is a low level in the Thermal Oxidizer Waste Heat Boiler on A2-LI15150A. The DCS operator acknowledges the alarm on the DCS and reports it to the outside operator.
(5)
After being notified of the alarm, the outside operator closes the drain valve on A2-LT15150A, slowly opens its bottom block valve to allow the transmitter to fill with water then opens its top block valve. This should clear the low level alarm on A2-LI15150A in the DCS.
(6)
After confirming that the low level alarm has cleared, the other level transmitters can be tested in a similar fashion.
NOTE:
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The DCS operator must not begin another task until confirming that the low level alarm has cleared. This is to guard against having a level transmitter malfunction that causes a TTO ESD when the other transmitters are tested.
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12.5.5
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
Thermal Oxidizer Shutdown System The purpose of the Tailgas Thermal Oxidation Emergency Shutdown system (TTO ESD) is to shut off the flow of fuel gas, fuel gas, and combustion air to the Thermal Oxidizer when serious problems occur. The Cause and Effect Diagram, contained in the Instrumentation and Controls Diagrams section of the Basic Engineering Package, describes the TTO ESD system in block format. For reference, the causes and effects of the ESD system shown on this diagram are explained below. As noted on the Cause and Effect Diagram, it is recommended that a 5 second delay be used for most of the process parameters included in the causes of the ESD system. This is to prevent the "nuisance" shutdowns that are sometimes caused by momentary fluctuations in the process or the sensing elements.
12.5.5.1
Causes Any one of the causes listed below will activate the TTO ESD system: a.
Manual Shutdown Switches, A2-HS15783 and A2-HS15784 An operator can activate the TTO ESD system using either of two manual shutdown switches:
b.
(1)
A2-HS15783 is a NORMAL / ESD selector switch in the DCS.
(2)
A2-HS15784 is a NORMAL / ESD selector switch mounted on the local TTO control panel.
No Thermal Oxidizer Air Blower Running, A2-GB1570A/B starter contacts If neither Thermal Oxidizer Air Blower is running, TGCU effluent and/or SRU tailgas could flow backwards down the combustion air line and escape from the blowers. The motor starter contacts are used to determine whether a blower is running, and will activate the TTO ESD system if neither is running.
c.
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Thermal Oxidizer A2-FT15760A/B/C
Combustion
Tailgas Thermal Oxidation
Air
Low-Low
Flow,
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK Loss of air flow from the Thermal Oxidizer Air Blower could cause the Thermal Oxidizer Burner flame to become unstable, or allow TGCU effluent and/or SRU tailgas to flow backwards down the combustion air line and escape from the blowers. These devices will activate the TTO ESD to block the air line before this can occur. The shutdown setpoint is 20% of normal flow. Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD (i.e., at least two transmitters must show low-low flow) to avoid spurious "trips" due to the malfunction of a single transmitter. d.
Burner Fuel Gas Supply Low-Low Pressure, A2-PT15744A/B/C Loss of the fuel gas supply would cause the fuel gas pressure to drop at the burner. This device will shut down the TTO before flame instability creates the potential for an explosion. The setpoint for these transmitters is 0.35 kg/cm2(g). Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD.
e.
Burner Fuel Gas A2-PT15751A/B/C
High-High
Burner
Pressure,
A malfunction of the fuel gas pressure control could cause excessive firing of the main burner in the Thermal Oxidizer Burner. These devices will prevent this unsafe condition by shutting down the Thermal Oxidizer. The setpoint for the Note that there are three transmitters is 3.5 kg/cm2(g). independent transmitters and 2oo3 voting logic is used for the ESD. f.
Thermal Oxidizer Burner Flame Failure, A2-BY15763A and A2-BY15763B Dual flame scanners are aimed to observe the flames from both the pilot burner and the main gas burner. If the neither scanner detects a flame (2oo2), a "flame failure" occurs and activates the TTO ESD system. If only one scanner detects a flame (1oo2), a malfunction alarm is activated in the DCS, but the TTO ESD system is not activated. A third flame scanner, A2-BY15758, is furnished with the pilot to detect its flame, but it is used only to activate its status light (A2-GL15758) on the
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK local control panel and a status indicator (A2-BL15758) in the DCS. g.
Thermal Oxidizer High-High Temperature, A2-TT15749A/B/C These devices activate the TTO ESD system and shut down the Thermal Oxidizer Burner if a temperature of 1000°C or higher is measured in the Thermal Oxidizer. Temperatures higher than this can overheat the refractory inside the Thermal Oxidizer to the point that it weakens and fails, causing heat damage to the Thermal Oxidizer shell. Excessive temperatures in this furnace can also lead to damage of the tubes or casing of the Thermal Oxidizer Waste Heat Boiler installed downstream. Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD.
h.
Superheated Steam High-High Temperature, A2-TT15142AB/C These devices activate the TTO ESD system and shut down the Thermal Oxidizer Burner if the temperature of the superheated steam leaving the second superheater pass of the Thermal Oxidizer Waste Heat Boiler reaches 420°C. Steam temperatures higher than this can lead to damage of the superheater tubes, or damage the piping and equipment downstream in the steam header and its users.
i.
Steam Separator High-High Liquid Level, A2-LT15148A/B/C If the steam trap that drains the Steam Scrubber, A2-FA1570, should fail, a level of condensate could begin to build inside the vessel. These devices activate the TTO ESD system to shut down the Thermal Oxidizer Burner before this condensate can carry-over into the hot tubes in the superheater passes of the Thermal Oxidizer Waste Heat Boiler and cause damage to the tubes. They are set to actuate if the liquid level reaches 1280 mm above the bottom seam of the vessel. Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD.
j.
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Thermal Oxidizer Waste Heat Boiler Low-Low Water Level, A2-LT15150A/B/C
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK These devices prevent the water level from dropping too low in the steam drum of the boiler. Hot combustion gas flows outside the boiler tubes and will destroy these tubes if they are not cooled by water boiling inside the tubes. The setpoint for these devices will be specified by the boiler vendor. Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD. k.
Thermal Oxidizer A2-TT15155A/B/C
Vent
Stack
High-High
Temperature,
During periods when the Thermal Oxidizer is shut down, if the sulfur plants continue to run but the TGCU is not on-line, elemental sulfur in the SRU tailgas may condense inside the Thermal Oxidizer, the Thermal Oxidizer Waste Heat Boiler, and/or the Thermal Oxidizer Vent Stack. If the plant is operated in this manner for extended periods, a considerable amount of liquid sulfur may accumulate. This liquid sulfur may ignite once the Thermal Oxidizer is restarted and air is flowing through the system. The heat from the sulfur fire could damage the non-refractory lined surfaces of the boiler casing and stack if allowed to continue burning. These devices detect the high temperature from the fire and shut the Thermal Oxidizer back down before equipment damage occurs. The setpoint for the transmitters is 400°C. Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD. l.
Pilot Ignition Safety Interlock Timer Expired, BMS logic Once the pre-ignition steps have been completed and the BMS gives a "PERMIT TO IGNITE" for the pilot burner in the Thermal Oxidizer Burner (signaled by illuminating status indicator light A2-AL15773 on the local TTO control panel), an ignition safety interlock timer is started in the BMS. If an ignition attempt is not made within 5 minutes, the TTO ESD system will be activated to shut down the Thermal Oxidizer. This prevents a potentially unsafe condition from persisting, where a leaking fuel gas valve could cause an explosive mixture to form in the Thermal Oxidizer, since the air flow is low at this point in the startup procedure.
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12.5.5.2
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK Effects A Thermal Oxidizer shutdown, activated either manually or automatically, has the following effects on the Tailgas Thermal Oxidation system: a.
Shuts down the Thermal Oxidizer Air Blower, A2-GB1570A/B.
b.
Closes the air flow control valve, A2-FV15760, to prevent back-flow and venting of any hazardous gases to the atmosphere.
c.
Initiates the Thermal Oxidizer Burner Shutdown system, which performs the following actions:
d.
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(1)
Shuts off and depressurizes the main fuel gas supply by closing block valves A2-NV15746 and A2-NV15748 and opening vent valve A2-NV15747.
(2)
Shuts off the pilot air supply by closing block valve A2-NV15753.
(3)
Shuts off and depressurizes the pilot gas supply by closing block valves A2-NV15755 and A2-NV15757 and opening vent valve A2-NV15756.
(4)
De-energizes the ignition system, A2-BX15758.
(5)
Begins purging the pilot burner with air by opening block valve A2-HV15782.
Initiates back-purging of the stack gas analyzer, A2-AE15152, to prevent any un-oxidized sulfur leaving the TTO from fouling the analyzer.
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12.6 Process Principles and Operating Techniques The more important considerations involved in startup, operation, shutdown, maintenance, and emergency procedures of the Tailgas Thermal Oxidation system are discussed in the remaining sections of this portion of the operating guidelines. The operator should also be thoroughly acquainted with the equipment and the "Process Description" section in these guidelines before attempting to operate the plant in accordance with the operating techniques that follow. If the function of each portion of the plant equipment is understood, the sequence of steps outlined in the "procedures" sections will be more easily understood. In addition, the following general discussion of principles and techniques will clarify the reasons for some of the procedures.
12.6.1
Equipment Damage During periods when the TTO is shut down, if either SRU continues to run and the TGCU Unit is not on-line, elemental sulfur in the SRU tailgas may condense inside the Thermal Oxidizer, the Thermal Oxidizer Waste Heat Boiler, and/or the Thermal Oxidizer Vent Stack. If the plant is operated in this manner for extended periods, a considerable amount of liquid sulfur may accumulate. This liquid sulfur will ignite once the TTO is restarted and air is flowing through the system. The heat from the sulfur fire will damage the tubes in the boiler and/or the non-refractory lined surfaces of the boiler, outlet line, and stack if allowed to continue burning. If this situation develops, connect a steam trap to the bottom connection on the steam-jacketed nozzle in the bottom of the Thermal Oxidizer Waste Heat Boiler casing and supply LP steam to the top connection. Then remove the blind flange from the nozzle and allow the liquid sulfur to drain from the casing. Once the sulfur has been removed, a safe restart of the TTO should then be possible.
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WARNING IF EITHER SRU IS ON-LINE WHILE DRAINING SULFUR FROM THE BOILER CASING, TGCU EFFLUENT OR SRU TAILGAS MAY BE RELEASED TO THE SURROUNDINGS FROM THE DRAIN NOZZLE. THIS PROCESS GAS CONTAINS TOXIC GASES (H2S AND PERHAPS SO2). ALWAYS OBSERVE PROPER PROCEDURES AND PRECAUTIONS WHEN USING THIS DRAIN CONNECTION. THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES SHOULD BE CONSULTED IF THERE IS ANY DOUBT ABOUT HOW TO WORK SAFELY WHEN H2S OR SO2 MAY BE PRESENT. Too rapid heating or cooling can damage the refractory installed in the Thermal Oxidizer. The Initial Cure and Normal Warmup schedules for the refractory are provided by the refractory vendor. These schedules should be adhered to quite closely. Explosive mixtures of air and gases in the equipment are a potential danger. During an automatic shutdown, all air, pilot gas, and fuel gas flows are shut off simultaneously. Any malfunction of these devices could leak an explosive mixture into the unit. For this reason, the PLC requires purging of the Thermal Oxidizer before attempting pilot ignition, and requires re-purging the furnace if the burner does not light but fuel gas was admitted.
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CAUTION
NEVER "HYDROBLAST" THE TUBES (OR ANY OTHER STEEL SURFACES) IN TTO EQUIPMENT. NOT ONLY DOES THIS REMOVE THE PROTECTIVE SULFIDE FILM THAT FORMS ON CARBON STEEL AND PREVENTS CORROSION, THE WATER WILL REACT WITH THE SULFUR COMPOUNDS PRESENT IN THE EQUIPMENT TO FORM A VARIETY OF ACIDS (SULFUROUS, POLYTHIONIC, ETC.) THAT RAPIDLY CORRODE THE STEEL. THERE HAVE BEEN NUMEROUS INSTANCES OF SULFUR PLANT BOILERS BEING BLASTED DURING A TURNAROUND TO CLEAN THEM UP, THEN HAVING THE TUBES BEGIN LEAKING AS SOON AS THE BOILER IS RETURNED TO SERVICE. IF THE FINNED BOILER TUBES HAVE BECOME FOULED, THE BEST WAY TO CLEAN THE TUBES IS TO BLAST THEM WITH COMPRESSED AIR. IF SULFUR OR SULFUR COMPOUNDS HAVE FOULED THE TUBES, IT MAY BE HELPFUL TO APPLY HEAT TO THE TUBES, AS THIS WILL MELT ANY SULFUR THAT MAY BE PART OF WHAT HAS FOULED THE TUBES. ONE WAY TO DO THIS IS TO DRAIN THE WATER FROM THE BOILER AND PUT STEAM IN THE STEAM DRUM. DRAIN THE CONDENSATE PERIODICALLY FROM THE MUD DRUM TO KEEP LIVE STEAM ON THE TUBES.
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12.6.2
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
Effect of Upstream Operations on the Thermal Oxidizer The process gases to be incinerated in the Thermal Oxidizer can have a widely varying content of combustible gases, such as hydrogen, carbon monoxide, hydrogen sulfide, and even hydrocarbons on occasion. As a result, the temperature control system for the Thermal Oxidizer can be subjected to sudden swings in fuel gas demand, leading to temperature excursions if the changes occur more rapidly than the control system can accommodate. Sudden drops in combustible content are most often caused by low H2S in the TTO feed gas. This will usually only occur when SRU tailgas is being routed directly to the TTO because the TGCU Unit is not in service. Under these circumstances, if too much process air is fed to either SRU, nearly all of the H2S will be consumed in the sulfur plant and the tailgas from that SRU will contain only SO2. This will be indicated by high air demand on the air demand controller in the SRU in question. However, the sudden drop in the Thermal Oxidizer temperature is usually of no consequence since the TTO feed contains very little H2S under these circumstances, meaning that the potential loss of H2S oxidation efficiency in the Thermal Oxidizer is not really of concern. The low furnace temperature alarms in the DCS will alert the operator when this condition occurs, as will the high air demand alarm on the air demand controller in the DCS. The more serious problem is when the combustible content of the TTO feed gas suddenly increases and causes high temperature in the furnace. The most common cause of this is high hydrocarbon content in the sulfur plant feed stream(s). Hydrocarbons require 3-15 times more combustion air per mole than H2S does. A sudden increase in the hydrocarbon concentration of the acid gas (due to upsets in the upstream units) will "starve" the sulfur plant(s) for air because the air demand controller(s) cannot adjust the air:acid gas ratio enough to keep the SRU(s) on-ratio. The available oxygen will burn the hydrocarbons preferentially over H2S, with the result that insufficient H2S is reacted to form SO2. The SO2 that does form will be completely consumed by the Claus reaction in the furnace(s) and the catalyst beds, allowing large quantities of unreacted H2S to leave the sulfur plant(s). Even if the TGCU is in service at the time, H2S in these quantities will overwhelm the capability of the TGCU solvent to absorb H2S. Thus,
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regardless of whether the TGCU is in service or not, these large quantities of H2S will reach the Thermal Oxidizer and cause high furnace temperature there. Even though the TTO temperature control system will begin to cut back the fuel gas to the Thermal Oxidizer Burner, it is possible that the TTO feed gas will contain so much H2S that the temperature can be excessive even with the fuel gas valve at its "minimum fire" position. If the H2S concentration is high enough, or the change is sudden enough, the high-high furnace temperature shutdownwill be tripped and the TTO ESD system will be activated to shut down the Thermal Oxidizer. However, the high-H2S gas will still be flowing into the Thermal Oxidizer, since the TTO feed gas is not interrupted by a TTO ESD. This means that large amounts of H2S may be vented un-incinerated from the Thermal Oxidizer Vent Stack.
WARNING
IF THIS SITUATION OCCURS, DIRECT YOUR ATTENTION IMMEDIATELY TO CORRECTING THE UPSET IN THE UPSTREAM UNIT THAT IS CAUSING THE PROBLEM IN THE SULFUR PLANT(S). IN EXTREME CASES, IT MAY BE NECESSARY TO SHUT DOWN THE SRUS AND THE TGCU UNIT UNTIL THE UPSTREAM PROBLEMS HAVE BEEN CORRECTED, SO THAT EXCESSIVE AMOUNTS OF H2S DO NOT CONTINUE TO BE VENTED FROM THE THERMAL OXIDIZER VENT STACK. DO NOT ATTEMPT TO RESTART THE THERMAL OXIDIZER UNTIL THE PROBLEM HAS BEEN CORRECTED AND THE H2S CONTENT OF THE TTO FEED GAS IS BACK TO ACCEPTABLE LEVELS. ATTEMPTING TO RESTART THE THERMAL OXIDIZER WHEN ITS FEED GAS CONTAINS EXCESSIVE H2S WILL SIMPLY LEAD TO THE THERMAL OXIDIZER GOING DOWN AGAIN ON HIGH-HIGH TEMPERATURE.
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12.6.3
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
"Swapping" Air Blowers During Operation While the TTO is running, it is often necessary to "swap" air blowers to bring the off-line blower on-line so that the other blower can be shut down. This can usually be accomplished with minimal impact on the process by starting and stopping the blowers in the proper sequence. The procedure given below is one technique for swapping blowers. One of the complicated aspects associated with swapping blowers is the impact that bringing the off-line blower on-line can have on the air flow. When the second blower is brought on-line, there is a potential to suddenly double the air flow to the TTO. This would not only disturb the process, it could possibly blow out the flame in the burner. For this reason, the switch from one blower to the other must be made in a controlled fashion. The procedure below describes how to switch from the "A" blower to the "B" blower, for example. That is, the "A" blower is running to the TTO and the "B" blower is not currently running. The procedure to switch from the "B" blower to the "A" blower in the TTO is similar. Make sure the SRUs, TGCU, and TTO are operating stably before proceeding.
Issued 30 August 2011
A.
Confirm that the manual discharge valve on the off-line blower, the "B" blower, is closed.
B.
Start the "B" blower using its local start/stop control station.
C.
Once the blower starts, slowly open its discharge valve, allowing time for the air flow controller to adjust the air flow control valve to keep the combustion air flow rate at the proper value.
D.
Once the discharge valve on the "B" blower is fully open, slowly close the discharge valve on the "A" blower, again allowing time for air flow controller to adjust the air flow control valve.
E.
Once the discharge valve on the "A" blower is fully closed, shut down the "A" blower using its local start/stop control station.
F.
The blower swap is now complete. Before leaving the area, visually confirm that: (1)
The off-line blower is stopped.
(2)
The discharge valve on the off-line blower is closed.
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12.6.4
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK (3)
The on-line blower is running smoothly.
(4)
The process has returned to steady operation.
Boiler Water Treatment SAMSUNG TOTAL PETROCHEMICALS CO., LTD. IS RESPONSIBLE FOR ESTABLISHING AND MONITORING THE BOILER AND WATER CHEMICAL TREATMENT PROGRAM. Proper boiler water chemical treatment is essential to achieving long service life for the Thermal Oxidizer Waste Heat Boiler. Without good day-to-day control of the water quality, solids buildup, corrosion, and attack by the treating chemicals themselves can occur. It is Samsung Total Petrochemicals Co., Ltd.'s responsibility to see that a proper chemical treating program is initiated prior to startup and that the program is properly monitored and refined throughout the service life of the plant. There are many qualified boiler and water treatment companies that can advise the owner/operator on chemical treatment testing and controls. It is recommended that only those companies that have local technicians with extensive experience specifically in boiler water treatment be selected to assist with Samsung Total Petrochemicals Co., Ltd.’s program. The design details incorporated in the Thermal Oxidizer Waste Heat Boiler have proven to be very reliable when combined with good operator practice regarding water treatment. However, even properly designed equipment can be severely damaged during a short period of operation if the water treatment program is inadequate or improper. The Thermal Oxidizer Waste Heat Boiler is equipped with a continuous blowdown on the steam drum to remove suspended and dissolved solids from the water inside the boiler. In addition, the boiler is equipped with an intermittent blowdown connection on the bottom of its mud drum. This intermittent blowdown valve should be used on a regular basis to give the boiler a good "blow" to prevent sludge from accumulating in the bottom of the drum. Sludge must not be allowed to coat the boiler tubes. The consequence of fouling the inside of the boiler tubes is tube failure from overheating, as the fouling will impair the heat transfer and allow the hot combustion gases to destroy the tubes.
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Prior to using the intermittent blowdown valve, use the level controller in the DCS to raise the water level in the boiler up to the high level alarm point. Then open the intermittent blowdown valve until the level drops back to the normal liquid level. Watch the boiler level in the sight glasses throughout this operation to ensure that the level is not lost (which would activate the TTO ESD and shut the Thermal Oxidizer down). Remember to reset the level controller at the conclusion of this procedure.
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
12.7 Precommissioning Procedures Prior to the initial startup, there are a number of precommissioning activities that are necessary to ensure that the newly constructed plant is ready to be placed in service. The activities outlined below should serve as a guide, but there may be others required as a part of your normal plant procedures.
12.7.1
Issued 30 August 2011
Preliminary Check-out A.
Check all equipment to ensure that it is properly installed. This will probably require consulting Manufacturer's literature as well as construction drawings.
B.
Check and lubricate all equipment, in accordance with the Manufacturer's recommendations.
C.
Check the rotation of the Thermal Oxidizer Air Blowers by operating each blower for a short period with its discharge valve closed.
D.
Check all piping and equipment to be sure that all blinds have been removed and that no valves are vented to atmosphere.
E.
Place the Instrument Air System in service to all instruments and check the action of controllers and control valves.
F.
Place all of the instrument air purges in service.
G.
Turn on the steam supplies to all of the steam-jacketed sulfur vapor valves and use the vent valves on each jacket section to vent the air from the jackets. Manually "stroke" each valve and check to be sure it moves freely.
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12.7.2
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
Shutdown System Check-out A.
Fill the Thermal Oxidizer Waste Heat Boiler with treated boiler feed water up to the high level alarm point. As the level is rising, check the level transmitters and the high level alarms for proper operation.
B.
Use the quick-opening blowdown valve to lower the water level in the boiler and check for proper operation of the level transmitters, the low level alarms, and the low-low level shutdowns.
C.
Fill the boiler with treated boiler feed water back up to the normal liquid level. NOTE:
Issued 30 August 2011
The Thermal Oxidizer Waste Heat Boiler vendor recommends performing a "boil-out" with an aqueous alkaline solution during the initial startup to remove oil, grease, dirt, and biological material from the boiler drums and tubes. For this "boil-out" during the initial startup, the recommended chemical solution can be added to the boiler drum at this time as boiler feed water is added to bring the level back to the normal level points. Refer to the vendor's literature for the chemicals to be used. The "boil-out" can be performed during the refractory cure-out.
D.
Physically check all shutdown activating devices to ensure that they activate the TTO ESD system.
E.
Check all devices activated by the TTO ESD system to ensure that they operate properly.
F.
Check all relief valves to ensure that they are installed in the proper locations and set for the correct relieving pressures.
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Operating Guidelines Fall 2011
12.7.3
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
Commissioning Fuel Gas, Pilot Gas, and I/A to the Process The fuel gas, pilot gas (vaporized C4 LPG), and instrument air supplies to the process side of the Thermal Oxidizer must be made ready for use prior to starting up the Thermal Oxidizer using the procedures in these guidelines. This requires blowing down each section of piping to ensure that there are no liquids and/or construction debris in the headers and supply lines. The procedure below can be used to make sure that these gas utility systems are ready for service.
Issued 30 August 2011
A.
Select local manual control for the main fuel gas control valve by switching the hand switch in the DCS to "local".
B.
Set the manual fuel gas control on the local TTO control panel to 0% output.
C.
Confirm that the following fuel gas, pilot gas, and instrument air valves are closed: (1)
The manual block valve(s) in the main fuel gas supply line.
(2)
The manual block valve(s) in the main pilot gas supply line.
(3)
The main fuel gas automated block valves, the fuel gas control valve, and the block valve at the burner in the main fuel gas line to the Thermal Oxidizer Burner.
(4)
The manual block valve(s), and the two automated block valves in the pilot gas supply line to the pilot.
(5)
The block valve(s) in the main instrument air supply line.
(6)
The manual block valves and the automated block valve in the air supply line to the pilot.
(7)
The manual block valve in the air supply line to the purges for the burner instruments.
(8)
The block valves in the purge lines to the burner instruments.
D.
Confirm that all of the manual vent/drain valves in the main fuel gas, pilot gas, pilot air, and purge air piping are closed.
E.
If the orifice plate has already been installed in the fuel gas flow meter, remove it for now.
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Operating Guidelines Fall 2011
F.
G.
H.
I.
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK Disconnect the fuel gas, pilot gas, and instrument air from the burner system by performing the following steps: (1)
Unbolt the flanged connection at the burner in the main fuel gas supply line.
(2)
Disconnect the pilot gas supply tubing where it connects to the pilot.
(3)
Disconnect the instrument air supply tubing where it connects to the pilot.
(4)
Cover the open ends of these connections on the burner to prevent debris from entering when the upstream piping is blown down.
Remove the following pressure regulators, then cover the downstream piping to prevent debris from entering when the upstream piping is blown down: (1)
The main fuel gas supply regulator.
(2)
The pilot instrument air supply regulator.
(3)
The pilot gas supply regulator.
(4)
The purge instrument air supply regulator.
"Force" the PLC to open the following valves, then confirm they are open: (1)
The automated block valves in the main fuel gas supply line to the burner.
(2)
The automated block valves in the pilot gas supply line to the pilot.
(3)
The automated block valve in the instrument air supply line to the pilot.
"Force" the PLC to close the following valves, then confirm they are closed: (1)
Issued 30 August 2011
The automated vent valve on the main fuel gas supply line to the burner.
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK (2)
Issued 30 August 2011
The automated vent valve on the pilot gas supply line to the pilot.
J.
"Crack" the manual block valve in the main fuel gas supply line (upstream of the pressure regulator) and allow fuel gas to blow through the piping until it is clear. Then close the block valve, reinstall the main fuel gas supply pressure regulator, and reopen the gate valve.
K.
Using the pressure gauge and the vent valve downstream of the main fuel gas supply regulator, adjust the main fuel gas regulator to its specified setpoint.
L.
Use the manual fuel gas controller on the local control panel to fully open the control valve in the main fuel gas line, then use the downstream drain valve to blow out this section of piping. Close the drain valve when the piping is clear, then close the control valve.
M.
Open the bypass valve around the main fuel gas control valve. "Crack" the block valve at the burner and allow fuel gas to blow through the piping until it is clear. Then close the block valve and bypass valve.
N.
"Crack" the block valve in the main pilot gas supply line to the pilot (upstream of the pressure regulator) and allow pilot gas to blow through the piping until it is clear. Then close the block valve, reinstall the pilot gas supply pressure regulator, and reopen the block valve.
O.
Using the pressure gauge and the vent valve downstream of the pilot gas supply regulator, adjust the regulator to its specified setpoint.
P.
"Crack" the block valve downstream of two automated block valves and allow pilot gas to blow through the piping until it is clear. Then close the block valve.
Q.
"Crack" the block valve in the instrument air supply line to the pilot and blow air through the piping until it is clear. Then close the block valve, reinstall the pilot instrument air supply pressure regulator, and reopen the block valve.
R.
Using the pressure gauge and the vent valve downstream of the pilot instrument air supply regulator, adjust the regulator to its specified setpoint.
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Operating Guidelines Fall 2011
Issued 30 August 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
S.
"Crack" the block valve downstream of the pilot air supply automated block valve and allow instrument air to blow through the piping until it is clear. Then close the block valve.
T.
Remove the "forces" from the PLC and confirm that all of the automated block valves close and all of the automated vent valves open.
U.
Close the block valve in the main fuel gas supply line (upstream of the regulator), the block valve in the pilot gas supply to the pilot (upstream of the regulator), and the block valve in the instrument air supply to the pilot (upstream of the regulator) until the TTO is ready for startup.
V.
Reconnect the fuel gas, pilot gas, and instrument air to the burner systems by performing the following steps: (1)
Bolt the flanged connection at the burner in the main fuel gas supply line back together.
(2)
Reinstall the pilot gas supply tubing where it connects to the pilot.
(3)
Reinstall the instrument air supply tubing where it connects to the pilot.
(4)
Reinstall the orifice plate in the fuel gas flow meter.
W.
"Crack" the block valve in the instrument air supply line to the purge rotameters (upstream of the purge pressure regulator) and blow air through the piping until it is clear. Then close the block valve, reinstall the purge instrument air supply pressure regulator, and reopen the block valve.
X.
Using the pressure gauge and the downstream drain valve, adjust the purge instrument air regulator to its specified setpoint.
Y.
Open the drain valve to blow out this section of piping until it is clear, then close the drain valve.
Z.
Each of the low pressure purges for the burner instruments has a rotameter near where it connects to the process. Disconnect the upstream fitting at each rotameter and open its upstream ball valve briefly to blow any liquids or debris from the purge line. Reconnect each rotameter, disconnect the fitting where each purge enters the
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK process, open its upstream ball valve, and open its needle valve briefly to blow any liquids or debris from the purge line. Then reconnect each purge to the process and open its needle valve to place it in service.
Issued 30 August 2011
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
12.8 Startup Procedures The procedure used to start up the Thermal Oxidizer depends on whether the refractory in the Thermal Oxidizer is up to operating temperature. This first section describes the procedure for the initial startup of a new plant, and subsequent startups when the refractory is cold (less than 500°C in the Thermal Oxidizer). Subsequent startups with the refractory already up to operating temperature can use a different procedure, discussed later in Section 12.8.2 of these guidelines.
12.8.1
Initial Firing / Refractory Cure-out During the initial startup, the Thermal Oxidizer and downstream equipment will be warmed up to operating conditions following the initial refractory cure-out schedule for the Thermal Oxidizer. This cure-out schedule should be provided by the refractory vendor.
CAUTION
IT IS CRITICAL THAT THE WARMUP PROCEDURES BE FOLLOWED VERY CLOSELY. THE REFRACTORY MATERIAL MUST BE HEATED SLOWLY TO ALLOW THE CONTAINED WATER TO VAPORIZE AND ESCAPE FROM THE REFRACTORY LINING, WITHOUT EXERTING EXCESSIVE INTERNAL PRESSURE AND CAUSING LINING DAMAGE.
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12.8.1.1
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK Initial Preparations A.
Check that all devices in the TTO ESD have been satisfied, except for the following: (1)
Low-low air flow.
(2)
Neither blower running.
(3)
Flame failure.
The PLC logic provides bypasses for these three conditions so that the system can be started up.
Issued 30 August 2011
B.
Select local manual control for the air flow control valve by switching the hand switch in the DCS to "local".
C.
Place the air flow controller in "automatic".
D.
Select local manual control for the fuel gas control valve by switching the hand switch in the DCS to "local".
E.
Place the Thermal "automatic".
F.
"Toggle" the superheated steam hand switch in the DCS to give the blow-off pressure controller control of the superheater pressure via the steam blow-off control valve.
G.
Place the blow-off pressure controller in "manual" and set its output to 100% to fully open the steam blow-off control valve.
H.
Place the Thermal Oxidizer Waste Heat Boiler steam pressure controller in "automatic" and adjust its setpoint to 0.7 kg/cm2(g) (or whatever value the boiler manufacturer recommends) in preparation for "boil-out".
I.
Adjust the output from the temperature controller for the interstage desuperheater, to 0%. Switch the controller to "automatic" and adjust its setpoint to its normal value.
J.
Adjust the output from the temperature controller for the discharge desuperheater, to 0%. Switch the controller to "automatic" and adjust its setpoint to its normal value.
K.
Confirm that the Thermal Oxidizer Waste Heat Boiler is filled with water up to its normal liquid level.
Oxidizer
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temperature
controller
in
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK L.
Confirm that the superheated steam blow-off control valve is fully open.
M.
Confirm that the two desuperheater BFW supply control valves, and their bypass valves are closed. Confirm that the upstream and downstream block valves around the control valves are open.
N.
Open the vent valves on the boiler to vent air from the steam section.
O.
Set the manual fuel gas control on the local TTO control panel to 0% output. Visually confirm that the main fuel gas valve, its bypass valve, and the two main fuel gas shutdown valves are closed.
P.
Set the manual air control on the local TTO control panel to 0% output. Visually confirm that the air flow control valve is closed.
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12.8.1.2
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK Igniting the Pilot Burner A.
Switch the Startup/Run selector switch on the local TTO control panel to "STARTUP". The PLC should perform the following actions: (1)
The TTO bypass valve is opened. The "BYPASS OPEN" status light on the local TTO control panel will flash until the valve has moved to the proper position, then remain steadily illuminated.
(2)
The TTO inlet valve is closed. The "INLET OPEN" status light will flash until the valve has moved to the proper position, then will be extinguished.
NOTE:
If a status light continues to flash, it means that the limit switches on the associated valve never confirmed that the valve moved to the proper position. If this occurs, the startup sequence will not be allowed to proceed until the problem is corrected and the valve moves to the proper position. Note that the valve may have actually moved to the proper position, but a faulty limit switch may not be detecting that the valve is in the proper position.
Confirm that these valves have moved to the proper positions. Confirm that the "BYPASS OPEN" light on the panel is illuminated, and that the "INLET OPEN" light on the panel is extinguished.
Issued 30 August 2011
B.
Verify that both of the local start/stop controls for the Thermal Oxidizer Air Blower have their selector switches turned to the "STOP" position.
C.
Verify that the discharge valves are closed on both air blowers.
D.
Start a Thermal Oxidizer Air Blower: (1)
Use the local start/stop control station to start the desired blower.
(2)
Once the blower comes up to speed, open its discharge valve.
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK E.
Once an air blower is running, press the "ESD RESET" push-button on the local TTO control panel to reset the TTO ESD and extinguish the "RESET REQUIRED" light. This will illuminate the "PURGE REQUIRED" light.
F.
Verify that the "LIMITS SATISFIED" light is glowing steadily (not flashing) on the local TTO control panel. NOTE: If the "LIMITS SATISFIED" light is flashing, this means that a limit switch is not satisfied. The limit switches on the main fuel gas valves and the TTO inlet valve must all indicate that their valves are closed. For safety reasons, the PLC will not allow the light-off sequence to proceed until these valves are proven closed. Once the problem with the valves or their limit switches has been corrected, the "LIMITS SATISFIED" light will stop flashing and glow steadily, and the light-off sequence can proceed.
G.
Adjust the output of the local manual air control to open the air flow control valve and allow a large air flow, 80% or more on the flow indicator, to purge the furnace and downstream equipment for 5 minutes. The "PURGE REQUIRED" light will be extinguished and the "PURGE COMPLETE" light will be illuminated after about 40 seconds, but continue to purge the system for a full 5 minutes prior to this first time ignition attempt.
H.
Open the following manual block valves:
I.
(1)
The block valves in the pilot gas to the ignitor/pilot.
(2)
The block valves in the air supply to the ignitor/pilot.
Adjust the output of the local manual air control to reduce the air flow on the flow indicator to 10-20%. This will extinguish the "PURGE COMPLETE" light and illuminate the "PERMIT TO IGNITE" light, and the PLC will "enable" the ignition circuit. NOTE: Once the "PERMIT TO IGNITE" light is illuminated, an ignition safety interlock timer starts. If an ignition attempt is not made within 5 minutes, the TTO ESD system will be activated to shut down the Thermal Oxidizer. This prevents a potentially unsafe condition
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK from persisting, where a leaking fuel gas valve could cause an explosive mixture to form in the Thermal Oxidizer, since the air flow is low at this point in the startup procedure. If either scanner detects a flame before the "PILOT ON" push-button is pressed, this will activate the TTO ESD system and the "flame scanner malfunction" alarm in the DCS. This will stop the air blower and extinguish the flame (unless of course, a flame scanner is giving a false indication). A flame prior to ignition usually indicates a leaking fuel gas valve. If this occurs, check these valves before proceeding with startup, as a leaking valve can allow an explosive mixture to form in the Thermal Oxidizer without warning. J.
Issued 30 August 2011
Press the "PILOT ON" push-button to initiate an ignition attempt. The PLC will do the following: (1)
The air purge valve for the pilot burner is closed.
(2)
The ignitor/pilot air block valve is opened.
(3)
The ignitor/pilot gas vent valve is closed and the block valves are opened.
(4)
The ignition system is energized to begin sparking the ignitor inside the pilot in a series of pulses.
(5)
The "PILOT ON" light is illuminated.
K.
The air and pilot gas pressure regulators for the ignitor may require some adjustment when first put in service before the ignitor will light the pilot. However, once set properly, the ignitor should ignite the pilot readily on subsequent startups. Refer to the SRU Section of these guidelines for a suggested procedure to adjust these regulators.
L.
If neither flame scanner detects a flame after 15 seconds of sparking the ignitor, the ignition try is aborted, the TTO Burner Shutdown system is activated, and the PLC causes the sequence to return to Step G.
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK M.
Issued 30 August 2011
When either of the flame scanners detects a flame from the pilot burner, the appropriate "FLAME PROVEN" light(s) are illuminated. The pilot air and pilot gas valves will remain open after the ignition trial, and the PLC will perform the following activities: (1)
The "LIMITS SATISFIED" and "PERMIT TO IGNITE" lights are extinguished.
(2)
The "PILOT ON" light remains illuminated.
(3)
The ignition system is de-energized.
(4)
The startup bypass in the PLC for the "flame failure" S/D is disabled.
(5)
The "MAIN FUEL START" push-button on the local TTO control panel is enabled.
(6)
The "RUN" position on the Startup/Run selector switch on the local TTO control panel is enabled.
N.
After the pilot is lit, use the local manual air control to increase the air flow rate to about 50%, or as high a rate as can be maintained without blowing the pilot out. When curing refractory, it is best to keep the air flow as high as possible to help distribute the heat more evenly and to heat the downstream equipment more quickly.
O.
The heat input from the pilot should be sufficient to reach the first "hold" point in the refractory warmup schedule, 100-150°C. If the temperature is too high, increase the air flow rate. If the temperature is too low, decrease the air flow rate.
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12.8.1.3
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK Thermal Oxidizer Waste Heat Boiler "Boil-Out" The Thermal Oxidizer WHB vendor recommends performing a "boil-out" with an aqueous alkaline solution during the initial startup to remove oil, grease, dirt, and biological material from the boiler drum and tubes. This boiler "boil-out" can be performed in conjunction with the refractory cure-out of the Thermal Oxidizer. Refer to the vendor's literature for the specific procedure to be used. During "boil-out", the steam produced in the steam drum of the Thermal Oxidizer Waste Heat Boiler will flow through the superheater pass of the boiler and then be vented to atmosphere through the steam blow-off valve. Note that if the SRU(s) is being warmed up at the same time, any high pressure steam being produced by its Waste Heat Boiler will also be flowing through the superheater pass of the Thermal Oxidizer Waste Heat Boiler. Depending on the firing rate in the SRU(s), the steam flow may become too high to maintain the desired pressure in the Thermal Oxidizer Waste Heat Boiler steam drum (usually 0.7-1.0 kg/cm2(g)) even with the blow-off valve fully open. If this is the case, the firing rate will have to be reduced in the SRU(s) to reduce the steam production until "boil-out" of the Thermal Oxidizer Waste Heat Boiler is completed. Once "boil-out" has been completed, the steam pressure in the steam drum can be raised to its normal operating pressure. Confirm that WHB steam pressure control is in "automatic", then adjust its setpoint to its normal setting. Then place the steam pressure controller in control by confirming that its setpoint is tracking the current reading and switching the controller to "automatic". Slowly adjust its setpoint to its normal setting.
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12.8.1.4
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK Igniting the Main Gas Burner, Refractory Cure-out and Warmup When the firing rate needs to be increased to raise the furnace temperature, the main gas burner can be placed in service. The local manual control has control of the main fuel gas valve at this time because the hand switch in the DCS is switched to "local". The fuel gas flow rate can be monitored using the flow indicator on the local TTO control panel and the flow indicator in the DCS. A.
Verify that the hand switch in the DCS is set to "local" to give local manual control of the fuel gas control valve.
B.
Confirm that the output from the manual fuel gas control on the local TTO control panel is set to 0%, that the fuel gas control valve and its bypass valve are closed, and that the two block valves at the control station are both open.
C.
Open the manual block valve in the main fuel gas line and the manual block valve at the burner.
D.
If the air flow rate is not at least 50%, use the local manual air control to set the air flow at 50% as indicated by the flow indicator.
E.
Press the "MAIN FUEL START" push-button on the local TTO control panel, to commission the main fuel gas. The PLC performs the following actions: (1)
The main fuel gas vent valve is closed.
(2)
The main fuel gas automated block valves are opened.
(3)
The fuel gas control valve is released to operator control.
(4)
The "MAIN FUEL ON" light on the local TTO control panel is illuminated.
(5)
A 2-minute low-low air flow S/D bypass timer is started.
NOTE: Be sure the air flow is above the low-low flow shutdown point, about 20% on the flow indicator, or the TTO ESD will be activated when the bypass timer expires and the Thermal Oxidizer will shut down. F.
Issued 30 August 2011
Use the manual fuel gas control on the local TTO control panel to slowly open the fuel gas control valve until the burner lights
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK and has a stable flame. The "minimum fire" setting required for this particular burner at the normal air flow will be determined later. G.
The manual fuel gas control may now be used to manually control the furnace temperature. Make adjustments to the output as needed to follow the appropriate refractory cure-out or warmup schedule (from the refractory vendor), either the chart for the initial cure-out or the chart for normal warmup. The temperature of the Thermal Oxidizer is indicated on the local panel by a temperature indicator. The temperature is also indicated by the temperature control in the DCS, which can be used to monitor or control the warmup of the Thermal Oxidizer in the DCS. It is often helpful to maintain a log of air flow using the flow indicator on the local panel or the air flow controller in the DCS, fuel gas flow using the flow indicator on the local panel or the flow indicator in the DCS, and furnace temperature using a temperature indicator on the local panel or the temperature control in the DCS during the cure-out for future reference. NOTE: During the early stages of warmup when the furnace temperature is supposed to be low, the fuel gas flow rate may be too high with the control valve at its "minimum fire" position. If this is the case, use the local manual air control to raise the air flow in order to control the furnace temperature at the proper value.
H.
As the firing rate increases, raise the air flow rate with the local manual air control to 75%-80% as indicated by the flow indicator.
I.
Once the main fuel gas burner in the Thermal Oxidizer Burner is operating smoothly, the pilot burner can be shut down and retracted or extracted. For the initial startup of the Thermal Oxidizer, this step should be performed after the "minimum fire" setting for DCS the fuel gas control valve relay has been determined. Press the "PILOT STOP" push-button on the local TTO control panel. The PLC performs the following actions to block the pilot air and "double block and bleed" the pilot gas:
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK (1)
The automated block valve in the air supply to the ignitor/pilot is closed.
(2)
The ignitor/pilot pilot gas automated block valves are closed.
(3)
The pilot gas vent valve is opened.
(4)
The air purge valve for the pilot burner is opened.
(5)
The "PILOT ON" light is extinguished.
Verify that the air and pilot gas valves have moved to their proper positions and that the pilot burner is being purged with air as indicated by the rotameter. J.
K.
Close the following manual block valves: (1)
The manual block valves in the pilot gas supply to the ignitor/pilot.
(2)
The manual block valves in the air supply to the ignitor/pilot.
Loosen the packing gland on the pilot and retract or extract the pilot assembly: (1)
(2)
Issued 30 August 2011
If the pilot is just to be retracted: (a)
Retract it until it reaches the limit of the retraction bar.
(b)
Tighten the packing gland on the pilot.
(c)
Confirm that the pilot is still being purged with air as indicated by the air flow rotameter.
If the pilot is to be completely extracted: (a)
Retract it until the retaining chain is taut.
(b)
Close the block valve at the burner to isolate the pilot from the furnace.
(c)
Close the block valve in the purge air to the pilot burner.
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK CAUTION: THE PILOT ASSEMBLY WILL BE VERY HOT. HANDLE IT CAREFULLY TO AVOID BURNS AND TO AVOID DAMAGING IT. (d)
(3)
Disconnect the chain and remove the pilot assembly and store it in a safe place.
Verify that the pilot burner mounting nozzle is still being purged with air as indicated by the rotameter.
L.
Frequently confirm that the proper water level is maintained in the Thermal Oxidizer Waste Heat Boiler. Confirm that the level control system is functioning properly.
M.
As steam pressure starts to build in the Thermal Oxidizer Waste Heat Boiler, confirm that the boiler pressure controller in the DCS is in "automatic" and controlling the steam pressure at its setpoint. Allow the vent valves to sweep non-condensibles out of the steam spaces on the boiler.
N.
Confirm that the superheater pass pressure controller in the DCS is in "automatic" with the proper setpoint. At this time, the steam pressure "toggle" switch in the DCS has not yet been reset, so the steam leaving the superheater pass is still being vented to atmosphere through the silencer.
Issued 30 August 2011
O.
Confirm that the interstage desuperheater temperature controller and the discharge despuerheater temperature controller in the DCS are in "automatic".
P.
As the equipment and piping heat up, inspect all of the equipment and piping for the effects of thermal expansion. Ensure that all slide plates, rollers, spring hangers, etc. are functioning properly.
Q.
As the steam pressure builds in the boiler, the vent valves on the steam sections may be closed.
R.
As the superheated steam temperature begins to increase, confirm that the temperature controllers on the desuperheaters
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK are adding BFW as needed to prevent excessive temperatures around the superheat passes of the boiler. S.
T.
Issued 30 August 2011
Switch the combustion air flow control from the local TTO control panel to the DCS as follows: (1)
Confirm that the air flow controller in the DCS is in "automatic", its output is tracking the output from the manual air control on the local TTO control panel as indicated by the hand indicator in the DCS, and its setpoint is tracking its current reading.
(2)
Switch the air flow control hand switch from "local" to "remote". The air flow controller now has control of the air flow control valve, and will be controlling the air flow rate with its last value as the setpoint.
(3)
Slowly adjust the setpoint of the air flow controller to its normal value.
Switch the temperature control of the Thermal Oxidizer from the local TTO control panel to the DCS as follows: (1)
Confirm that the temperature control in the DCS is in "automatic", its output is tracking the output of the manual fuel gas control on the local TTO control panel as indicated by the hand indicator in the DCS, and its setpoint is tracking its current reading.
(2)
Switch the temperature hand switch from "local" to "remote". The temperature control now has control of the fuel gas control valve, and will be controlling the temperature with its last value as the setpoint.
U.
Adjust the setpoint of the temperature controller as necessary so that the Thermal Oxidizer continues to follow the appropriate refractory cure-out or warmup schedule.
V.
When the temperature of the superheated steam leaving the superheater pass of the Thermal Oxidizer Waste Heat Boiler reaches the proper value and is under control, the high pressure steam can be directed to the export header. After confirming that the steam header is ready to accept steam, "toggle" the reset permit switch in the DCS.
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK The relay in the DCS will begin ramping down the output to the steam blow-off valve. As the valve closes, the pressure in the steam header will begin to increase until it is high enough to open the check valve and the steam begins flowing to the export header. Confirm that the blow-off valve closes fully. W.
Issued 30 August 2011
At the conclusion of the refractory cure-out during the initial startup, the "minimum fire" setting for the burner needs to be determined: (1)
Adjust the output of the manual fuel gas flow control on the local TTO control panel so that the reading displayed on the hand indicator in the DCS matches the current output from the temperature control.
(2)
Switch the hand switch in the DCS from "remote" to "local".
(3)
While observing the flame through one of the viewports on the burner, slowly reduce the fuel gas flowrate by reducing the output of the manual fuel gas control until the flame starts to become unstable.
(4)
Raise the fuel gas flowrate back up slightly using the manual fuel gas control until the flame is stable again.
(5)
This is the actual "minimum fire" setting required for this particular burner. Record the fuel gas flowrate on the flow indicator in the DCS and the output on the manual fuel gas control on the local TTO control panel.
(6)
Use the manual fuel gas control to raise the fuel gas flowrate back up to the value before starting this step. Confirm that the temperature control is still in "automatic" and its output is tracking the manual fuel gas control, then switch the hand switch back to "remote" and adjust the setpoint of the temperature control to its normal setpoint.
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12.8.1.5
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK Routing SRU/TGCU Tailgas to the Thermal Oxidizer A.
When the Thermal Oxidizer temperature reaches 816°C, the TTO is ready to be placed in service. Switch the Startup/Run selector switch on the local TTO control panel to "RUN". The PLC will perform the following actions: (1)
The TTO inlet valve is opened.
(2)
After the limit switches prove this valve open, the TTO bypass valve is closed.
Confirm that these valves have moved to the proper positions. Confirm that the "INLET OPEN" light on the panel is illuminated, and the "BYPASS OPEN" light on the panel is extinguished. B.
Issued 30 August 2011
The Thermal Oxidizer is now on-stream, ready to incinerate SRU tailgas or TGCU effluent. Before directing your attention away from the Thermal Oxidizer, be sure that: (1)
The Thermal Oxidizer is operating smoothly, with both the combustion air and fuel gas on automatic control.
(2)
The Thermal Oxidizer Waste Heat Boiler level, pressure, and steam temperature controls are functioning properly.
(3)
The stack gas analyzers are performing satisfactorily.
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12.8.2
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
Normal Startup The procedure for startup of the unit after it has been shut down for a short period, not long enough to get cold (less than about 500°C in the Thermal Oxidizer), will be very similar to the procedure for the initial startup, Section 12.8.1 of these guidelines. However, the steps to be performed are written in this Section to serve as a "check list" that can be easily followed on subsequent startups. Refer to the previous Section for the reasons and details pertaining to the different steps performed.
WARNING THE THERMAL OXIDIZER MAY BE SAFELY RESTARTED WHILE THE SRUS ARE RUNNING (WITH OR WITHOUT THE TGCU ON-LINE) BECAUSE THE TTO FEED GAS IS BYPASSED AROUND THE THERMAL OXIDIZER DURING STARTUP. HOWEVER, IF THE FEED GAS TO THE TTO CONTAINS AN EXCESSIVE AMOUNT OF COMBUSTIBLES, THE THERMAL OXIDIZER WILL SHUT DOWN ON HIGH-HIGH FURNACE TEMPERATURE WHEN THE TTO INLET VALVE IS OPENED. THE MAJOR COMBUSTIBLE THAT MAY EXIST IN THE TTO FEED GAS IS H2S, ESPECIALLY IF THE SULFUR PLANT IS UPSET AND RUNNING WITH DEFICIENT AIR, OR THE TGCU IS UPSET AND ALLOWING H2S TO "SLIP". THIS WOULD BE INDICATED BY LOW AIR DEMAND ON THE AIR DEMAND CONTROLLER IN THE DCS, AND/OR HIGH H2S ON THE TGCU H2S ANALYZER IF THE TGCU IS OPERATING. HOWEVER, IF EITHER ANALYZER IS OUT OF SERVICE OR IF THERE IS ANY REASON TO SUSPECT HIGH H2S IN THE TTO FEED GAS, THE FEED GAS SHOULD BE TESTED FOR H2S TO DETERMINE WHETHER IT IS SAFE TO RESTART THE TTO. GAS DETECTOR TUBES (DRÄGER TUBES, ETC.) MAY BE USED TO SAMPLE THE TTO FEED GAS. REFER TO THE LABORATORY PROCEDURES GIVEN IN THESE GUIDELINES.
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
IF THE AIR DEMAND IN THE SRU(S) IS LOW (BELOW –3.0%) OR THE H2S CONCENTRATION IN THE FEED GAS TO THE THERMAL OXIDIZER IS HIGH (ABOVE 3%), DO NOT ATTEMPT TO RESTART THE TTO. INSTEAD, DIRECT YOUR ATTENTION TO THE AMINE OR SWS UNIT(S) UPSTREAM OF THE SRUS (WHICH ARE PROBABLY CAUSING THE PROBLEM) AND BRING THE SRU(S) BACK ON-RATIO, OR CORRECT THE OPERATING PROBLEM IN THE TGCU. THIS WILL REDUCE THE CONCENTRATION OF H2S IN THE TTO FEED GAS TO AN ACCEPTABLE LEVEL, SO THAT RESTARTING THE THERMAL OXIDIZER PROCEEDS SMOOTHLY. FAILURE TO CORRECT THE UPSTREAM PROBLEM(S) FIRST WILL LIKELY LEAD TO THE THERMAL OXIDIZER SHUTTING DOWN AGAIN, REQUIRING ANOTHER RESTART OF THE TTO. Prior to commencing Thermal Oxidizer startup:
Issued 30 August 2011
1.
Check for the completion of all maintenance work (connecting lines, removing blinds, etc.) if such work was performed.
2.
Place all steam heating systems in service. Check all steam traps for proper operation, and use the vent valves to sweep non-condensibles out of the steam spaces.
3.
Physically check all shutdown-activating devices to ensure that they activate the TTO ESD system.
4.
Physically check all devices activated by the TTO ESD system to ensure that they operate properly.
5.
Confirm that the Thermal Oxidizer Waste Heat Boiler is filled with water up to its normal liquid level.
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12.8.2.1
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK Initial Preparations A.
Check that all devices on the TTO ESD have been satisfied, except for the following: (1)
Low-low air flow.
(2)
Neither blower running.
(3)
Flame failure.
B.
Select local manual control for the air flow control valve by switching the hand switch in the DCS to "local".
C.
Place the air flow controller in "automatic".
D.
Select local manual control for the fuel gas control valve by switching the hand switch in the DCS to "local".
E.
Place the Thermal "automatic".
F.
Confirm that the following controllers are in "automatic" with their setpoints:
G.
Oxidizer
temperature
controller
in
(1)
The Thermal Oxidizer Waste Heat Boiler steam pressure controller.
(2)
The Thermal Oxidizer Waste Heat Boiler superheater pressure controller.
(3)
The interstage desuperheater temperature controller.
(4)
The export steam temperature controller.
Set the manual fuel gas control on the local TTO control panel to 0% output. Visually confirm that the main fuel gas valve and its bypass valve are closed.
H.
Set the manual air control on the local control panel to 0% output. Visually confirm that the air flow control valve is closed.
I.
Prepare the pilot burner for service: (1)
Issued 30 August 2011
If the pilot is in the retracted position:
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
(2)
Issued 30 August 2011
(a)
Loosen the packing gland on the pilot.
(b)
Slide the pilot forward until it reaches the limit of the retraction bar.
If the pilot was extracted earlier: (a)
Insert the pilot assembly into its packing gland and open the block valve at the furnace.
(b)
Slide the pilot assembly forward until it reaches the limit of the retraction bar.
(c)
Reconnect the retaining chain.
(d)
Open the block valve in the purge air to the pilot and confirm that the pilot is now being purged with air.
(3)
Tighten the packing gland on the pilot.
(4)
Verify that the pilot burner mounting nozzle is still being purged with air.
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12.8.2.2
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK Igniting the Pilot Burner A.
Switch the Startup/Run selector switch on the local TTO control panel to "STARTUP". The PLC will open the TTO bypass valve and close the TTO inlet valve. Verify that the "BYPASS OPEN" light on the panel is now illuminated and the "INLET OPEN" light on the panel is extinguished. NOTE:
If a status light continues to flash, it means that the limit switches on the associated valve never confirmed that the valve moved to the proper position. If this occurs, the startup sequence will not be allowed to proceed until the problem is corrected and the valve moves to the proper position.
B.
Verify that the local start/stop controls for the blowers have their selector switches turned to the "STOP" position.
C.
Verify that the discharge valves are closed on both air blowers.
D.
Start a Thermal Oxidizer Air Blower: (1)
Use the local start/stop control station to start the desired blower.
(2)
Once the blower comes up to speed, open its discharge valve.
E.
Once an air blower is running, press the "ESD RESET" push-button on the local TTO control panel to reset the TTO ESD and extinguish the "RESET REQUIRED" light. This will illuminate the "PURGE REQUIRED" light.
F.
Verify that the "LIMITS SATISFIED" light is glowing steadily (not flashing) on the local TTO control panel. NOTE:
If the "LIMITS SATISFIED" light is flashing, this means that a limit switch is not indicating that the fuel gas valves and the TTO inlet valve are all closed. For safety reasons, the PLC will not allow the light-off sequence to proceed until these valves are proven closed. Once the problem with the valves or their
Issued 30 August 2011
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK limit switches has been corrected, the "LIMITS SATISFIED" light will stop flashing and glow steadily, and the light-off sequence can proceed. G.
Open the following manual block valves: (1)
The manual block valves in the pilot gas to the ignitor/pilot.
(2)
The block valves in the air supply to the ignitor/pilot.
H.
Adjust the output of the local manual air control to open the air flow control valve and allow a large air flow, 80% or more on the flow indicator, to purge the furnace for 40 seconds and extinguish the "PURGE REQUIRED" light. The "PURGE COMPLETE" light will then be illuminated.
I.
Adjust the output of the local manual air control to reduce the air flow on the flow indicator to 10-20%. This will extinguish the "PURGE COMPLETE" light and illuminate the "PERMIT TO IGNITE" light. NOTE: Remember that the ignition safety timer will shut down the Thermal Oxidizer if an ignition attempt is not made within 5 minutes of receiving the "PERMIT TO IGNITE".
Issued 30 August 2011
J.
Press the "PILOT ON" push-button to initiate an ignition attempt.
K.
If neither flame scanner detects a flame after 15 seconds of sparking the ignitor, the ignition try is aborted, the TTO Burner Shutdown system is activated, and the PLC causes the sequence to return to Step H.
L.
When either of the flame scanners detects a flame from the pilot burner, the pilot air and natural gas valves will remain open and the PLC will enable the "MAIN FUEL START" switch on the local TTO control panel.
M.
Adjust the output of the local manual air control to increase the air flow on the flow indicator to at least 50%.
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12.8.2.3
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK Igniting the Main Gas Burner A.
Confirm that the output from the manual fuel gas control on the local TTO control panel is set to 0%, that the fuel gas control valve and its bypass valve are closed, that the block valves at the control station are both open, and that the manual block valves in the main fuel gas line and the block valve at the burner are open.
B.
If the air flow rate is not at least 50%, use the local manual air control to set the air flow at 50% as indicated by the flow indicator.
C.
Press the "MAIN FUEL START" push-button on the local TTO control panel to open the main fuel gas block valves. NOTE: Be sure the air flow is above the low-low flow shutdown point, about 20% on the flow indicator, or the TTO ESD will be activated when the bypass timer expires and the Thermal Oxidizer will shut down. (This timer begins running when the "MAIN FUEL START" push-button is pressed, and has a 2 minute duration.)
Issued 30 August 2011
D.
Use the manual fuel gas control to increase the firing rate and bring the Thermal Oxidizer back to its normal operating temperature.
E.
As the firing rate increases, raise the air flow rate with the local manual air control to 75%-80% as indicated by the flow indicator.
F.
Press the "PILOT STOP" push-button on the local TTO control panel to block the pilot air and to "double block and bleed" the pilot gas. Verify that the "PILOT ON" light is extinguished.
G.
Close the following manual block valves: (1)
The manual block valves in the pilot gas to the pilot.
(2)
The manual block valves in the air supply to the pilot.
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK H.
Loosen the packing gland on the pilot and retract or extract the pilot assembly: (1)
(2)
If the pilot is just to be retracted: (a)
Retract it until it reaches the limit of the retraction bar.
(b)
Tighten the packing gland on the pilot.
(c)
Confirm that the pilot is still being purged with air.
If the pilot is to be completely extracted: (a)
Retract it until the retaining chain is taut.
(b)
Close the block valve at the furnace to isolate the pilot from the furnace.
(c)
Close the block valve in the purge air to the pilot burner. CAUTION: THE PILOT ASSEMBLY WILL BE VERY HOT. HANDLE IT CAREFULLY TO AVOID BURNS AND TO AVOID DAMAGING IT.
(d)
(3)
Verify that the pilot burner mounting nozzle is still being purged with air.
I.
Confirm that the Thermal Oxidizer Waste Heat Boiler steam pressure controller is in "automatic" and is controlling the steam pressure properly.
J.
Confirm that the superheated steam temperature controllers are in "automatic" and are controlling the steam temperature properly.
K.
Switch the combustion air flow control from the local TTO control panel to the DCS as follows: (1)
Issued 30 August 2011
Disconnect the chain and remove the pilot assembly and store it in a safe place.
Confirm that the air flow controller in the DCS is in "automatic", its output is tracking the output from the
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK manual air control on the local TTO control panel, and its setpoint is tracking its current value.
L.
Issued 30 August 2011
(2)
Switch the air flow control hand switch from "local" to "remote". The air flow controller now has control of the air flow control valve, and will be controlling the air flow rate with its last value as the setpoint.
(3)
Slowly adjust the setpoint of the air flow controller to its normal value.
Switch the temperature control of the Thermal Oxidizer from the local TTO control panel to the DCS as follows: (1)
Confirm that the temperature control in the DCS is in "automatic", its output is tracking the output of the manual fuel gas control on the local TTO control panel, and its setpoint is tracking its current value.
(2)
Switch the hand switch from "local" to "remote". The temperature control now has control of the fuel gas control valve, and will be controlling the temperature with its last value as the setpoint.
(3)
Slowly adjust the setpoint of the temperature control to its normal value.
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12.8.2.4
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK Routing SRU/TGCU Tailgas to the Thermal Oxidizer A.
When the Thermal Oxidizer temperature reaches 816°C, the TTO is ready to be placed in service. Switch the Startup/Run selector switch on the local TTO control panel to "RUN". The PLC will open the TTO inlet valve, then close the TTO bypass valve. The "INLET OPEN" light will be illuminated, then the "BYPASS OPEN" light will be extinguished as the valves move to their new positions.
Issued 30 August 2011
B.
If the temperature of the superheated steam leaving the superheater pass of the Thermal Oxidizer Waste Heat Boiler fell low enough to activate the low-low temperature interlock while the Thermal Oxidizer was being restarted, the steam will be venting to atmosphere at this time. After confirming that the steam temperature is under control at the proper value and the steam header is ready to accept steam, "toggle" the steam reset permit switch in the DCS to slowly close the steam blow-off valve and send the steam to the export header.
C.
The Thermal Oxidizer is back on-stream, incinerating SRU tailgas or TGCU effluent. Before directing your attention away from the Thermal Oxidizer, be sure that: (1)
The Thermal Oxidizer is operating smoothly, with both the combustion air and fuel gas on automatic control.
(2)
The Thermal Oxidizer Waste Heat Boiler level, pressure, and steam temperature controls are functioning properly.
(3)
The stack gas analyzers are performing satisfactorily.
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
12.9 Shutdown Procedures The procedures to be used in performing a planned shutdown of the Thermal Oxidizer will vary depending on the extent and type of work to be performed in and around the TTO during the downtime period. If there are no plans for entering the TTO equipment, no special procedures are required in performing the shutdown. Section 12.9.1 that follows is an example of such a procedure. However, if you plan to enter any vessels for inspection or maintenance, then more extensive and lengthy procedures must be followed to accomplish a satisfactory shutdown and minimize the time required for performance of the desired maintenance work. Section 12.9.2 that follows is an example of a procedure for this circumstance. One special circumstance that may exist during a shutdown is to have tube leaks in the Thermal Oxidizer Waste Heat Boiler. This special case is discussed in Section 12.9.3. Section 12.9.4 is a discussion of emergency shutdown situations. A guide to troubleshooting the causes of unplanned shutdowns is presented to assist in quickly identifying and correcting the problem so the Thermal Oxidizer can be put back on-line in a minimum amount of time. The TTO is affected directly and indirectly by shutdowns and outages that occur in other systems both within the Sulfur Block and outside the battery limits. The more important aspects of the effects these other systems can have on the Thermal Oxidizer are discussed in Section 0. Typical shutdown procedures are outlined and discussed in the sections that follow for the more common cases. Your existing company procedures and common sense operational judgment should be used to modify these procedures as needed to serve the purpose of any given planned shutdown situation.
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12.9.1
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
Planned Shutdown - No Entry When there are no plans to enter any of the equipment in the TTO system, no special shutdown procedures are required. Under these circumstances, the shutdown procedure given in this section may be used as a guide. It is generally preferable to shut down the Thermal Oxidizer in a controlled fashion to minimize the impact on the other process units, particularly if the SRUs and/or TGCU are to remain on-line. If time does not allow performing a controlled shutdown, however, the Thermal Oxidizer can be shut down by simply activating its TTO ESD system (using either the local push-button or the DCS "toggle" switch). This will automatically block the fuel gas, pilot gas, and combustion air feeding the Thermal Oxidizer. A.
If the SRUs and/or the TGCU are to be shut down also, shut down the TGCU first using the appropriate procedures from Section 11.9 Then shutdown the SRUs using the appropriate procedures from Section 9.9. NOTE:
If the SRUs are to remain in service while the TTO is shut down, SRU tailgas or TGCU effluent (plus the Sulfur Surge Tank sweep air and spent degassing air) will be flowing through the Thermal Oxidizer. Since these gases contains H2S (and possibly SO2), they should not be allowed to escape to the surroundings except from the top of the Thermal Oxidizer Vent Stack. The operating permit for this plant may not allow venting un-oxidized process gases for extended periods. In addition to H2S and SO2, SRU tailgas, Sulfur Surge Tank sweep air, and spent degassing air also contain elemental sulfur. This sulfur may condense in the Thermal Oxidizer system while it is shut down.
Issued 30 August 2011
B.
If the SRUs and the TGCU have been shut down, continue firing the Thermal Oxidizer Burner with the main fuel gas burner for several minutes to clear as much of the sulfur gases out of the system as possible.
C.
Use the "toggle" switch in the DCS or the push-button on the local TTO control panel to activate the TTO ESD system.
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D.
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK Switch the Startup/Run selector switch on the local TTO control panel to "STARTUP". This will open the Thermal Oxidizer Bypass valve and prove it open, then close the Thermal Oxidizer Feed valve.
E.
Close the manual block valves in the discharge lines of the Thermal Oxidizer Air Blowers.
F.
Visually confirm that:
G.
(1)
The main fuel gas shutdown valves are closed and the vent valve is open.
(2)
The block valves in the main fuel gas line and pilot gas supply line are closed.
(3)
The automated block valve in the air supply to the ignitor/pilot, and the automated block valves in the pilot gas supply to the ignitor/pilot, are closed and the pilot gas vent valve is open.
(4)
The Thermal Oxidizer Air Blowers are shut down and their discharge valves are closed.
(5)
The air flow control valve is closed.
If the Thermal Oxidizer will be down for an extended period, special precautions should be taken to prevent the boiler tubes from cooling to the point where water can condense on them. Most of the corrosion that occurs in TTOs is due to the acidic water that can form if the plant is allowed to get cold. Allow the Thermal Oxidizer Waste Heat Boiler to cool enough to Then reduce the steam pressure to about 1.0 kg/cm2(g). de-pressure the boiler and drain the water from it. Use a temporary "jumper" to supply LP steam to the boiler, and drain the condensate from it occasionally. This will keep the tubes safely above the water condensation temperature (100-110°C) and above the temperature at which sulfur freezes (119°C).
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12.9.2
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
Planned Shutdown for Entry When vessel entry for maintenance, inspection, or other purposes is required, the Thermal Oxidizer must be cooled down and isolated. The procedure below may be used as a guide for performing this type of shutdown. A.
Shut down the TGCU first with the appropriate procedures.
B.
Shut down the SRU with the appropriate procedures.
C.
Shut down the SDU with the appropriate procedures.
D.
Shut down the Sulfur Surge Tank Vent Ejectors as follows: (1)
Close the gate valve and the globe valve in the motive steam supply line.
(2)
Close its manual discharge valve.
WARNING NEVER BLOCK-IN THE EJECTORS COMPLETELY (CLOSING BOTH THE SUCTION VALVE AND THE DISCHARGE VALVE AT THE SAME TIME) WHILE THE HP MOTIVE STEAM SUPPLY LINE IS CONNECTED TO THE EJECTOR. A LEAK IN THE MOTIVE STEAM BLOCK VALVES COULD ALLOW THE HP STEAM TO OVER-PRESSURE THE EJECTOR BODY. E.
Continue firing the Thermal Oxidizer Burner with the main fuel gas burner for several minutes to clear as much of the sulfur gases out of the system as possible.
F.
Use the temperature controller to gradually reduce the temperature in the Thermal Oxidizer. To prevent damage to the refractory lining in the furnace, do not allow the temperature to drop more rapidly than 100-150°C per hour. NOTE:
Issued 30 August 2011
As the furnace temperature drops, the fuel gas flow rate will become progressively lower. Once the fuel gas control valve reaches its "minimum fire" position, it will not be possible to drop the temperature any further.
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G.
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK Once the furnace temperature reaches 100-150°C, the burner can be extinguished and the air blower used to provide the rest of the cooling: (1)
Shut down the Thermal Oxidizer by pressing the S/D push-button on the local TTO control panel.
(2)
Visually confirm that the main fuel gas shutdown valves are closed and the vent valve is open.
(3)
Visually confirm that the automated block valves in the pilot gas supply to the ignitor/pilot are closed and the vent valve is open.
(4)
Close the gate valve in the main fuel gas supply line and the gate valve at the burner.
(5)
Switch the Startup/Run selector switch on the local TTO control panel to "STARTUP".
(6)
Switch the air flow control hand switch in the DCS to "local" so that the manual air control on the local TTO control panel has control of the air flow control valve.
(7)
Start a Thermal Oxidizer Air Blower and open its discharge valve.
(8)
Press the "ESD RESET" push-button on the local TTO control panel.
(9)
Adjust the manual air control to send a large flow, 80% or more on the combustion air flow line alarms, to the Thermal Oxidizer.
H.
Allow the large flow of air to continue until the Thermal Oxidizer reaches ambient temperature.
I.
Once the Thermal Oxidizer is cool, use the "toggle" switch in the DCS, or the push-button on the local TTO control panel to activate the TTO ESD system.
J.
Close the manual block valves in the discharge lines of the Thermal Oxidizer Air Blowers.
K.
Visually confirm that: (1)
Issued 30 August 2011
The main fuel gas shutdown valves are closed and the vent valve is open.
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L.
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK (2)
The block valves in the main fuel gas line and the pilot gas supply line are closed.
(3)
The automated block valve in the air supply to the ignitor/pilot and the automated block valves in the pilot gas supply to the ignitor/pilot are closed and the pilot gas vent valve is open.
(4)
The Thermal Oxidizer Air Blowers are shut down and their discharge valves are closed.
(5)
The air flow control valve is closed.
Isolate the Thermal Oxidizer from all potential contaminating gases using slip blinds or by disconnecting the piping. In particular, isolate the Thermal Oxidizer from the SRUs and the TGCU using slip-blinds, etc.
WARNING THE THERMAL OXIDIZER INLET LINE CONTAINS TOXIC GASES (H2S AND SO2). THE "GENERAL SAFETY" SECTION OF THIS MANUAL SHOULD BE CONSULTED IF THERE IS ANY DOUBT ABOUT HOW TO WORK SAFELY WHEN THESE GASES ARE PRESENT.
CAUTION SINCE ISOLATION OF THE THERMAL OXIDIZER RESULTS IN THE LOW PRESSURE PIPING AND EQUIPMENT IN THE SRUS AND TGCU BEING COMPLETELY BLOCKED-IN, THE ACID GAS TO THE SRUS, SWS GAS TO THE SRUS, FUEL GAS TO THE SRUS, REDUCING GAS TO THE TGCU, AND NITROGEN PURGES TO THE SRUS AND THE TGCU SHOULD ALSO BE BLINDED OR DISCONNECTED. THIS WILL ENSURE THAT A LEAKING VALVE, ESPECIALLY FUEL GAS OR NITROGEN, WILL NOT BE ABLE TO OVER-PRESSURE THE SRUS AND/OR THE TGCU.
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M.
Once the Thermal Oxidizer is isolated, the TTO system can be opened for entry. Refer to the "General Safety" section of this manual for procedures to be followed when performing maintenance work on this plant.
N.
If the Thermal Oxidizer will be down for an extended period, special precautions should be taken to prevent the boiler tubes from cooling to the point where water can condense on them. Most of the corrosion that occurs in TTOs is due to the acidic water that can form if the plant is allowed to get cold. Allow the Thermal Oxidizer Waste Heat Boiler to cool enough to reduce the steam pressure to about 1.0 kg/cm2(g). Then de-pressure the boiler and drain the water from it. Use a temporary "jumper" to supply LP steam to the boiler, and drain the condensate from it occasionally. This will keep the tubes safely above the water condensation temperature (100-110°C) and above the temperature at which sulfur freezes (119°C).
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12.9.3
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
Shutting Down When Boiler Tubes Are Leaking One special circumstance that merits discussion is shutting down the TTO when there are tube leaks in the Thermal Oxidizer Waste Heat Boiler. While the plant is running, minor tube leaks usually cause little damage because the hot process gas vaporizes the boiler feed water before it has a chance to form acid and cause rapid corrosion. When a Thermal Oxidizer is shut down, however, several problems can develop: 1.
Liquid water may accumulate in the equipment or piping and form a variety of acids (sulfurous, polythionic, etc.) that will rapidly corrode the steel.
2.
Liquid water may reach the refractory linings in the equipment and damage the linings.
3.
If there is a large tube leak in the boiler, water may back-flow into the hot Thermal Oxidizer and rapidly vaporize, possibly violently enough to damage its refractory lining or create high pressure in the Thermal Oxidizer.
If a boiler tube leak is suspected, a shutdown procedure similar to the following may be appropriate:
Issued 30 August 2011
A.
Shut down the TGCU, shut down the SDU and shut off the Sulfur Surge Tank Vent Ejectors. Shut down the SRUs.
B.
Begin cooling down the Thermal Oxidizer using the procedure in Section 12.9.2. Do not activate the TTO ESD to shut down the air blower (Step I in Section 12.9.2) until the Thermal Oxidizer Waste Heat Boiler has been drained in Step E below.
C.
De-pressure the Thermal Oxidizer Waste Heat Boiler, taking care to reduce the pressure slowly enough to avoid over-stressing the boiler.
D.
Maintain a visible water level in the boiler. Water must remain in the boiler until it is de-pressured and the Thermal Oxidizer has been cooled to prevent overheating damage to the tubes.
E.
Once the Thermal Oxidizer is cool and the boiler is fully de-pressured, drain the water from the boiler to prevent any further leakage into the process side of the equipment.
F.
The TTO is now ready to be isolated and made safe for entry.
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12.9.4
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
Emergency Shutdown The TTO ESD system can be initiated by any of the actuating devices outlined in Section 12.5.9.1 of this manual, or by a power failure. The operator must determine and correct the condition causing the shutdown before the TTO can be restarted. The problems outlined below should be investigated first by the operator in his troubleshooting procedure. If the malfunction causing the emergency shutdown can be determined and corrected in a short period of time, the TTO can be put back on-line using the normal restart procedure outlined in Section 12.8.2 of this manual.
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S/D Actuation Device
Possible Causes
Thermal Oxidizer Burner Low-Low Combustion Air Flow
1. Malfunction of the flow control valve or flow control system. 2. Blower discharge block valve is closed or pinched. 3. The discharge block valve on the spare blower is open, allowing air to escape. 4. Blower shutdown due to mechanical problems with the blower, the motor, or the switchgear. 5. High pressure drop from plugging in the waste heat boiler.
Thermal Oxidizer Air Blower Neither Blower Running
1. Equipment damage has caused the blower to quit running. 2. A failure in the starter contacts is causing a false indication that the blower is not running.
Thermal Oxidizer Burner Fuel Gas Low-Low Pressure
1. A manual block valve is closed or pinched. 2. Header pressure is low due to problems elsewhere. 3. Malfunction of the fuel gas pressure regulator.
Thermal Oxidizer Burner Fuel Gas High-High Burner Pressure
1. Malfunction of the fuel gas pressure regulator. 2. Malfunction of the temperature control system. 3. The burner has been damaged (tip plugged or obstructed, etc.).
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S/D Actuation Device
Possible Causes
Thermal Oxidizer Burner Flame Failure
1. Failure of a component in the flame sensor circuit. 2. Condensation of sulfur or water vapor on the lens of the flame scanners. 3. Low fuel gas flow due to: a. Malfunction of the temperature control valve or the temperature control system. b. Malfunction of the fuel gas pressure regulator. c. A manual valve is closed or pinched. d. Fuel gas header pressure is low due to problems elsewhere. 4. Low combustion air flow due to: a. Malfunction of the flow control valve or the flow control system. b. Blower discharge block valve is closed or pinched. c. The discharge block valve on the spare blower is open, allowing air to escape. d. Blower shutdown due to mechanical problems with the blower, the motor, or the switchgear. e. High pressure drop from plugging in the waste heat boiler.
Thermal Oxidizer High-High Temperature
1. A sulfur plant is off-ratio, causing the tailgas from that SRU to contain large amounts of H2S (a combustible gas). 2. An upset in the TGCU is allowing large amounts of H2S to enter the Thermal Oxidizer. 3. Malfunction of the temperature control system or control valve. 4. Sulfur fire from accumulation of liquid sulfur in the bottom of the Thermal Oxidizer.
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S/D Actuation Device
Possible Causes
Thermal Oxidizer Waste Heat Boiler Superheated Steam High-High Temperature
1. Low steam flow through the superheater pass. 2. Malfunction of the interstage temperature control system or the desuperheating system. 3. Malfunction of the discharge temperature control system or the desuperheating system.
Thermal Oxidizer Waste Heat Boiler Low-Low Level
1. Loss of make-up water supply pressure. 2. Make-up water line plugged, or manual block valve closed or pinched. 3. Malfunction of the level control system. 4. Manual blowdown valve left open.
Thermal Oxidizer Vent Stack High-High Temperature
1. High temperature in the Thermal Oxidizer. 2. Sulfur fire from accumulation of liquid sulfur in the bottom of the stack or the Thermal Oxidizer Waste Heat Boiler casing. 3. Loss of water level in the Thermal Oxidizer Waste Heat Boiler which was not detected by the low-low level S/D. 4. Fouling of the tubes in the Thermal Oxidizer Waste Heat Boiler.
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12.9.5
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
Effects of Shutdowns and Outages in Other Systems The Tailgas Thermal Oxidation system is directly or indirectly affected by shutdowns and/or outages in four other systems in the complex. These effects are described below.
12.9.5.1
ATU / ARU Outages Acid gas flow from the ARU can be interrupted for a variety of reasons. When these events occur, the acid gas flow will not cease immediately. If processing in the ARU is restarted within the time frame of the system residence time, the ARU acid gas flow to the SRUs will probably dip, but should not stop completely. If the interruption in an ARU is long enough, though, the ARU acid gas flow can fall far enough to cause the acid gas flame in the SRUs to become unstable, at which point the SRU ESDs will be activated by "flame failure". Section 12.9.5.3 below describes the effect of this on the TTO.
12.9.5.2
Sour Water Stripper Outages SWS gas flow from the Sour Water Stripper can also be interrupted for a variety of reasons. However, since the loss of SWS gas flow to the SRUs generally has minimal impact, outages in this system are usually of little consequence to the SRUs or to the TTO.
12.9.5.3
SRU ESD System The SRU ESD system stops the flow of acid gas to the SRU. As a result, the tailgas flow from the SRU ceases almost immediately. However, the Thermal Oxidizer will continue to operate, with the temperature control on the Thermal Oxidizer cutting back the flow of fuel gas to the Thermal Oxidizer Burner to the amount needed to heat its combustion air (plus the sweep air from the Sulfur Surge Tank and the spent degassing air) to the operating temperature of the Thermal Oxidizer. The Thermal Oxidizer can run in this mode indefinitely. When acid gas flow resumes to the SRU(s), SRU tailgas and/or TGCU effluent will begin to flow once again to the Thermal Oxidizer. The temperature control will automatically increase the fuel gas flow
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12.9.5.4
TGCU ESD System When the TGCU ESD system is activated, the warmup/bypass valve in the TGCU opens immediately to divert the SRU tailgas streams to the TTO. At the same time, the PLC opens the Tailgas Valve to the TTO, proves the valve open, then closes the Tailgas Valve to the TGCU. Once this switch is complete, the SRU tailgas streams are blocked off from the TGCU and flow directly to the Thermal Oxidizer. When the TGCU warmup/bypass valve first opens, the pressure drop through the TGCU will no longer be imposing back-pressure on the SRUs. Depending on the magnitude of this change in back-pressure (which is mainly determined by the unit throughput), there may be a temporary "bobble" in the feed and air flow rates to the SRUs. Although this will probably cause brief deviations from the proper air:acid gas ratio in the SRUs, the "bobble" should not be large enough to cause a "flame failure" shutdown in the SRUs. If so, the SRUs will remain on-line with their tailgas flowing to the TTO.
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OPERATING GUIDELINES
Prepared by Ortloff Engineers, Ltd. Midland, Texas USA Project 507000 Fall 2011
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
Table of Contents 1. INTRODUCTION .......................................................................................................... 1-1 2. GENERAL SAFETY ..................................................................................................... 2-1 2.1 DEFINITION OF TERMS ....................................................................................... 2-1 2.2 HYDROGEN SULFIDE (H2S) ................................................................................ 2-3 2.2.1 Description and Properties ............................................................................. 2-3 2.2.2 First Aid .......................................................................................................... 2-7 2.2.3 Precautions (remember these facts) .............................................................. 2-8 2.2.4 Good Work Practices...................................................................................... 2-9 2.3 SULFUR DIOXIDE (SO2) ..................................................................................... 2-10 2.3.1 Description and Properties ........................................................................... 2-10 2.3.2 First Aid ........................................................................................................ 2-13 2.3.3 Precautions................................................................................................... 2-14 2.4 SULFUR .............................................................................................................. 2-15 2.4.1 Description and Properties ........................................................................... 2-15 2.4.2 Precautions................................................................................................... 2-20 2.4.3 Fire Fighting.................................................................................................. 2-21 2.5 AMMONIA (NH3) .................................................................................................. 2-22 2.5.1 Description and Properties ........................................................................... 2-22 2.5.2 First Aid ........................................................................................................ 2-26 2.5.3 Precautions................................................................................................... 2-26 2.6 METHYLDIETHANOLAMINE (MDEA, CH3-N-(CH2-CH2-OH)2)........................... 2-28 2.6.1 Description and Properties ........................................................................... 2-28 2.6.2 First Aid ........................................................................................................ 2-29 2.6.3 Precautions................................................................................................... 2-30 2.7 SODIUM HYDROXIDE (CAUSTIC SODA, NAOH) ............................................. 2-31 2.7.1 Description and Properties ........................................................................... 2-31 2.7.2 First Aid ........................................................................................................ 2-35 2.7.3 Precautions................................................................................................... 2-36 2.8 SULFUR PLANT SAFETY ................................................................................... 2-37 2.8.1 Hydrogen Sulfide .......................................................................................... 2-37 2.8.2 Sulfur Dioxide ............................................................................................... 2-37 2.8.3 Sulfur Storage Tank...................................................................................... 2-38 2.9 HOT WORK ......................................................................................................... 2-39 2.10 VESSEL ENTRY.................................................................................................. 2-39 2.11 PIPES AND LINES .............................................................................................. 2-41 2.11.1 General ......................................................................................................... 2-41 2.11.2 Before Breaking Lines .................................................................................. 2-42
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Table of Contents 2.11.3 When Breaking Lines ................................................................................... 2-42 2.12 ELECTRICAL EQUIPMENT ................................................................................ 2-42 2.12.1 Electrical Repairs.......................................................................................... 2-43 2.12.2 Grounding ..................................................................................................... 2-43 2.12.3 Conduit, Cables, and Wires .......................................................................... 2-43 2.12.4 Fuses ............................................................................................................ 2-43 2.12.5 Switching ...................................................................................................... 2-43 2.12.6 Hand Tools and Portable Equipment............................................................ 2-44 2.12.7 Miscellaneous ............................................................................................... 2-44 2.13 BOILERS AND OTHER DIRECT-FIRED EQUIPMENT ...................................... 2-45 2.13.1 General ......................................................................................................... 2-45 2.13.2 Boilers........................................................................................................... 2-45 2.13.3 Direct-Fired Equipment................................................................................. 2-46 2.14 LABORATORY SAFETY ..................................................................................... 2-47 2.14.1 Good Housekeeping ..................................................................................... 2-47 2.14.2 Equipment .................................................................................................... 2-47 2.14.3 Chemical Sorting and Identification .............................................................. 2-47 2.14.4 Chemical Handling ....................................................................................... 2-48 2.15 MATERIAL SAFETY DATA SHEETS (MSDS) .................................................... 2-49 3. GENERAL .................................................................................................................... 3-1 3.1 ORGANIZATION ................................................................................................... 3-1 3.2 GENERAL PRECOMMISSIONING PROCEDURES ............................................. 3-2 3.2.1 Mechanical ..................................................................................................... 3-2 3.2.2 Electrical ......................................................................................................... 3-3 3.2.3 Instrumentation ............................................................................................... 3-5 3.3 DESIGN BASIS ..................................................................................................... 3-7 3.3.1 Plant Capacity ................................................................................................ 3-7 3.3.2 Sulfur Block Feed Streams ............................................................................. 3-7 3.3.3 Effluent Stream Conditions ........................................................................... 3-12 3.3.4 Other Design Requirements ......................................................................... 3-13 3.3.5 Utility Information .......................................................................................... 3-14 3.3.6 Plant Site Conditions .................................................................................... 3-16 4. POWER DISTRIBUTION .............................................................................................. 4-1 4.1 PURPOSE OF SYSTEM ....................................................................................... 4-1 4.2 SAFETY ................................................................................................................. 4-1 4.2.1 General ........................................................................................................... 4-1 4.2.2 Hazardous (Classified) Areas ......................................................................... 4-1
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Table of Contents 4.3 EQUIPMENT DESCRIPTION ................................................................................ 4-2 4.3.1 Motors and Motor Controls ............................................................................. 4-2 5. PLANT CONTROL SYSTEMS ..................................................................................... 5-1 5.1 5.2 5.3 5.4
DISTRIBUTED CONTROL SYSTEM .................................................................... 5-1 PROGRAMMABLE LOGIC CONTROL SYSTEM ................................................. 5-2 EMERGENCY SHUTDOWN SYSTEMS ............................................................... 5-3 LOCAL CONTROL PANELS ................................................................................. 5-3
6. UTILITY SYSTEMS ...................................................................................................... 6-1 6.1 PURPOSE OF SYSTEM ....................................................................................... 6-1 6.2 SYSTEM DESCRIPTION ...................................................................................... 6-1 6.2.1 Nitrogen Supply .............................................................................................. 6-1 6.2.2 C4 LPG and Treated Fuel Gas Supply .......................................................... 6-2 6.2.3 Hydrogen Supply ............................................................................................ 6-2 6.2.4 Plant Air .......................................................................................................... 6-3 6.2.5 Instrument Air ................................................................................................. 6-3 6.2.6 Sour Water Disposal....................................................................................... 6-3 6.2.7 Steam, Condensate, Boiler Feed Water, and Blowdown ............................... 6-4 6.3 PRECOMMISSIONING, STARTUP, AND SHUTDOWN PROCEDURES............. 6-8 7. AMINE TREATING & AMINE REGENERATION ......................................................... 7-1 7.1 PURPOSE OF SYSTEM ....................................................................................... 7-1 7.2 SAFETY ................................................................................................................. 7-1 7.3 PROCESS DESCRIPTION.................................................................................... 7-2 7.3.1 General ........................................................................................................... 7-2 7.3.2 Water Washing ............................................................................................... 7-2 7.3.3 Sour Gas Contacting ...................................................................................... 7-3 7.3.4 Solvent Regeneration ..................................................................................... 7-3 7.4 EQUIPMENT DESCRIPTION ................................................................................ 7-6 7.4.1 Wash Water Column, A2-DA1510 .................................................................. 7-6 7.4.2 Amine Absorber, A2-DA1511 ......................................................................... 7-6 7.4.3 Flash Gas Contactor, A2-DA1512 .................................................................. 7-6 7.4.4 Stripper, A2-DA1513 ...................................................................................... 7-6 7.4.5 Wash Water Column Packing, A2-DB1510 .................................................... 7-7 7.4.6 Amine Absorber Trays, A2-DB1511 ............................................................... 7-7 7.4.7 Stripper Trays, A2-DB1513 ............................................................................ 7-7 7.4.8 Amine Absorber Overhead Cooler, A2-EA1510 ............................................. 7-8 7.4.9 Lean/Rich Exchanger, A2-EA1511A/B ........................................................... 7-8 7.4.10 Stripper Reboiler, A2-EA1512A/B .................................................................. 7-8
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Table of Contents 7.4.11 Stripper Reflux Condenser, A2-EC1511......................................................... 7-8 7.4.12 Lean Amine Cooler, A2-EC1510 .................................................................... 7-8 7.4.13 Wash Water Feed Knock-Out Drum, A2-FA1510 ........................................... 7-8 7.4.14 Amine Absorber Feed Knock-Out Drum, A2-FA1511 ..................................... 7-9 7.4.15 Amine Absorber Overhead Knock-Out Drum, A2-FA1512 ............................. 7-9 7.4.16 Rich Amine Flash Drum, A2-FA1513 ............................................................. 7-9 7.4.17 Stripper Reflux Accumulator, A2-FA1514..................................................... 7-10 7.4.18 Stripper Reboiler Condensate Pot, A2-FA1515A/B ...................................... 7-10 7.4.19 ATU Skim Oil Sump, A2-FA1516 ................................................................. 7-10 7.4.20 ATU Skim Oil Pump Sump, A2-FA1517A/B ................................................. 7-10 7.4.21 ATU Amine Drips Tank, A2-FA1580............................................................. 7-11 7.4.22 MDEA Storage Tank, A2-FB1580 ................................................................ 7-11 7.4.23 Wash Water Filter, A2-FD1510A/B ............................................................... 7-11 7.4.24 Rich Amine Filter, A2-FD1511A/B ................................................................ 7-11 7.4.25 Lean Amine Filter, A2-FD1512 ..................................................................... 7-11 7.4.26 Lean Amine Carbon Filter, A2-FD1513 ........................................................ 7-12 7.4.27 Lean Amine After-Filter, A2-FD1514 ............................................................ 7-12 7.4.28 ATU Amine Drips Filter, A2-FD1580 ............................................................ 7-12 7.4.29 Wash Water Pump, A2-GA1510A/B ............................................................. 7-13 7.4.30 Lean Amine Pump, A2-GA1511A/B ............................................................. 7-13 7.4.31 ATU Skim Oil Pump, A2-GA1512A/B ........................................................... 7-13 7.4.32 Rich Amine Pump, A2-GA1513A/B .............................................................. 7-13 7.4.33 Lean Amine Booster Pump, A2-GA1514A/B ................................................ 7-13 7.4.34 Stripper Reflux Pump, A2-GA1515A/B ......................................................... 7-13 7.4.35 MDEA Transfer Pump, A2-GA1580.............................................................. 7-14 7.5 INSTRUMENTATION AND CONTROL SYSTEMS ............................................. 7-15 7.5.1 Treated Fuel Gas H2S Analyzer ................................................................... 7-15 7.5.2 ATU Emergency Shutdown Systems ........................................................... 7-15 7.6 PROCESS PRINCIPLES AND OPERATING TECHNIQUES ............................. 7-19 7.6.1 Amine Absorber Operation ........................................................................... 7-19 7.6.2 Stripper Operation ........................................................................................ 7-22 7.6.3 Amine Water Balance ................................................................................... 7-24 7.6.4 Amine Loss ................................................................................................... 7-27 7.6.5 Operation at Low Flow Rates ....................................................................... 7-29 7.7 PRECOMMISSIONING PROCEDURES ............................................................. 7-30 7.7.1 Preliminary Check-out .................................................................................. 7-30 7.7.2 Shutdown System Check-out ....................................................................... 7-31 7.7.3 Leak Testing the Process Piping and Equipment ......................................... 7-31
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Table of Contents 7.7.4 Washing the Wash Water System ................................................................ 7-33 7.7.5 Washing the Amine System ......................................................................... 7-38 7.7.6 Purging the Low Pressure Columns ............................................................. 7-50 7.8 STARTUP PROCEDURES.................................................................................. 7-52 7.8.1 Wash Water and Amine Systems ................................................................. 7-52 7.8.2 Sour Fuel Gas Flow to the Columns............................................................. 7-53 7.9 SHUTDOWN PROCEDURES ............................................................................. 7-56 7.9.1 Planned Shutdown - ATU ............................................................................ 7-57 7.9.2 Planned Shutdown - ATU and ARU ............................................................. 7-60 7.9.3 Emergency Shutdown .................................................................................. 7-62 7.9.4 Effects of Shutdowns and Outages in Other Systems.................................. 7-63 7.10 ANALYTICAL PROCEDURES ............................................................................ 7-64 7.10.1 General Procedures for Analyzing ATU/ARU Solvent, ................................. 7-64 7.10.2 Determination of Amine Concentration in ATU/ARU Solvent ....................... 7-68 7.10.3 Determination of Total Acid Gas Loading in ATU/ARU Solvent ................... 7-70 7.10.4 Determination of H2S and CO2 Loading in ATU/ARU Solvent ...................... 7-72 7.10.5 Determination of Foaming Tendency of ATU/ARU Solvent .......................... 7-76 7.10.6 H2S Conc. in Amine Absorber Ovhd by the Tutweiler Method ..................... 7-78 7.10.7 H2S Conc. in Amine Absorber Ovhd Using Gas Detector Tubes ................. 7-79 8. SOUR WATER STRIPPING ......................................................................................... 8-1 8.1 PURPOSE OF SYSTEM ....................................................................................... 8-1 8.2 SAFETY ................................................................................................................. 8-1 8.3 PROCESS DESCRIPTION.................................................................................... 8-2 8.3.1 General ........................................................................................................... 8-2 8.3.2 Sour Water Collection..................................................................................... 8-2 8.3.3 Sour Water Stripping ...................................................................................... 8-3 8.4 EQUIPMENT DESCRIPTION ................................................................................ 8-5 8.4.1 Sour Water Stripper, A2-DA1520 ................................................................... 8-5 8.4.2 Sour Water Stripper Packing and Internals, A2-DB1520 ................................ 8-5 8.4.3 Stripper Trays, A2-DB1521 ............................................................................ 8-5 8.4.4 SWS Cross Exchanger, A2-EA1520 .............................................................. 8-5 8.4.5 Sour Water Stripper Reboiler, A2-EA1521 ..................................................... 8-6 8.4.6 SWS Quench Water Cooler, A2-EC1520 ....................................................... 8-6 8.4.7 SWS Bottoms Cooler, A2-EC1521 ................................................................. 8-6 8.4.8 Sour Water Flash Drum, A2-FA1520.............................................................. 8-6 8.4.9 SWS Skim Oil Sump, A2-FA1522 .................................................................. 8-7 8.4.10 SWS Skim Oil Pump Sump, A2-FA1523A/B .................................................. 8-7 8.4.11 Sour Water Tank, A2-FB1520 ........................................................................ 8-7
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Table of Contents 8.4.12 Sour Water Filter, A2-FD1520A/B .................................................................. 8-7 8.4.13 Sour Water Transfer Pump, A2-GA1520A/B .................................................. 8-7 8.4.14 SWS Feed Pump, A2-GA1521A/B ................................................................. 8-8 8.4.15 SWS Quench Water Pump, A2-GA1522A/B .................................................. 8-8 8.4.16 SWS Bottoms Pump, A2-GA1523A/B ............................................................ 8-8 8.4.17 SWS Skim Oil Pump, A2-GA1524A/B ............................................................ 8-8 8.5 INSTRUMENTATION AND CONTROL SYSTEMS ............................................... 8-9 8.5.1 SWS Shutdowns and Alarms ......................................................................... 8-9 8.6 PROCESS PRINCIPLES AND OPERATING TECHNIQUES ............................. 8-11 8.6.1 SWS Stripper Operation ............................................................................... 8-11 8.6.2 Quench Water Circulation ............................................................................ 8-12 8.6.3 pH Control .................................................................................................... 8-13 8.7 PRECOMMISSIONING PROCEDURES ............................................................. 8-14 8.7.1 Preliminary Check-out .................................................................................. 8-14 8.7.2 Washing the Sour Water System ................................................................. 8-15 8.8 STARTUP PROCEDURES.................................................................................. 8-19 8.8.1 Initial Startup of the SWS ............................................................................. 8-19 8.8.2 Normal Startup of the SWS .......................................................................... 8-23 8.9 SHUTDOWN PROCEDURES ............................................................................. 8-29 8.9.1 Planned Shutdown ....................................................................................... 8-29 8.9.2 Effects of Shutdowns and Outages in Other Systems.................................. 8-31 9. SULFUR RECOVERY .................................................................................................. 9-4 9.1 PURPOSE OF SYSTEM ....................................................................................... 9-4 9.2 SAFETY ................................................................................................................. 9-4 9.3 PROCESS DESCRIPTION.................................................................................... 9-5 9.3.1 Overview......................................................................................................... 9-5 9.3.2 General ........................................................................................................... 9-6 9.3.3 Feed Gas Processing ..................................................................................... 9-6 9.3.4 Thermal Processing........................................................................................ 9-7 9.3.5 Catalytic Processing ....................................................................................... 9-8 9.3.6 Air Control System.......................................................................................... 9-9 9.3.7 Molten Sulfur Handling ................................................................................. 9-10 9.3.8 Steam Production ......................................................................................... 9-10 9.4 EQUIPMENT DESCRIPTION .............................................................................. 9-11 9.4.1 Reactor Furnace, A2-BA1530 (A2-BA1540) ................................................. 9-11 9.4.2 Acid Gas Burner Assembly, A2-BA1531 (A2-BA1541) ................................ 9-12 9.4.3 Acid Gas Knock-Out Drum, A2-FA1530 (A2-FA1540) ................................. 9-12 9.4.4 SWS Gas Knock-Out Drum, A2-FA1531 (A2-FA1541) ................................ 9-12
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Table of Contents 9.4.5 Reactor, A2-DC1530 (A2-DC1540) .............................................................. 9-13 9.4.6 Catalyst for Sulfur Plant Reactors, A2-MC1530 (A2-MC1540) ..................... 9-13 9.4.7 Acid Gas Preheater, A2-EA1530 (A2-EA1540) ............................................ 9-13 9.4.8 Sulfur Condenser, A2-EA1531 (A2-EA1541) ............................................... 9-13 9.4.9 Reactor No. 1 Feed Heater, A2-EA1532 (A2-EA1542) ................................ 9-14 9.4.10 Reactor No. 2 Feed Heater, A2-EA1533 (A2-EA1543) ................................ 9-14 9.4.11 Reactor No. 3 Feed Heater, A2-EA1534 (A2-EA1544) ................................ 9-15 9.4.12 Sulfur Surge Tank, A2-FB1530 (A2-FB1540) ............................................... 9-15 9.4.13 Acid Gas Knock-Out Drum Pump, A2-GA1530A/B (A2-GA1540A/B) .......... 9-16 9.4.14 SWS Gas Knock-Out Drum Pump, A2-GA1531A/B (A2-GA1541A/B) ......... 9-17 9.4.15 Sulfur Storage Tank Vent Ejector, A2-EE1530 (A2-EE1540) ....................... 9-17 9.4.16 Process Air Blower, A2-GB1530A/B (A2-GB1540A/B)................................. 9-18 9.4.17 Air Blower Suction Screen/Silencer, A2-FD1530A/B (A2-FD1540A/B) ........ 9-19 9.4.18 Process Air Vent Silencer, A2-FG1530A/B (A2-FG1540A/B) ....................... 9-19 9.4.19 Sulfur Drain Seal Assembly, A2-ME1530A-D (A2-ME1540A-D) .................. 9-19 9.4.20 Refractory for Reactor Furnace and Waste Heat Boiler, A2-MR1530 (A2-MR1540) .............................................................................................................. 9-20 9.4.21 Ceramic Ferrules for Waste Heat Boiler, A2-MR1532 (A2-MR1542) ........... 9-20 9.4.22 Refractory for Waste Heat Boiler, A2-MR1533 (A2-MR1543) ...................... 9-20 9.4.23 Refractory for Sulfur Condenser, A2-MR1534 (A2-MR1544) ....................... 9-20 9.4.24 Refractory for Reactor, A2-MR1535 (A2-MR1545) ...................................... 9-21 9.4.25 Rainshield for Reactor Furnace, A2-ME1531 (A2-ME1541) ........................ 9-21 9.4.26 Ceramic Ferrule for Reactor Furnace, A2-MR1531 (A2-MR1541) ............... 9-21 9.4.27 Waste Heat Boiler, A2-BF1530 (A2-BF1540) ............................................... 9-22 9.5 INSTRUMENTATION AND CONTROL SYSTEMS ............................................. 9-24 9.5.1 SRU Air:Acid Gas Ratio Control Loop .......................................................... 9-24 9.5.2 Acid Gas Burner Management System ........................................................ 9-30 9.5.3 Process Air Blower Controls ......................................................................... 9-34 9.5.4 Reactor Furnace Temperature Control......................................................... 9-39 9.5.5 Knock-Out Drum Pump Control .................................................................... 9-41 9.5.6 "Ride-Through" System Considerations ....................................................... 9-41 9.5.7 Boiler Low-Low Level S/D Transmitter Testing ............................................ 9-44 9.5.8 SRU Emergency Shutdown Systems ........................................................... 9-46 9.6 PROCESS PRINCIPLES AND OPERATING TECHNIQUES ............................. 9-56 9.6.1 Equipment Damage ...................................................................................... 9-56 9.6.2 Cold Catalyst Bed Startup ............................................................................ 9-58 9.6.3 Sulfur Solidification ....................................................................................... 9-60 9.6.4 Ammonia Salt Formation .............................................................................. 9-61
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Table of Contents 9.6.5 Catalyst Fouling ............................................................................................ 9-62 9.6.6 Operation of SRUs in Parallel....................................................................... 9-62 9.6.7 Process air Blower Operation ....................................................................... 9-65 9.6.8 Reactor Furnace Temperature ..................................................................... 9-70 9.6.9 Ammonia Destruction Considerations .......................................................... 9-73 9.6.10 Sulfur Recovery Efficiency............................................................................ 9-76 9.6.11 Operation at Low Flow Rates ....................................................................... 9-78 9.6.12 Pressure Drop Surveys ................................................................................ 9-82 9.6.13 Boiler Water Treatment ................................................................................ 9-84 9.7 PRECOMMISSIONING PROCEDURES ............................................................. 9-86 9.7.1 Preliminary Check-out .................................................................................. 9-86 9.7.2 Shutdown System Check-out ....................................................................... 9-87 9.7.3 Leak Testing the Process Piping and Equipment ......................................... 9-88 9.7.4 Purging the Inlet Knock-Out Drums .............................................................. 9-93 9.7.5 Commissioning Fuel Gas and Instrument Air to the Process ....................... 9-95 9.7.6 Commissioning Nitrogen to the Process ...................................................... 9-99 9.7.7 Commissioning the Sulfur Surge Tank Heating and Ventilation ................. 9-102 9.7.8 Pre-filling the Sulfur Drain Seal Assemblies ............................................... 9-104 9.8 STARTUP PROCEDURES................................................................................ 9-105 9.8.1 Initial Firing / Refractory Cure-out............................................................... 9-105 9.8.2 Amine Acid Gas Flow ................................................................................. 9-117 9.8.3 SWS Gas Flow ........................................................................................... 9-124 9.8.4 Routing SRU Tailgas to the TGCU ............................................................. 9-127 9.8.5 Normal Startup - Cold System .................................................................... 9-129 Normal Startup - Hot System...................................................................... 9-146 9.8.6 9.8.7 Firing Supplemental Fuel Gas .................................................................... 9-158 9.9 SHUTDOWN PROCEDURES ........................................................................... 9-164 9.9.1 Planned Shutdown - No Reactor Entry....................................................... 9-165 9.9.2 Planned Shutdown for Reactor Entry ......................................................... 9-170 9.9.3 Shutting Down When Boiler Tubes Are Leaking ........................................ 9-180 9.9.4 Emergency Shutdown ................................................................................ 9-181 9.9.5 Effects of Shutdowns and Outages in Other Systems................................ 9-183 9.10 ANALYTICAL PROCEDURES .......................................................................... 9-187 9.10.1 Procedure for Sampling and Titrating with a Tutweiler Apparatus ............. 9-187 9.10.2 H2S Concentration in Acid Gas by the Tutweiler Method ........................... 9-189 9.10.3 H2S and SO2 Concentration in Tailgas by the Tutweiler Method ................ 9-192 9.10.4 Tailgas Analysis Table................................................................................ 9-196 9.10.5 Tailgas Analysis Operating Chart ............................................................... 9-197
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Table of Contents 9.10.6 Essential Apparatus for Tutweiler Analysis ................................................ 9-199 9.10.7 Materials for Tutweiler Analysis .................................................................. 9-200 9.10.8 H2S and SO2 Conc. in Tailgas Using Gas Detector Tubes ......................... 9-200 9.11 ADJUSTING STACKMATCH® IGNITOR/PILOTS ............................................. 9-205 10.
SULFUR DEGASSING, STORAGE & LOADING .................................................. 10-3
10.1 PURPOSE OF SYSTEM ..................................................................................... 10-3 10.2 SAFETY ............................................................................................................... 10-4 10.3 PROCESS DESCRIPTION.................................................................................. 10-5 10.4 EQUIPMENT DESCRIPTION .............................................................................. 10-7 10.4.1 Sulfur Degassing Reactor, A2-DC1550 ........................................................ 10-7 10.4.2 Sulfur Storage Tank, A2-FB1550 ................................................................. 10-7 10.4.3 Sulfur Feed Pump, A2-GA1532A/B (A2-GA1542A/B) .................................. 10-8 10.4.4 Sulfur Loading Pump, A2-GA1550A/B ......................................................... 10-8 10.4.5 Degassing Air Blower, A2-GB1550A/B ......................................................... 10-9 10.4.6 Bed Support and Limiter for Sulfur Degassing Reactor, A2-DC1551 ........... 10-9 10.4.7 Degassed Sulfur Drain Seal Assembly, A2-ME1550.................................... 10-9 10.5 INSTRUMENTATION AND CONTROL SYSTEMS ........................................... 10-11 10.5.1 Sulfur Feed Rate Control ............................................................................ 10-11 10.5.2 Degassing Air Flow..................................................................................... 10-12 10.5.3 Sulfur Degassing Unit Startup Interlock ...................................................... 10-13 10.5.4 Snuffing Steam ........................................................................................... 10-13 10.5.5 Sulfur Loading ............................................................................................ 10-14 10.5.6 Sulfur Loading Pump Local Stop Switches................................................. 10-17 10.5.7 Sulfur Degassing Shutdown System .......................................................... 10-18 10.5.8 Sulfur Loading ESD System ....................................................................... 10-21 10.6 PROCESS PRINCIPLES AND OPERATING TECHNIQUES ........................... 10-23 10.6.1 Equipment Damage .................................................................................... 10-23 10.6.2 Degassing Air Blower Operation ................................................................ 10-26 10.6.3 Sulfur Solidification ..................................................................................... 10-29 10.6.4 Sulfur Pumping ........................................................................................... 10-29 10.7 PRECOMMISSIONING PROCEDURES ........................................................... 10-31 10.7.1 Preliminary Check-out ................................................................................ 10-31 10.7.2 Commissioning the Heating and Ventilation Systems ................................ 10-32 10.7.3 Purging the Sulfur Degassing Reactor ....................................................... 10-37 10.8 STARTUP PROCEDURES................................................................................ 10-40 10.8.1 Initial Startup of the Sulfur Degassing Unit ................................................. 10-40 10.8.2 Normal Startup of the Sulfur Degassing System ........................................ 10-46 10.8.3 Initial Sulfur Loading Operation .................................................................. 10-51
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Table of Contents 10.8.4 Normal Sulfur Loading Operation ............................................................... 10-53 10.9 SHUTDOWN PROCEDURES ........................................................................... 10-54 10.9.1 Planned Shutdown - No Reactor Entry....................................................... 10-54 10.9.2 Planned Shutdown for Reactor Entry ......................................................... 10-55 10.9.3 Shutdown for Tank Entry ............................................................................ 10-57 11.
TAILGAS CLEANUP .............................................................................................. 11-1
11.1 PURPOSE OF SYSTEM ..................................................................................... 11-1 11.2 SAFETY ............................................................................................................... 11-2 11.3 PROCESS DESCRIPTION.................................................................................. 11-3 11.3.1 General ......................................................................................................... 11-3 11.3.2 Tailgas Hydrogenation/Hydrolysis ................................................................ 11-3 11.3.3 Process Gas Cooling .................................................................................... 11-4 11.3.4 Gas Contacting ............................................................................................. 11-5 11.3.5 Solvent Regeneration Section ...................................................................... 11-6 11.3.6 Steam Production/Consumption ................................................................... 11-7 11.4 EQUIPMENT DESCRIPTION .............................................................................. 11-8 11.4.1 TGCU Quench Column, A2-DA1560 ............................................................ 11-8 11.4.2 TGCU Quench Column Packing, A2-DB1560 .............................................. 11-8 11.4.3 TGCU Contactor, A2-DA1561 ...................................................................... 11-8 11.4.4 TGCU Contactor Packing & Internals, A2-DB1561 ...................................... 11-8 11.4.5 TGCU Stripper, A2-DA1562 ......................................................................... 11-9 11.4.6 TGCU Stripper Trays, A2-DB1562 ............................................................... 11-9 11.4.7 TGCU Reactor, A2-DC1560 ....................................................................... 11-10 11.4.8 TGCU Stripper Reflux Accumulator, A2-FA1560 ....................................... 11-10 11.4.9 Catalyst for TGCU Reactor, A2-MC1560 ................................................... 11-10 11.4.10 TGCU Stripper Reboiler Condensate Pot, A2-FA1562 ........................... 11-10 11.4.11 TGCU Reactor Feed Heater, A2-EA1560 ............................................... 11-11 11.4.12 TGCU Waste Heat Reclaimer, A2-EA1561 ............................................ 11-11 11.4.13 TGCU Quench Water Trim Cooler, A2-EA1562A/B ................................ 11-11 11.4.14 TGCU Lean/Rich Exchanger, A2-EA1564 .............................................. 11-11 11.4.15 TGCU Stripper Reboiler, A2-EA1565 ..................................................... 11-12 11.4.16 TGCU Lean Amine Trim Cooler, A2-EA1563 ......................................... 11-12 11.4.17 TGCU Quench Water Cooler, A2-EC1560 ............................................. 11-12 11.4.18 TGCU Stripper Reflux Condenser, A2-EC1562 ...................................... 11-12 11.4.19 TGCU Lean Amine Cooler, A2-EC1561 ................................................. 11-12 11.4.20 TGCU Quench Water Pump, A2-GA1560A/B......................................... 11-13 11.4.21 TGCU Rich Amine Pump, A2-GA1561A/B ............................................. 11-14 11.4.22 TGCU Stripper Reflux Pump, A2-GA1563A/B ........................................ 11-14
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Table of Contents 11.4.23 TGCU Lean Amine Pump, A2-GA1562A/B ............................................. 11-14 11.4.24 TGCU Start-Up Blower, A2-GB1560 ....................................................... 11-14 11.4.25 Refractory for TGCU Reactor, A2-MR1560 ............................................ 11-15 11.4.26 TGCU Reactor Feed Mixer, A2-ME1560 ................................................ 11-16 11.4.27 TGCU Quench Water Filter, A2-FD1560A/B .......................................... 11-16 11.4.28 TGCU Rich Amine Filter, A2-FD1562A/B ............................................... 11-16 11.4.29 TGCU Lean Amine Filter, A2-FD1563 .................................................... 11-17 11.4.30 TGCU Amine Carbon Filter, A2-FD1564 ................................................ 11-17 11.4.31 TGCU Amine After-Filter, A2-FD1565 .................................................... 11-17 11.4.32 pH Meter Sample Filter, A2-FD1561A/B ................................................. 11-17 11.5 INSTRUMENTATION AND CONTROL SYSTEMS ........................................... 11-18 11.5.1 TGCU Reactor Feed Control Loops ........................................................... 11-18 11.5.2 Hydrogen and Hydrogen Sulfide Analyzer, A2-AE15858/A2-AE15859 ...... 11-23 11.5.3 Boiler Low-Low Level S/D Transmitter Testing .......................................... 11-24 11.5.4 Tailgas Switching Valve Controls ............................................................... 11-26 11.5.5 TGCU Shutdown System ........................................................................... 11-33 11.6 PROCESS PRINCIPLES AND OPERATING TECHNIQUES ........................... 11-39 11.6.1 Equipment Damage .................................................................................... 11-39 11.6.2 Catalyst Fouling .......................................................................................... 11-40 11.6.3 TGCU Reactor Operation ........................................................................... 11-41 11.6.4 TGCU Catalyst ........................................................................................... 11-43 11.6.5 TGCU Start-Up Blower Operation .............................................................. 11-44 11.6.6 TGCU Quench Column Operation.............................................................. 11-45 11.6.7 TGCU Contactor Operation ........................................................................ 11-48 11.6.8 TGCU Stripper Operation ........................................................................... 11-52 11.6.9 TGCU Amine Water Balance...................................................................... 11-55 11.6.10 TGCU Amine Loss .................................................................................. 11-59 11.6.11 Operation at Low Flow Rates.................................................................. 11-60 11.6.12 Pressure Drop Surveys ........................................................................... 11-61 11.6.13 Boiler Water Treatment ........................................................................... 11-63 11.7 PRECOMMISSIONING PROCEDURES ........................................................... 11-64 11.7.1 Preliminary Check-out ................................................................................ 11-64 11.7.2 Shutdown System Check-out ..................................................................... 11-65 11.7.3 Commissioning Nitrogen and Utility Air to the Process .............................. 11-66 11.7.4 Commissioning Hydrogen to the Process .................................................. 11-72 11.7.5 Leak Testing the Process Piping and Equipment ....................................... 11-75 11.7.6 Washing the Quench Water System .......................................................... 11-79 11.7.7 Washing the Amine System ....................................................................... 11-85
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SULFUR BLOCK
Table of Contents 11.7.8 Purging the Low Pressure TGCU Columns ................................................ 11-97 11.8 STARTUP PROCEDURES.............................................................................. 11-102 11.8.1 Initial Startup of the TGCU ....................................................................... 11-102 11.8.2 Pre-Sulfiding the TGCU Catalyst .............................................................. 11-107 11.8.3 Routing SRU Tailgas to the TGCU ........................................................... 11-115 11.8.4 Quench Water and Amine Systems ......................................................... 11-122 11.8.5 Process Gas Flow to the TGCU Columns ................................................ 11-124 11.8.6 Normal Startup of the TGCU .................................................................... 11-128 11.9 SHUTDOWN PROCEDURES ......................................................................... 11-144 11.9.1 Planned Shutdown - No Reactor Entry..................................................... 11-145 11.9.2 Planned Shutdown for Reactor Entry ....................................................... 11-151 11.9.3 Shutting Down When Boiler Tubes Are Leaking ...................................... 11-158 11.9.4 Special Precaution During Shutdowns ..................................................... 11-159 11.9.5 Emergency Shutdown .............................................................................. 11-163 11.9.6 Effects of Shutdowns and Outages in Other Systems.............................. 11-164 11.10 ANALYTICAL PROCEDURES ..................................................................... 11-167 11.10.1 General Procedures for Analyzing TGCU Solvent, ............................... 11-167 11.10.2 Determination of Amine Concentration in TGCU Solvent ..................... 11-171 11.10.3 Determination of Total Acid Gas Loading in TGCU Solvent ................. 11-173 11.10.4 Determination of H2S and CO2 Loading in TGCU Solvent .................... 11-175 11.10.5 Determination of Foaming Tendency of TGCU Solvent ........................ 11-179 11.10.6 H2S Conc. in TGCU Contactor Ovhd by the Tutweiler Method ............. 11-181 11.10.7 H2S Conc. in TGCU Contactor Ovhd Using Gas Detector Tubes ......... 11-182 11.10.8 Monitoring the Performance Level of TGCU Catalyst ........................... 11-185 12.
TAILGAS THERMAL OXIDIZER ............................................................................ 12-2
12.1 PURPOSE OF SYSTEM ..................................................................................... 12-2 12.2 SAFETY ............................................................................................................... 12-2 12.3 PROCESS DESCRIPTION.................................................................................. 12-3 12.4 EQUIPMENT DESCRIPTION .............................................................................. 12-4 12.4.1 Thermal Oxidizer, A2-BA1570 ...................................................................... 12-4 12.4.2 Thermal Oxidizer Burner, A2-BA1571 .......................................................... 12-4 12.4.3 Steam Knock-out Drum, A2-FA1570 ............................................................ 12-4 12.4.4 Thermal Oxidizer Air Blower, A2-GB1570A/B .............................................. 12-4 12.4.5 Thermal Oxidizer Vent Stack, A2-ME1570 ................................................... 12-5 12.4.6 Refractory for Thermal Oxidizer, A2-MR1570 .............................................. 12-5 12.4.7 Thermal Oxidizer Waste Heat Boiler, A2-BF1570 ........................................ 12-5 12.5 INSTRUMENTATION AND CONTROL SYSTEMS ............................................. 12-7 12.5.1 Thermal Oxidizer Burner Management System ........................................... 12-7
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Table of Contents 12.5.2 Thermal Oxidizer Temperature Control ...................................................... 12-10 12.5.3 Thermal Oxidizer Excess Oxygen Control.................................................. 12-10 12.5.4 Boiler Low-Low Level S/D Transmitter Testing .......................................... 12-11 12.5.5 Thermal Oxidizer Shutdown System .......................................................... 12-13 12.6 PROCESS PRINCIPLES AND OPERATING TECHNIQUES ........................... 12-18 12.6.1 Equipment Damage .................................................................................... 12-18 12.6.2 Effect of Upstream Operations on the Thermal Oxidizer ............................ 12-21 12.6.3 "Swapping" Air Blowers During Operation .................................................. 12-23 12.6.4 Boiler Water Treatment .............................................................................. 12-24 12.7 PRECOMMISSIONING PROCEDURES ........................................................... 12-26 12.7.1 Preliminary Check-out ................................................................................ 12-26 12.7.2 Shutdown System Check-out ..................................................................... 12-27 12.7.3 Commissioning Fuel Gas, Pilot Gas, and I/A to the Process ..................... 12-28 12.8 STARTUP PROCEDURES................................................................................ 12-33 12.8.1 Initial Firing / Refractory Cure-out............................................................... 12-33 12.8.2 Normal Startup ........................................................................................... 12-48 12.9 SHUTDOWN PROCEDURES ........................................................................... 12-58 12.9.1 Planned Shutdown - No Entry .................................................................... 12-59 12.9.2 Planned Shutdown for Entry ....................................................................... 12-61 12.9.3 Shutting Down When Boiler Tubes Are Leaking ........................................ 12-65 12.9.4 Emergency Shutdown ................................................................................ 12-66 12.9.5 Effects of Shutdowns and Outages in Other Systems................................ 12-69
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SULFUR BLOCK
1. INTRODUCTION THE INFORMATION IN THESE GUIDELINES IS CONFIDENTIAL. SOME OF THE PROCESSES, DESIGNS, EQUIPMENT, AND/OR PROCEDURES DESCRIBED HEREIN ARE PROPRIETARY AND/OR LICENSED BY BP AMOCO CORPORATION, SHELL GLOBAL SOLUTIONS (US) INC., UOP LLC. AND/OR ORTLOFF ENGINEERS, LTD. DISCLOSURE, REPRODUCTION, OR USE OF THESE GUIDELINES FOR ANY REASON OTHER THAN OPERATION OF THIS FACILITY IS IN VIOLATION OF WRITTEN SECRECY AGREEMENTS. These Operating Guidelines have been prepared by Ortloff Engineers, Ltd. as a guide for the initial operation of the new Sulfur Block at Samsung Total Petrochemicals Co., Ltd.’s Daesan No. 2 Aromatics Complex. The new Sulfur Block consists of an Amine Treating Unit (ATU), an Amine Regeneration Unit (ARU), a Sour Water Stripper (SWS), two parallel Sulfur Recovery Units (SRUs), and a common Sulfur Degassing Unit (SDU), Tailgas Cleanup Unit (TGCU) and Tailgas Thermal Oxidation Unit (TTO). These units are to process sour gas and sour water streams to remove the contained sulfur and produce treated fuel gas for consumption in the complex, treated water safe for reuse or disposal, and commercial grade molten sulfur for sales. These guidelines contain information concerning the design, startup, operation, and shutdown of the new facility to assist plant personnel in developing familiarity with and understanding of the process, equipment, and overall plant operation, and to supplement equipment manufacturers' operating instructions. We have tried to present all of the information from an operations viewpoint by breaking the facility into separate systems for the ease of understanding and startup. The information for the systems is organized as follows, although some systems will not require every category: 1.
Purpose of System
2.
Safety
3.
Process Description
4.
Instrumentation and Control Systems
5.
Operating Principles and Techniques
6.
Precommissioning Procedures
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Introduction
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 7.
Startup Procedures
8.
Shutdown Procedures
9.
Setpoints (Controllers, Alarms, Shutdowns, PCVs, PSVs)
10.
Analytical Procedures
The instructions in these guidelines are based on past experience with similar plants and equipment. They are to be used as guidelines for developing detailed operating procedures customized for your plant and its actual operating conditions. These instructions are not intended in any way to supersede or supplant operating procedures and safety practices established by Samsung Total Petrochemicals Co., Ltd., nor are they intended to be used independently of equipment manufacturers’ operating instructions. In preparing these instructions, it has been assumed that all startup and operating personnel have been trained in and are knowledgeable of the operating instructions provided by the manufacturers of the equipment included in this facility. It is expected that Samsung Total Petrochemicals Co., Ltd. will revise and improve upon the operating instructions in this manual as operating experience is gained, and as required to incorporate any changes resulting from Samsung Total Petrochemicals Co., Ltd.'s Process Safety Management program. Update and maintenance of this manual is Samsung Total Petrochemicals Co., Ltd.'s responsibility and is not within Ortloff's scope of responsibility. Operating values and numbers quoted in this manual are design values. They are presented to enable the operator to have a "ball park" idea of plant operating values. Actual plant operating conditions may deviate from the design figures, yet yield satisfactory operations and products. We recommend that operating parameters such as temperatures, pressures, and flow rates be recorded on a routine basis. Good data, properly gathered and maintained, form a valuable base for plant studies and performance evaluations.
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SULFUR BLOCK
Table of Contents 2. GENERAL SAFETY ..................................................................................................... 2-1 2.1 DEFINITION OF TERMS ....................................................................................... 2-1 2.2 HYDROGEN SULFIDE (H2S) ................................................................................ 2-3 2.2.1 Description and Properties ............................................................................. 2-3 2.2.1.1 General.................................................................................................... 2-3 2.2.1.2 Toxicity Information ................................................................................. 2-3 2.2.1.3 Permissible Exposure Limits ................................................................... 2-3 2.2.1.4 Odor ........................................................................................................ 2-3 2.2.1.5 Physical Data .......................................................................................... 2-3 2.2.1.6 Reactivity Data ........................................................................................ 2-4 2.2.1.7 Corrosivity Data ....................................................................................... 2-5 2.2.1.8 Water Solubility ....................................................................................... 2-5 2.2.1.9 Other Characteristics............................................................................... 2-5 2.2.1.10 Fire and Explosion Hazard ...................................................................... 2-6 2.2.1.11 Life Hazard .............................................................................................. 2-6 2.2.2 First Aid .......................................................................................................... 2-7 2.2.3 Precautions (remember these facts) .............................................................. 2-8 2.2.4 Good Work Practices...................................................................................... 2-9 2.3 SULFUR DIOXIDE (SO2) ..................................................................................... 2-10 2.3.1 Description and Properties ........................................................................... 2-10 2.3.1.1 General.................................................................................................. 2-10 2.3.1.2 Toxicity Information ............................................................................... 2-10 2.3.1.3 Permissible Exposure Limits ................................................................. 2-10 2.3.1.4 Odor ...................................................................................................... 2-11 2.3.1.5 Physical Data ........................................................................................ 2-11 2.3.1.6 Reactivity Data ...................................................................................... 2-11 2.3.1.7 Corrosivity Data ..................................................................................... 2-12 2.3.1.8 Water Solubility ..................................................................................... 2-12 2.3.1.9 Fire and Explosion Hazard .................................................................... 2-12 2.3.1.10 Life Hazard ............................................................................................ 2-12 2.3.2 First Aid ........................................................................................................ 2-13 2.3.3 Precautions................................................................................................... 2-14 2.4 SULFUR .............................................................................................................. 2-15 2.4.1 Description and Properties ........................................................................... 2-15 2.4.1.1 General.................................................................................................. 2-15 2.4.1.2 Toxicity Information ............................................................................... 2-15 2.4.1.3 Permissible Exposure Limits ................................................................. 2-15
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General Safety
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 2.4.1.4 Odor ...................................................................................................... 2-15 2.4.1.5 Physical Data ........................................................................................ 2-15 2.4.1.6 Reactivity Data ...................................................................................... 2-16 2.4.1.7 Corrosivity Data ..................................................................................... 2-19 2.4.1.8 Other Characteristics............................................................................. 2-19 2.4.1.9 Fire and Explosion Hazard .................................................................... 2-19 2.4.1.10 Life Hazard ............................................................................................ 2-20 2.4.2 Precautions................................................................................................... 2-20 2.4.3 Fire Fighting.................................................................................................. 2-21 2.5 AMMONIA (NH3) .................................................................................................. 2-22 2.5.1 Description and Properties ........................................................................... 2-22 2.5.1.1 General.................................................................................................. 2-22 2.5.1.2 Toxicity Information ............................................................................... 2-22 2.5.1.3 Permissible Exposure Limits ................................................................. 2-22 2.5.1.4 Odor ...................................................................................................... 2-22 2.5.1.5 Physical Data ........................................................................................ 2-23 2.5.1.6 Reactivity Data ...................................................................................... 2-23 2.5.1.7 Corrosivity Data ..................................................................................... 2-25 2.5.1.8 Water Solubility ..................................................................................... 2-25 2.5.1.9 Fire and Explosion Hazard .................................................................... 2-25 2.5.1.10 Life Hazard ............................................................................................ 2-25 2.5.2 First Aid ........................................................................................................ 2-26 2.5.3 Precautions................................................................................................... 2-26 2.6 METHYLDIETHANOLAMINE (MDEA, CH3-N-(CH2-CH2-OH)2)........................... 2-28 2.6.1 Description and Properties ........................................................................... 2-28 2.6.1.1 General.................................................................................................. 2-28 2.6.1.2 Toxicity Information ............................................................................... 2-28 2.6.1.3 Permissible Exposure Limits ................................................................. 2-28 2.6.1.4 Odor ...................................................................................................... 2-28 2.6.1.5 Physical Data ........................................................................................ 2-28 2.6.1.6 Reactivity Data ...................................................................................... 2-28 2.6.1.7 Corrosivity Data ..................................................................................... 2-29 2.6.1.8 Water Solubility ..................................................................................... 2-29 2.6.1.9 Fire and Explosion Hazard .................................................................... 2-29 2.6.1.10 Life Hazard ............................................................................................ 2-29 2.6.2 First Aid ........................................................................................................ 2-29 2.6.3 Precautions................................................................................................... 2-30 2.7 SODIUM HYDROXIDE (CAUSTIC SODA, NAOH) ............................................. 2-31 2.7.1 Description and Properties ........................................................................... 2-31 2.7.1.1 General.................................................................................................. 2-31
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 2.7.1.2 Toxicity Information ............................................................................... 2-31 2.7.1.3 Permissible Exposure Limits ................................................................. 2-31 2.7.1.4 Odor ...................................................................................................... 2-31 2.7.1.5 Physical Data ........................................................................................ 2-32 2.7.1.6 Reactivity Data ...................................................................................... 2-32 2.7.1.7 Corrosivity Data ..................................................................................... 2-34 2.7.1.8 Water Solubility ..................................................................................... 2-34 2.7.1.9 Fire and Explosion Hazard .................................................................... 2-34 2.7.1.10 Life Hazard ............................................................................................ 2-35 2.7.2 First Aid ........................................................................................................ 2-35 2.7.3 Precautions................................................................................................... 2-36 2.8 SULFUR PLANT SAFETY ................................................................................... 2-37 2.8.1 Hydrogen Sulfide .......................................................................................... 2-37 2.8.2 Sulfur Dioxide ............................................................................................... 2-37 2.8.3 Sulfur Storage Tank...................................................................................... 2-38 2.8.3.1 Poisonous Gases .................................................................................. 2-38 2.8.3.2 Explosion and Fire................................................................................. 2-38 2.9 HOT WORK ......................................................................................................... 2-39 2.10 VESSEL ENTRY.................................................................................................. 2-39 2.11 PIPES AND LINES .............................................................................................. 2-41 2.11.1 General ......................................................................................................... 2-41 2.11.2 Before Breaking Lines .................................................................................. 2-42 2.11.3 When Breaking Lines ................................................................................... 2-42 2.12 ELECTRICAL EQUIPMENT ................................................................................ 2-42 2.12.1 Electrical Repairs.......................................................................................... 2-43 2.12.2 Grounding ..................................................................................................... 2-43 2.12.3 Conduit, Cables, and Wires .......................................................................... 2-43 2.12.4 Fuses ............................................................................................................ 2-43 2.12.5 Switching ...................................................................................................... 2-43 2.12.6 Hand Tools and Portable Equipment............................................................ 2-44 2.12.7 Miscellaneous ............................................................................................... 2-44 2.13 BOILERS AND OTHER DIRECT-FIRED EQUIPMENT ...................................... 2-45 2.13.1 General ......................................................................................................... 2-45 2.13.2 Boilers........................................................................................................... 2-45 2.13.2.1 Repair and Maintenance ....................................................................... 2-45 2.13.2.2 Operations ............................................................................................. 2-46 2.13.3 Direct-Fired Equipment................................................................................. 2-46 2.14 LABORATORY SAFETY ..................................................................................... 2-47 2.14.1 Good Housekeeping ..................................................................................... 2-47 2.14.2 Equipment .................................................................................................... 2-47
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 2.14.3 Chemical Sorting and Identification .............................................................. 2-47 2.14.4 Chemical Handling ....................................................................................... 2-48 2.15 MATERIAL SAFETY DATA SHEETS (MSDS) .................................................... 2-49 A. Hydrogen Sulfide B.
Sulfur Dioxide
C.
Sulfur
D.
Ammonia
E.
Methyldiethanolamine
F.
Sodium Hydroxide
G.
UOP/ESM S-2001 Sulfur Conversion Catalyst
H.
Criterion 234 Tailgas Treating Catalyst
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
2. GENERAL SAFETY General The safety information published herein is for guidance only and is not intended to supersede or replace your company's safety procedures program where a conflict of terminology or procedure may exist. Safety Considerations An employee's knowledge of the hazardous chemicals and compounds with which he will be working is one of the most basic prerequisites for his own safety, the safety of others, and the protection of equipment. All employees should review the following information occasionally to refresh their memories. New employees should study this information until it is thoroughly understood.
2.1
Definition of Terms A.
Auto-Ignition Temperature The minimum temperature to which a substance (the substance may be solid, liquid, or gaseous) must be heated to ignite independent of other ignition sources.
B.
Flammability Limits (explosive limits) When flammable vapors are mixed in air, there is a minimum concentration below which the propagation of flame does not occur upon contact with a source of ignition. There is also a maximum concentration above which propagation of flame does not occur. These boundary line concentrations of vapor in air are called flammable or explosive limits. Many people are familiar with lower and upper flammability limits in connection with engine carburetors which, when adjusted improperly, will prevent the engines from running if the fuel mixture is either too "lean" or too "rich".
C.
Flash Point Flash point is the lowest temperature of a liquid at which sufficient vapors are evolved to form an ignitable mixture with air.
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK D.
Specific Gravity (solids and liquids) Specific gravity of solids and liquids is the ratio of the weight of any solid or liquid to the weight of an equal volume of water. Therefore, if the specific gravity of a substance is a number less than one, it is lighter than water, and if the number is greater than one, it is heavier than water.
E.
Specific Gravity (gases) Specific gravity of gases is the ratio of weight of any gas to the weight of an equal volume of air. Therefore, if the specific gravity of a gas is a number less than one, it is lighter than air, and if the number is greater than one, it is heavier than air.
F.
Specific Volume Specific volume of a substance is the volume of a unit mass of the substance, i.e., the reciprocal of its density. The units used in this manual are cubic feet per pound, unless otherwise noted.
G.
Toxicity Toxicity is the ability of a chemical or compound to produce injury once it reaches a susceptible site in or on the body.
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
2.2
Hydrogen Sulfide (H2S)
2.2.1 2.2.1.1
Description and Properties General Hydrogen sulfide is a colorless, very flammable, highly toxic gas.
2.2.1.2
Toxicity Information LCLo:
600 PPM / 30 minutes
(death of inhalation)
humans
after
LCLo:
800 PPM / 5 minutes
(death of inhalation)
humans
after
LCLo (Lethal Concentration Low) is the lowest concentration of a substance in air which has been reported to have caused death in humans or animals. In other words, exposure to 600 PPM of H2S for 30 minutes or to 800 PPM of H2S for 5 minutes can cause death. 2.2.1.3
Permissible Exposure Limits TLV:
10 PPM in air
TLV (Threshold Limit Value) is the highest level of exposure to a toxic chemical at which no deleterious effect is noted. The American Conference of Government Industrial Hygienists (ACGIH) has set such levels for human exposure in industry. OSHA now uses this 10 PPM limit as the maximum allowable concentration for continuous exposure during an eight hour working day. 2.2.1.4
Odor Higher In low concentrations, H2S smells like rotten eggs. concentrations quickly damage the ability to smell and cannot be detected by the characteristic rotten egg odor.
2.2.1.5
Physical Data a. b. c. d. e. f.
Issued 30 August 2011
Melting Point: Boiling Point: Lower Explosive Limit: Upper Explosive Limit: Auto-Ignition Temperature: Vapor Specific Gravity:
General Safety
-122°F (-86°C) -77°F (-61°C) 4.3% H2S (by volume) vapor in air 46% H2S (by volume) vapor in air 500°F (260°C) 1.2 (heavier than air)
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 2.2.1.6
Reactivity Data Hydrogen sulfide is dangerously reactive with the following substances: Formula
Name
C2H4O
acetaldehyde
BaO + Hg2O + air
barium oxide + mercury oxide in air
BaO + NiO + air
barium oxide + nickel monoxide in air
BaO2
barium peroxide
BrF5
bromine pentafluoride
C6H4BrN2Cl
p-bromobenzene diazonium chloride
ClO
chlorine monoxide
ClF3
chlorine trifluoride
CrO3
chromium trioxide (chromic anhydride, chromic acid)
Cu
copper
Fe2O3·nH2O
di-iron trioxide hydrate
F2
fluorine hydrated iron oxide lead dioxide (lead peroxide)
PbO2
metal oxides metals HNO3
nitric acid
NCl3
nitrogen trichloride
NF3
nitrogen trifluoride
NI3
nitrogen triiodide oxidizing materials
OF2
oxygen difluoride
ClO3F
perchloryl fluoride
C6H5N2Cl
phenyl diazonium chloride rust
Issued 30 August 2011
Ag2C2N2O2
silver fulminate
NaOH + CaO
soda lime (a mixture of sodium hydroxide and calcium oxide)
Na
sodium
NaOH + CaO + air
sodium hydroxide + calcium oxide (lime) in air
Na2O2
sodium peroxide
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 2.2.1.7
2.2.1.8
Corrosivity Data a.
H2S readily attacks copper and most copper alloys (brass, bronze, etc.), so such materials should not be exposed to the process gases in an SRU, or to the atmosphere around an SRU.
b.
H2S can cause sulfide stress cracking (SSC) in a variety of materials as discussed in NACE Standard Material Requirements MR-01-75, "Sulfide Stress Cracking Resistant Metallic Materials for Oilfield Equipment". Most sulfur plant equipment operates at sufficiently low pressure to be outside the conditions at which SSC would be expected and so is not constructed in accordance with NACE MR-01-75. The upstream equipment (including the Knock-Out drums and/or pumps in the SRU, in some cases) is generally constructed of carbon steel and stress relieved, or is constructed of austenitic stainless steel, in accordance with NACE MR-01-75.
c.
At elevated temperature (generally, above 650°F/343°C), H2S will cause rapid corrosion of carbon steel even under low pressure conditions like those in a sulfur plant. Such steel surfaces are usually protected by refractory linings, water cooling, and/or coating the steel surface with a protective coating (such as Alonizing).
d.
H2S is considered to be non-corrosive to aluminum, glass, and Teflon®.
Water Solubility Hydrogen sulfide is soluble in water. At 60°F (15°C), approximately 3 parts (by volume) H2S will dissolve in one part water.
2.2.1.9
Other Characteristics Hydrogen sulfide is soluble in liquid sulfur and many hydrocarbons. Many porous materials, such as muds and residues, tend to absorb hydrogen sulfide. Increased temperature or mechanical disturbance tends to release the absorbed gas.
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 2.2.1.10
Fire and Explosion Hazard H2S is a dangerous fire hazard when exposed to an ignition source.
2.2.1.11
Life Hazard Hydrogen sulfide is extremely toxic even in very low concentrations. The maximum allowable concentration for continuous exposure during an eight hour working day (per current OSHA regulations) is 10 parts per million by volume, or 0.001%. Hydrogen sulfide poisoning is not cumulative like mercury, lead, and some other materials. Repeated exposure to small doses will not have the same effect as exposure to one long dose. Hydrogen sulfide is highly irritating to the eyes and mucous membranes. When inhaled, hydrogen sulfide is both an irritant and an asphyxiant. Low concentrations of 20-150 PPM cause irritation of the eyes; slightly higher concentrations may cause irritation of the upper respiratory tract, and, if exposure is prolonged, pulmonary edema may result. (Edema is a condition in which irritated tissues swell, collect fluid, and slowly excrete a watery fluid, in this case into the lungs or voice box.) The irritation action has been explained on the basis that H2S combines with the alkali present in moist surface tissues to form sodium sulfide, a caustic compound. (This compound is used by the leather industry to help remove hair from animal hides.) With higher concentrations, the action of H2S on the nervous system becomes more prominent. A 30 minute exposure to 500 PPM results in headache, dizziness, excitement, staggering gait, diarrhea, and dysuria, followed sometimes by bronchitis or bronchopneumonia. The action on the nervous system is, with small amounts, one of depression; in larger amounts, it stimulates; and, with very high amounts, the respiratory center is paralyzed. Exposure to 800-1000 PPM may be fatal in 30 minutes, and higher concentrations are instantly fatal. Fatal hydrogen sulfide poisoning may occur even more rapidly than that following exposure to a similar concentration of hydrogen cyanide. H2S does not combine with the hemoglobin of the blood; its asphyxiant action is due to paralysis of the respiratory center (which is usually the cause of death).
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK With repeated exposures to low concentrations, conjunctivitis, photophobia, corneal bullae, tearing, pain, and blurred vision are the most common findings. Higher concentrations may cause rhinitis, bronchitis, and occasionally pulmonary edema. Exposure to very high concentrations results in immediate death. Chronic poisoning results in headache, inflammation of the conjunctivae and eyelids, digestive disturbances, loss of weight, and general debility. H2S is a common air contaminant. It is an insidious poison since sense of smell may be fatigued and fail to give warning of high concentrations. The following table from the U.S. Bureau of Mines represents the degree of inhalation hazard with varying concentrations of hydrogen sulfide: HYDROGEN SULFIDE INHALATION HAZARDS PERIOD OF EXPOSURE
EXPOSURE PPM
PERCENT
10
0.001
Slight symptoms after exposure of several hours
70-150
0.007-0.015
Maximum concentration that can be inhaled for one hour without serious consequences
170-300
0.017-0.03
Dangerous after exposure of thirty minutes to one hour
400-500
0.04-0.05
Fatal in exposures of thirty minutes or less
600 & above 0.06 & above
Maximum allowable prolonged exposure
concentration
for
Concentrations exceeding 0.1% are considered rapidly fatal.
2.2.2
First Aid Anyone overcome by H2S should be removed immediately to fresh air, preferably a warm, well ventilated room. If breathing has stopped, begin artificial respiration immediately. The arm lift-back pressure method of artificial respiration is recommended. Since H2S paralyzes the respiratory system, time is very important. Administer oxygen (or carbogen, 97% oxygen and 3% carbon dioxide) if available and if someone trained with oxygen inhalation apparatus is present. Attempts to give oxygen by someone unfamiliar with the use of the apparatus may result in the loss of valuable time or may be harmful to the patient.
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK For severe irritation of the eyes, hold the lids open and pour clean water over the eyeball and lids (or use an eye irrigation fountain). Wash thoroughly in this fashion for 15 minutes. A physician, preferably an eye specialist, should be summoned immediately.
2.2.3
Issued 30 August 2011
Precautions (remember these facts) 1.
Odor is not a reliable test for the presence of hydrogen sulfide.
2.
Since hydrogen sulfide is heavier than air, it settles when released into the atmosphere and becomes more concentrated near the ground and in low places.
3.
Water at room temperature will dissolve approximately three times its volume of hydrogen sulfide. Heating or agitation of the water will cause the hydrogen sulfide to be released.
4.
Hydrogen sulfide dissolves in liquid sulfur and is a hazard in storage tanks and pits.
5.
H2S is a serious fire and explosion hazard.
6.
Low concentrations of hydrogen sulfide hinder the ability of an individual to think clearly and function properly.
7.
H2S concentrations higher than 0.06% can be fatal within 30 minutes and concentrations higher than 0.1% are rapidly fatal.
8.
In the Sulfur Block, H2S will always be present in the following locations: a.
In most of the process gas streams.
b.
In the rich and lean amine streams in the Amine Treating Unit.
c.
In the rich and lean amine streams in the Amine Regeneration Unit.
d.
In the Sour Water Stripper liquid streams.
e.
In the Acid Gas Knock-Out Drum and the SWS Knock-Out Drum liquids, TGCU quench water, TGCU solvent, and the TGCU Stripper reflux.
f.
In the amine acid gas, the TGCU recycle gas, and the SWS gas (the feed gases for the Sulfur Recovery Unit).
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
2.2.4
g.
In all of the Sulfur Recovery, Tailgas Cleanup, Tailgas Thermal Oxidation, and Sulfur Degassing system process gases, with the exception of the incinerated vent gas.
h.
In the vapors from the molten sulfur storage tank.
Good Work Practices Know the above facts and use caution when working around any equipment that may contain H2S. If H2S will be a hazard in any operation:
Issued 30 August 2011
1.
Make adequate plans to cope with any situation that may develop.
2.
Adequate respiratory protective equipment is essential; have it available and use it. Persons who must work in an atmosphere contaminated with H2S should use either a self-contained breathing unit or a hose mask with a hand-operated blower.
3.
Observe the wind direction. Stay upwind if possible and warn others who may be downwind.
4.
Keep ignition sources away from the area.
5.
Two men should always be present when opening a flange or performing any other work where the release of H2S is possible.
6.
When one man is working in an area of potential H2S exposure, the other man should concentrate on the wind direction and on the action of the man performing the work. At the first sign of loss of coordination or illogical action, the worker should be removed immediately to fresh air. If a man is being overcome by H2S, he will be outwardly sluggish and poorly coordinated (although inwardly he will be peacefully unconcerned) and he will then begin illogical actions as his mind begins to imagine things. Any sign of actions that are out of the ordinary is a last minute warning.
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
2.3
Sulfur Dioxide (SO2)
2.3.1 2.3.1.1
Description and Properties General Sulfur dioxide is a colorless, nonflammable, highly toxic gas.
2.3.1.2
Toxicity Information LCLo:
400 PPM / 1 minute
(death of inhalation)
humans
after
LCLo (Lethal Concentration Low) is the lowest concentration of a substance in air which has been reported to have caused death in humans or animals. In other words, exposure to 400 PPM of SO2 for 1 minute can cause death. TCLo:
3 PPM / 5 days
(pulmonary system effects on humans after inhalation)
TCLo:
4 PPM / 1 minute
(pulmonary system effects on man after inhalation)
TCLo (Toxic Concentration Low) is the lowest concentration of a substance in air to which humans or animals have been exposed for any given period of time that has produced any toxic effect in humans or produced a carcinogenic, neoplastigenic, or teratogenic effect in animals or humans. In other words, exposure to 3 PPM SO2 for 5 days or to 4 PPM SO2 for 1 minute have both been reported to have toxic effects on the human pulmonary system. 2.3.1.3
Permissible Exposure Limits TLV:
2 PPM in air
TLV (Threshold Limit Value) is the highest level of exposure to a toxic chemical at which no deleterious effect is noted. The American Conference of Government Industrial Hygienists (ACGIH) has set such levels for human exposure in industry. OSHA regulations set a limit of 5 PPM TWA (Time Weighted Average) concentration for continuous exposure during an eight hour working day.
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 2.3.1.4
Odor Sulfur dioxide has a pungent, suffocating odor that can be detected at very low concentrations, 0.3 to 1.0 PPM, possibly by taste rather than odor.
2.3.1.5
Physical Data a. b. c. d. e. f.
2.3.1.6
Melting Point: Boiling Point: Lower Explosive Limit: Upper Explosive Limit: Auto-Ignition Temperature: Vapor Specific Gravity:
-104°F (-76°C) 14°F (-10°C) N/A (SO2 will not burn) N/A N/A 2.2 (heavier than air)
Reactivity Data Sulfur dioxide is dangerously reactive with the following substances: Formula
Name
C3H4O
acrolein
Al
aluminum
CsHC2
cesium hydrogencarbide
Cs2O
cesium oxide
x-ClO3
chlorates
ClF3
chlorine trifluoride
Cr
chromium
FeO
ferrous oxide
F2
fluorine lithium acetylene carbide diammino
Issued 30 August 2011
Mn
manganese
KHC2
potassium carbide
KClO3
potassium chlorate
Rb2C2
rubidium carbide
Na
sodium
Na2C2
sodium carbide
SnO
tin monoxide
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK Sulfur dioxide is incompatible with the following substances: Formula
Name halogens or interhalogens
LiNO3
lithium nitrate
x-C2H
metal acetylides metal oxides metals polymeric tubing sodium hydride
NaH
2.3.1.7
2.3.1.8
Corrosivity Data a.
Dry SO2 causes only mild corrosion of carbon steel and stainless steel.
b.
Wet SO2 (sulfurous acid) is very corrosive to carbon steel and most stainless steels. Certain alloy materials (Carpenter ® 20Cb-3 , for instance) are relatively impervious to attack by wet SO2.
c.
SO2 is considered to be non-corrosive to graphite, glass, and Teflon®.
Water Solubility Sulfur dioxide will dissolve readily in water to form a weak solution of sulfurous acid (H2SO3). At 60°F (15°C), about 50 parts (by volume) SO2 will dissolve in one part water.
2.3.1.9
Fire and Explosion Hazard None
2.3.1.10
Life Hazard Like hydrogen sulfide, sulfur dioxide is extremely toxic in very low concentrations. The serious life threat is through paralysis of the respiratory system. The maximum allowable concentration for continuous exposure during an eight hour working day (per current OSHA regulations) is 5 parts per million by volume, or 0.0005%. Sulfur dioxide is highly irritating to skin, eyes, and mucous membranes. When inhaled, sulfur dioxide is very irritating and can cause pulmonary distress. This gas is dangerous to the eyes, as it
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK causes irritation at 20 PPM and inflammation of the conjunctiva. It has a suffocating odor and is a corrosive and poisonous material. In moist air or fogs, it combines with water to form sulfurous acid, but is only slowly oxidized to sulfuric acid. Concentrations of 6-12 PPM cause immediate irritation of the nose and throat, while 0.3-1 PPM can be detected by the average individual, possibly by taste rather than by sense of smell. 3 PPM has an easily noticeable odor and 20 PPM is the least amount which is irritating to the eyes. 10,000 PPM is an irritant to moist areas of the skin within a few minutes of exposure. SO2 chiefly affects the upper respiratory tract and the bronchi. It may cause edema of the lungs or glottis, and can produce respiratory paralysis. (Edema is a condition in which irritated tissues swell, collect fluid, and slowly excrete a watery fluid, in this case into the lungs or voice box.) This material is so irritating that it provides its own warning of toxic concentrations. 400-500 PPM is immediately dangerous to life, and 50-100 PPM is considered to be the maximum permissible concentration for exposures of 30-60 minutes. Excessive exposures to high enough concentrations of this material can be fatal. Its toxicity is comparable to that of hydrogen chloride. However, less than fatal concentrations can be borne for fair periods of time with no apparent permanent damage. It is used as a fumigant, insecticide and fungicide, and a chemical preservative food additive. It is a common air contaminant.
2.3.2
First Aid In cases of inhalation, remove the victim to fresh air and begin artificial respiration immediately if breathing has ceased. The arm lift-back pressure method of artificial respiration is recommended. If an oxygen apparatus is available, oxygen (100%) should be administered only by someone trained in the use of the apparatus. Preferably, oxygen should be administered against a positive exhalation pressure of 1.25 inches of water. Oxygen inhalation must be continued as long as necessary to maintain the normal color of the skin and mucous membranes. In cases of severe exposure, the patient should breathe 100% oxygen under positive exhalation pressure for 30 minute periods every hour for at least 3 hours.
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK If there are no signs of lung congestion at the end of this period, and if the breathing is easy and the color is good, oxygen inhalation may be discontinued. Throughout this time, the patient should be kept comfortably warm, but not hot. For irritation of the eyes, flush them with large amounts of warm water for at least 15 minutes. It is advisable to irrigate the eyes gently with water at room temperature in order to minimize additional pain and discomfort. Take the patient to a physician, preferably an eye specialist, at once.
2.3.3
Precautions Special precautions should be observed when fighting sulfur fires. Sulfur fires should be approached from an upwind direction if possible, and respiratory equipment should be used in the case of larger fires or when fires are in enclosed areas. SO2 is always present in the following locations:
Issued 30 August 2011
1.
In all of the Sulfur Recovery Unit process gases downstream of the Reactor Furnace, up through and including the TGCU Reactor in the TGCU Unit.
2.
In the stack or flare gases in any process where sulfur or hydrogen sulfide is being burned, including the Thermal Oxidizer.
3.
In the vapors from the molten sulfur storage tank.
4.
In the fumes from sulfur fires.
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
2.4
Sulfur
2.4.1 2.4.1.1
Description and Properties General Sulfur is a yellow solid at normal ambient temperatures. However, it is normally handled in bulk quantities in plant operations as a liquid.
2.4.1.2
Toxicity Information Sulfur is nontoxic. Sulfur dust in air can produce irritation of the human eye at concentrations of 6 PPM or above, resulting in its classification as a nuisance dust. Repeated inhalation can cause irritation to the mucous membranes.
2.4.1.3
Permissible Exposure Limits There are no standards or regulations concerning sulfur.
2.4.1.4
Odor Pure sulfur is odorless.
2.4.1.5
Physical Data a. b. c.
d. e. f.
Issued 30 August 2011
Melting Point: 246°F (119°C) Boiling Point: 832°F (444°C) Auto-Ignition Temperature: 450°F (232°C) for liquid sulfur 374°F (190°C) for sulfur dust suspended in air Flash Point: 405°F (207°C) Liquid Specific Gravity: 1.8 (almost twice as heavy as water) Color Pure sulfur is bright yellow when solid. Sulfur produced by Claus sulfur plants may be contaminated with hydrocarbons, causing the color to be orange, green, tan, brown, gray, or black. The color of liquid sulfur ranges from bright yellow to dark orange (almost red), depending on its temperature.
General Safety
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 2.4.1.6
Reactivity Data Sulfur can react violently with the following substances: Formula
Name alkali metal nitrides
Issued 30 August 2011
Al
aluminum
Al + Cu
aluminum + copper
Al + Nb2O5
aluminum + niobium pentoxide
NH3
ammonia
NH4NO3
ammonium nitrate
NH4ClO4
ammonium perchlorate
Ba(BrO3)2·H2O
barium bromate
BaC2
barium carbide
Ba(ClO3)2·H2O
barium chlorate
Ba(IO3)2
barium iodate
B
boron
BrF5
bromine pentafluoride
BrF3
bromine trifluoride
Cd
cadmium
Ca
calcium
Ca(BrO3)2·H2O
calcium bromate
CaC2
calcium carbide
Ca(ClO3)2
calcium chlorate
Ca(ClO)2
calcium hypochlorite
Ca(IO3)2
calcium iodate
Ca3P2
calcium phosphide
Ca + VO + H2O
calcium + vanadium oxide + water carbides
Cs3N
cesium nitride
C + impurities
charcoal
ClO2
chlorine dioxide
ClO
chlorine monoxide
ClF3
chlorine trifluoride
ClO3
chlorine trioxide
Cr(ClO)2
chromium oxychloride (chromyl chloride)
CrO3
chromium trioxide (chromic acid) anhydride, chromic
Cu + x-ClO3
copper + chlorates
As2S3
diarsenic trisulfide
General Safety
Page 2-16
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK Formula
Name
Cl2O
dichlorine monoxide
(C2H5)2O
diethyl ether fiberglass + iron filings fluorine
F2
halogenates halogenites halogens Ag7NO11
heptasilver nitrate octaoxide
CxHy
hydrocarbons
In
indium interhalogens
IF5
iodine pentafluoride
IO5
iodine pentoxide
C
lampblack (carbon black)
Pb(ClO3)2
lead chlorate
PbCl2
lead chloride
Pb(ClO2)2
lead chlorite
PbCrO4
lead chromate
PbO2
lead dioxide (lead peroxide)
Li
lithium
Li + NH3
lithium dissolved in ammonia
Li2C2
lithium carbide
Mg
magnesium
Mg(BrO3)2·6H2O
magnesium bromate
Mg(ClO3)2
magnesium chlorate
Mg(IO3)2·4H2O
magnesium iodate
Hg(NO3)2·H2O
mercuric nitrate
HgO
mercury(II) oxide (mercuric oxide)
Hg2O
mercury(I) oxide (mercurous oxide)
x-C2H
metal acetylides of carbides
x-(ClO3)n
metal chlorates
x-(zO3)n
metal halogenates
x-On
metal oxides metals
Issued 30 August 2011
RbC2H
monorubidium acetylide (rubidium acetylene carbide)
Ni
nickel
General Safety
Page 2-17
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK Formula
Name
NO2
nitrogen dioxide
Os
osmium oxidants
Issued 30 August 2011
Pd
palladium
x-(ClO4)n
inorganic perchlorates
x-(MnO4)n
permanganates
P
phosphorus (phosphorus, red)
P4
phosphorus, white (phosphorus, yellow)
P2O3
phosphorus trioxide
K
potassium
KBrO3
potassium bromate (bromic acid)
KClO3
potassium chlorate
KClO
potassium chlorite (potassium hypochlorite)
KIO3
potassium iodate
KNO3 + As2S3
potassium nitrate (saltpeter) + arsenic sulfide
K3N
potassium nitride
KClO4
potassium perchlorate
KMnO4
potassium permanganate
K + SnI4
potassium + tin(IV) iodide (stannic iodide)
Rh
rhodium
Rb
rubidium
Se
selenium
SeC2
selenium carbide
AgBrO3
silver bromate
AgClO3
silver chlorate
AgClO2
silver chlorite
AgNO3
silver nitrate
Ag2O
silver oxide
Na
sodium
NaBrO3
sodium bromate
NaClO3
sodium chlorate
NaClO2
sodium chlorite
NaH
sodium hydride
NaIO3
sodium iodate
NaNO3 + charcoal
sodium nitrate + charcoal
Na2O2
sodium peroxide
General Safety
Page 2-18
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
2.4.1.7
Formula
Name
Na + SnI4
sodium + tin(IV) iodide (stannic iodide)
SrC2
strontium carbide
SrC2+ Se
strontium carbide + selenium
SCl2
sulfur dichloride
(C6H5)4Pb
tetraphenyl lead
Tl2O3
thallic oxide (thallium peroxide)
Th
thorium
ThC2
thorium carbide
Sn
tin
U
uranium
UC2
uranium carbide (uranium dicarbide)
Zn
zinc
Zn(BrO3)2·6H2O
zinc bromate
Zn(ClO3)2
zinc chlorate
Zn(IO3)2
zinc iodate
Corrosivity Data Dry sulfur is not corrosive but in the presence of moisture it will attack steel rapidly.
2.4.1.8
2.4.1.9
Other Characteristics a.
Both hydrogen sulfide and sulfur dioxide will dissolve in liquid sulfur.
b.
At temperatures up to about 317°F (158°C), the viscosity of pure liquid sulfur decreases as the temperature increases. As the temperature increases from 317°F to 370°F (158°C to 188°C), the viscosity of pure liquid sulfur rises rapidly to a tremendously high maximum, causing the liquid to become a dark, sticky, plastic material impossible to pump. However, sulfur produced by Claus sulfur plants contains dissolved H2S that lowers the viscosity of the molten sulfur so that fluidity is not normally a concern, regardless of the temperature.
Fire and Explosion Hazard a.
Solid Sulfur The primary hazard in handling solid sulfur results from the fact that sulfur dust suspended in the air ignites easily. Even though
Issued 30 August 2011
General Safety
Page 2-19
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK the explosion hazard is considered moderate, an explosion occurring in a confined area could cause considerable damage. Sulfur, being a very poor conductor of electricity, tends to develop static electric charges when it is in motion. Ignition of sulfur dust by static-caused sparks is not uncommon. Frictional heat in equipment has also been responsible for starting sulfur fires. b.
Liquid Sulfur The fire hazards of liquid sulfur result primarily from the low ignition point of sulfur and from the presence of hydrogen sulfide.
2.4.1.10
Life Hazard a.
Solid Sulfur Solid elemental sulfur is considered to be more of a nuisance dust with a very low toxicity. Occasionally, sulfur dust will irritate the inner surfaces of the eyelids.
b.
Molten Sulfur Molten sulfur is capable of inflicting severe burns.
2.4.2
Issued 30 August 2011
Precautions 1.
Employees operating equipment containing molten sulfur should wear clothing capable of protecting the chest and arms, trousers without cuffs, high top shoes, safety glasses with side shields, and heat resistant gloves. When making connections or other changes in molten sulfur piping, full-face shields (in addition to safety glasses) and leather protective clothing may be needed.
2.
Every reasonable step should be taken to minimize formation of dust during the handling of solid sulfur.
3.
Eliminate ignition sources where sulfur dust may be produced. Enclosed areas are considered Class II hazardous locations according to the United States National Electrical Code. Where static electricity is a hazard, equipment should be grounded.
4.
Eliminate ignition sources near liquid sulfur where H2S may be liberated.
General Safety
Page 2-20
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 5.
2.4.3
Issued 30 August 2011
Sulfur spills and drips should be cleaned up to avoid accumulations of sulfur. Sulfur dust should never be allowed to accumulate in buildings.
Fire Fighting 1.
Small sulfur fires may be extinguished by smothering them with dirt or sand or by using a fire extinguisher. Water is the most satisfactory extinguishing agent but should be used as a fine spray or fog. Steam smothering can be used in storage pits and in other relatively small enclosures. Carbon dioxide is also a satisfactory fire extinguishing agent.
2.
Sulfur fires should be approached very carefully, from the upwind side if possible, because burning sulfur emits highly toxic fumes of sulfur dioxide.
General Safety
Page 2-21
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
2.5
Ammonia (NH3)
2.5.1 2.5.1.1
Description and Properties General Ammonia is a colorless, flammable, toxic gas.
2.5.1.2
Toxicity Information LCLo:
5,000 PPM / 1 minute
(death of inhalation)
mammals
after
LCLo (Lethal Concentration Low) is the lowest concentration of a substance in air which has been reported to have caused death in humans or animals. In other words, exposure to 5,000 PPM of NH3 for 1 minute can cause death. TCLo:
20 PPM
(toxic and irritant effects on humans after inhalation)
TCLo (Toxic Concentration Low) is the lowest concentration of a substance in air to which humans or animals have been exposed for any given period of time that has produced any toxic effect in humans or produced a carcinogenic, neoplastigenic, or teratogenic effect in animals or humans. In other words, exposure to 20 PPM NH3 has been reported to have toxic and irritant effects on humans. 2.5.1.3
Permissible Exposure Limits TLV:
25 PPM in air
TLV (Threshold Limit Value) is the highest level of exposure to a toxic chemical at which no deleterious effect is noted. The American Conference of Government Industrial Hygienists (ACGIH) has set such levels for human exposure in industry. OSHA regulations set a limit of 50 PPM TWA (Time Weighted Average) concentration for continuous exposure during an eight hour working day. 2.5.1.4
Odor Ammonia has a pungent odor that can be detected at low concentrations, 20 to 50 PPM.
Issued 30 August 2011
General Safety
Page 2-22
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 2.5.1.5
Physical Data a. b. c. d. e. f.
2.5.1.6
Melting Point: Boiling Point: Lower Explosive Limit: Upper Explosive Limit: Auto-Ignition Temperature: Vapor Specific Gravity:
-108°F (-78°C) -28°F (-33°C) 15% NH3 (by volume) in air 28% NH3 (by volume) in air 1204°F (651°C) 0.6 (lighter than air)
Reactivity Data Ammonia is incompatible with the following substances: Formula
Name
C2H4O
acetaldehyde
C3H4O
acrolein
H8N2O8S2
ammonium peroxo disulfate
Sb
antimony
SbH3
antimony hydride
B
boron boron halides
BI3
boron triiodide
BrF5
bromine pentafluoride
HClO3
chloric acid
ClN3
chlorine azide
ClO
chlorine monoxide
ClF3
chlorine trifluoride
x-ClO2
chlorites
SiHxCl4-x
chlorosilane
CrO3
chromium trioxide (chromic anhydride, chromic acid)
CrCl2
chromyl chloride
Cl2O
dichlorine oxide
C2H4Cl2 + NH3 (liq)
ethylene dichloride + liquid ammonia
C2H4O
ethylene oxide
Au
gold
AuCl3
gold (III) chloride halogens
Issued 30 August 2011
C3N6Cl6
hexachloromelamine
H4N2 + Li, Na, etc.
hydrazine + alkali metals
HBr
hydrogen bromide (hydrobromic acid)
General Safety
Page 2-23
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK Formula
Name
HOCl
hypochlorous acid
H2O2
hydrogen peroxide
Mg(ClO4)2
magnesium perchlorate
Hg
mercury
HNO3
nitric acid
NO2
nitrogen dioxide (nitrogen peroxide)
N2O4
nitrogen tetraoxide
NCl3
nitrogen trichloride
NF3
nitrogen trifluoride
NO2Cl
nitryl chloride
OF2
oxygen difluoride
O2 + Pt
oxygen + platinum
P2O5
phosphorus pentoxide
P2O3
phosphorus trioxide
C6H3N3O7
picric acid
K + AsH3
potassium + arsine
KClO3
potassium chlorate
K3Fe(CN)6
potassium ferricyanide
K2Hg(CN)4
potassium mercuric cyanide
K + PH3
potassium + phosphine
K + NaNO2
potassium + sodium nitrite
Ag
silver
AgCl
silver chloride
AgNO3
silver nitrate
Ag2O
silver oxide
Na + CO
sodium + carbon monoxide
S
sulfur
SCl2
sulfur dichloride
TeCl4
tellurium chloride tellurium hydropentachloride
Issued 30 August 2011
(CH3)4N2COH2
tetramethyl ammonium amide
SOCl2
thionyl chloride
N3S4Cl
thiotrithiazyl chloride
C3H3N6Cl3
trichloromelamine
O3F2
trioxygen difluoride
General Safety
Page 2-24
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 2.5.1.7
2.5.1.8
Corrosivity Data a.
Iron and carbon steel are recommended for ammonia service.
b.
Moist ammonia will rapidly attack copper, tin, zinc, and their alloys.
c.
Mixtures of ammonia and hydrogen sulfide are often very corrosive to carbon and stainless steels when wet. The corrosivity appears to increase when hydrogen cyanide (HCN) is present. (Hydrogen cyanide is a common contaminant in the sour water processed in many refineries.)
d.
Ammonia is considered to be non-corrosive to glass and Teflon®.
Water Solubility Ammonia will dissolve very readily in water. At 60°F (15°C), about 800 parts (by volume) NH3 will dissolve in one part water.
2.5.1.9
Fire and Explosion Hazard Ammonia is a low fire hazard when exposed to heat or flame because it is difficult to ignite. It is a moderate explosion hazard when exposed to flame or fire. Air-ammonia mixtures can detonate in a fire.
2.5.1.10
Life Hazard Ammonia is toxic in moderate concentrations. However, its pungent odor will provide ample warning of its presence, so it is unlikely that an individual would unknowingly become overexposed. The maximum allowable concentration for continuous exposure during an eight hour working day (per current OSHA regulations) is 50 parts per million by volume, or 0.005%. Ammonia is highly irritating to the eyes and mucous membranes. When inhaled, ammonia is both an irritant and an asphyxiant, and can cause respiratory distress. This gas is dangerous to the eyes, as it causes irritation at 40-100 PPM. Prolonged exposure to 700 PPM or more can cause extensive injuries to the eyes - irritation, hemorrhages, swollen lids, corneal ulcers, even partial or total loss of sight. Ammonia will also irritate the skin, particularly if the skin is moist, to the point of causing chemical burns from prolonged exposure.
Issued 30 August 2011
General Safety
Page 2-25
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK The life hazard from ammonia is due to its damage to the lungs when inhaled. This material is so irritating that it provides its own warning well below toxic concentrations. Ammonia can usually be detected at levels of 20-50 PPM. There will be noticeable irritation of the eyes and nasal passages when exposed to 100 PPM, severe irritation of the throat, nasal passages, and upper respiratory tract at 400 PPM, and severe eye irritation at 700 PPM. At 1700 PPM, there will be severe coughing and bronchial spasms, and an exposure of 30 minutes or less may be fatal. Concentrations of 5000 PPM and above are fatal almost immediately, causing serious edema of the lungs, strangulation, and asphyxiation. (Edema is a condition in which irritated tissues swell, collect fluid, and slowly excrete a watery fluid, in this case into the lungs.)
2.5.2
First Aid Anyone overcome by ammonia should be removed immediately to fresh air, preferably a warm, well-ventilated room. If breathing has stopped, begin artificial respiration immediately (by trained personnel only). The arm lift-back pressure method of artificial respiration is recommended. Be aware that excessive force during artificial respiration will further injure the lungs. Administer oxygen if available and if someone trained with oxygen inhalation apparatus is present. For severe irritation of the eyes, hold the lids open and pour clean water over the eyeball and lids (or use an eye irrigation fountain). Wash thoroughly in this fashion for 15 minutes. A physician, preferably an eye specialist, should be summoned immediately.
2.5.3
Precautions In this part of the complex, ammonia will usually be found mixed with hydrogen sulfide. Ammonia will always be present in the following locations:
Issued 30 August 2011
1.
In the process gas and liquid streams in the Sour Water Stripping Unit.
2.
In the Sour Water Stripper off-gas feeding the sulfur plant.
3.
In the SWS Gas Knock-Out Drum liquids, the TGCU quench water, and the TGCU Stripper reflux.
General Safety
Page 2-26
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 4.
Issued 30 August 2011
In the overhead gas from the TGCU Stripper, and possibly in the TGCU recycle gas.
General Safety
Page 2-27
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
2.6
Methyldiethanolamine (MDEA, CH3-N-(CH2-CH2-OH)2)
2.6.1 2.6.1.1
Description and Properties General MDEA is a colorless, viscous liquid.
2.6.1.2
Toxicity Information Ingestion of MDEA is moderately toxic, and may cause nausea, vomiting, and abdominal discomfort. Single dose oral toxicity is low. MDEA can cause moderate irritation of the eyes, with possible corneal damage. Prolonged or repeated exposure can cause skin irritation or burns. Inhalation of vapors is unlikely at room temperature due to its low vapor pressure. MDEA at elevated temperature may produce sufficient vapor to cause moderately severe eye and upper respiratory irritation.
2.6.1.3
Permissible Exposure Limits There are no standards or regulations concerning MDEA.
2.6.1.4
Odor MDEA has a slight odor of amine.
2.6.1.5
Physical Data a. b. c. d. e. f. g. h.
2.6.1.6
Melting Point: Boiling Point: Vapor Pressure: Flash Point: Lower Explosive Limit: Upper Explosive Limit: Specific Gravity: Color:
-6°F (-21°C) 477°F (247°C) <0.01 mm Hg @ 68°F (20°C) 260°F (127°C) not determined not determined 1.042 (about the same as water) Clear to light straw color
Reactivity Data MDEA is incompatible with strong oxidizers and strong acids. MDEA should not be allowed to contact sodium nitrite (NaNO2) or other nitrosating agents, as nitrosamines (suspected cancer-causing agents) could be formed.
Issued 30 August 2011
General Safety
Page 2-28
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 2.6.1.7
Corrosivity Data
2.6.1.8
a.
MDEA and MDEA-water solutions are generally non-corrosive to carbon and stainless steels.
b.
Acid gas (H2S and/or CO2) dissolved in MDEA-water solutions can cause appreciable corrosion of carbon steel, particularly in areas subjected to erosion.
c.
Copper, copper alloys, and galvanized steel should not be exposed to MDEA. Aluminum should not be exposed to MDEA at elevated temperatures.
d.
Oxygen will degrade MDEA by forming corrosive organic acids.
e.
MDEA is considered to be non-corrosive to glass, asbestos, Teflon®, and EPDM.
Water Solubility MDEA is completely soluble in water.
2.6.1.9
Fire and Explosion Hazard MDEA is considered a slight fire hazard when exposed to heat or flame.
2.6.1.10
Life Hazard The toxicity of MDEA is low. Ingestion of MDEA can cause nausea and vomiting. MDEA will irritate the skin and eyes, and can cause damage to the eyes. If heated, sufficient MDEA vapor may be evolved to irritate the nose and/or eyes.
2.6.2
First Aid If large amounts of MDEA are ingested, induce vomiting, then take the patient to a physician. If MDEA vapors are inhaled, remove the patient to fresh air. A physician should be consulted. In case of eye contact, flush the eyes with large amounts of water for at least 15 minutes. Take the patient to a physician, preferably an eye specialist, at once. In case of skin contact, flush the affected area with plenty of water. If exposure has produced a burn, it should be treated like a thermal burn,
Issued 30 August 2011
General Safety
Page 2-29
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK with treatment based on the physician's judgment. Contaminated clothing should be removed and washed before reuse.
2.6.3
Issued 30 August 2011
Precautions 1.
When handling MDEA, employees should wear protective clothing resistant to MDEA. The choice of gloves, boots, apron, or full-body suit will depend on the tasks to be performed. Chemical-resistant goggles should always be worn.
2.
Good general ventilation should be sufficient for most operations. If vapor concentrations are high, use local exhaust ventilators.
3.
If irritation of the nose and/or respiratory system is experienced, use an approved air-purifying respirator.
4.
Minimize the exposure of MDEA to oxygen to avoid forming organic acids.
General Safety
Page 2-30
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
2.7
Sodium Hydroxide (Caustic Soda, NaOH)
2.7.1 2.7.1.1
Description and Properties General Pure sodium hydroxide is a white solid. When dissolved in water, NaOH forms a clear, colorless or water-white, strongly alkaline liquid.
2.7.1.2
Toxicity Information Sodium hydroxide has acute oral toxicity if ingested. It will cause severe burns, including perforation and scarring, on the mouth, throat, esophagus, and stomach, and death may result. Cases of squamous cell carcinoma of the esophagus have occurred years after ingestion. Sodium hydroxide, both solid and in solution, has a markedly corrosive action on all body tissues. Inhalation of dust or mist can cause injury to the entire respiratory tract. The effects of inhalation depend on the severity of the exposure, ranging from mild irritation of the mucous membranes to severe pneumonitis. Contact with the eyes may cause irritation and, with greater exposure, severe burns and possible blindness. Skin contact may cause burns, frequently with deep ulceration and scarring. Prolonged contact, even with dilute solutions, can cause tissue damage.
2.7.1.3
Permissible Exposure Limits TLV:
2 mg/m3 in air (approximately 2 PPM by weight)
TLV (Threshold Limit Value) is the highest level of exposure to a toxic chemical at which no deleterious effect is noted. The American Conference of Government Industrial Hygienists (ACGIH) has set such levels for human exposure in industry. OSHA regulations set a limit of 2 mg/m3 TWA (Time Weighted Average) concentration for continuous exposure during an eight hour working day. 2.7.1.4
Odor Sodium hydroxide has no odor, in pure form or when dissolved in water.
Issued 30 August 2011
General Safety
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 2.7.1.5
Physical Data Solid Form a. b. c. d. e.
Melting Point: Boiling Point: Auto-Ignition Temperature: Flash Point: Specific Gravity:
f.
Color:
608°F (320°C) 2534°F (1390°C) Not combustible N/A 2.1 (more than twice as heavy as water) White
Water Solutions a. b. c. d. e. f.
2.7.1.6
Melting Point: Boiling Point: Auto-Ignition Temp.: Flash Point: Specific Gravity: Color:
25 wt% -2°F (-19°C) 232°F (111°C) Not combustible N/A 1.27 Colorless or water-white
50 wt% 50°F (10°C) 288°F (142°C) Not combustible N/A 1.53 Colorless or water-white
Reactivity Data Adding water to sodium hydroxide or sodium hydroxide solutions may cause localized overheating and spattering. Under the proper conditions, sodium hydroxide can react violently with the following substances:
Issued 30 August 2011
Formula
Name
C2H2O
acetaldehyde
C2H2O2
acetic acid
C2H6O3
acetic anhydride
C3H4O
acrolein
C3H3N
acrylonitrile
C3H6O
allyl alcohol
C3H5Cl
allyl chloride
Al
aluminum
ClF3
chlorine trifluoride
CHCl3 + CH3OH
chloroform + methanol
General Safety
Page 2-32
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK Formula
Name
C3H7ClO2
chlorohydrin (chlorhydrin)
C7H7ClO
4-chloro-2-methylphenol
C7H6ClNO2
chloronitrotoluene
ClHSO3
chlorosulfonic acid (chlorosulfuric acid)
C9H8O
cinnamaldehyde
Cu
copper
CN4
cyanogen azide
B2H6
diborane (boron hydride)
C2H2Cl2
1,2-dichloroethylene
C2H4F2
difluoroethane
C3H5NO
ethylene cyanohydrin (hydracrylonitrile)
C2H2O2
glyoxal
HCl
hydrochloric acid (hydrogen chloride)
HF
hydrofluoric acid (hydrogen fluoride)
C6H6O2
hydroquinone
Mg
magnesium
C4H2O3
maleic anhydride
CH3OH + C6H2Cl4
methanol + tetrachlorobenzene
C7H7NO3
4-methyl-2-nitrophenol 3-methyl-2-penten-4-yn-1-ol
HNO3
nitric acid
C2H5NO2
nitroethane (forms shock-sensitive salts)
CH3NO2
nitromethane (forms shock-sensitive salts)
CxH2x+1NO2
nitroparaffins (forms shock-sensitive salts)
C3H7NO2
nitropropane (forms shock-sensitive salts)
H2SO4 SO3
oleum (fuming sulfuric acid)
C5H12O
pentol
P
phosphorus
P2O5
phosphorus pentoxide
C3H4O2
ß-propiolactone (2-oxetanone) strong mineral or organic acids
Issued 30 August 2011
H2SO4
sulfuric acid
C6H2Cl4
1,2,4,5-tetrachlorobenzene
C4H8O
tetrahydrofuran
Sn
tin
C2H3Cl3O
1,1,1-trichloroethanol
General Safety
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
2.7.1.7
2.7.1.8
Formula
Name
C2HCl3
trichloroethylene
CCl3NO2
trichloronitromethane
H2O
water
Zn
zinc
Zr
zirconium
Corrosivity Data a.
At ambient temperature, sodium hydroxide solutions will cause only slight corrosion of carbon steel.
b.
Carbon steel can experience caustic embrittlement and intergranular corrosion when exposed to sodium hydroxide solutions at elevated temperature. Stress relieving the carbon steel after fabrication may reduce the susceptibility to this.
c.
If sodium hydroxide solutions must be handled at elevated temperatures, special resistant alloys should be used. Nickel and copper are common components in such alloys.
d.
Aluminum, tin, zinc, and their alloys are rapidly attacked by sodium hydroxide solutions, and should not be allowed to come in contact with NaOH.
e.
Sodium hydroxide is considered to be non-corrosive to glass, natural rubber, EPDM, and Teflon®.
Water Solubility Sodium hydroxide will dissolve readily in water, with the amount depending on the solution temperature. If a solution of sodium hydroxide is cooled below its saturation temperature, it will precipitate solid hydrates. At 60°F (15°C), sodium hydroxide will dissolve in water to produce solutions exceeding 50 wt% NaOH.
2.7.1.9
Fire and Explosion Hazard Sodium hydroxide and its water solutions are not flammable. However, adding water to NaOH or solutions of NaOH can cause localized overheating due to its heat of dilution. Sodium hydroxide will generate gaseous hydrogen (which is flammable and/or explosive) when in contact with aluminum, copper, tin, zinc, and their alloys.
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SULFUR BLOCK 2.7.1.10
Life Hazard Sodium hydroxide will cause damage to any tissue it contacts. It is acutely toxic if swallowed, causing severe burns and scarring to the mouth, throat, esophagus, and stomach, and may lead to death. Squamous cell carcinoma of the esophagus can occur years after the exposure. Contact with the skin, eyes, nose, or respiratory passages can result in severe burns and scarring. In the case of eye contact, blindness can occur rapidly.
2.7.2
First Aid If swallowed, do not induce vomiting - this will cause further damage to the throat and esophagus. Dilute by giving water to the patient immediately. Vinegar, 1% acetic acid solution, citrus fruit juices, or 5% citric acid solution may also be administered to help neutralize the alkaline solution. Follow this with milk, egg white in water, or milk of magnesia. Keep the patient warm and still, and summon a physician immediately. If dust or mist is inhaled, remove the patient to fresh air at once. If breathing has stopped, begin artificial respiration immediately. The air lift-back pressure method of artificial respiration is recommended. Keep the patient warm and still, and summon a physician immediately. In case of eye contact, immediately begin flushing the eyes with large amounts of water, preferably with an eye wash fountain. Continue flushing for at least 15 minutes, forcibly holding the eyelids apart and rotating the eyeball, to ensure complete irrigation of all eye and lid tissue. A physician, preferably an eye specialist, should be summoned immediately. In case of skin contact, immediately flush the affected areas with large amounts of water. If large areas of the body are contaminated, or if clothing has been penetrated to the skin, immediately use a safety shower, preferably removing clothing while under the shower. Continue flushing the areas for at least 15 minutes. If available, follow the water flush with a generous application of vinegar or 1% acetic acid solution to neutralize the residual NaOH. After the acid treatment, apply a good protective dressing as with any other burn and take the patient to a physician. Contaminated clothing should be washed before reuse. Contaminated leather articles (shoes, belts, etc.) should be discarded.
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SULFUR BLOCK 2.7.3
Issued 30 August 2011
Precautions 1.
Employees should wear impervious rubber, neoprene, or vinyl gloves, boots, and overalls or full-body suits, plus tightly fitting goggles and face shields.
2.
If dust or mist is present, use an appropriate respirator.
3.
When diluting sodium hydroxide, use agitation (mixing) and add the concentrated sodium hydroxide to water at a controlled rate to control the heat of dilution and avoid spattering. Never add water to sodium hydroxide.
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SULFUR BLOCK
2.8
Sulfur Plant Safety
2.8.1
Hydrogen Sulfide Hydrogen sulfide will be present in all of the process gas streams flowing in the ATU, the SWS, the SRU, the SDU, the TGCU, and the Thermal Oxidizer. The hydrogen sulfide content will decrease as the sulfur is extracted from the gas stream and will reach its lowest concentration in the incinerated vent gas. Some hydrogen sulfide will be dissolved in the liquid sulfur produced. Review the characteristics of this poisonous gas often, and be fully familiar with them. Avoid all possibility of exposure to hydrogen sulfide. Plan and think ahead, so that when there is a possibility of hydrogen sulfide release, you will know what to do. Plant safety procedures should be established that require the presence of at least two men before a flange is loosened, or any other opening is created, to allow a possible H2S release. The man doing the work should either wear a gas mask with canister, manufactured specifically for hydrogen sulfide protection, or a fresh air pack. The second man should stand on the side a few yards away, upwind, with the oxygen supply in his hands. If the job requires entering a vessel or enclosure which might contain some hydrogen sulfide, a safety harness with lifeline shall be attached to the man entering the vessel. Two men should remain outside the vessel to pull the man who entered the vessel to safety if he should be overcome. If a man who is working in a hydrogen sulfide exposure should begin moving sluggishly or lose coordination, the man who is standing by should remove him immediately to fresh air. Any sign of actions that are out of the ordinary is a last minute warning. After an extended exposure, a man will be unusually sensitive to even small concentrations of H2S gas.
2.8.2
Sulfur Dioxide Sulfur dioxide will not be present within the SRU, the SDU, the TGCU unit, and the Thermal Oxidizer as a pure gas but will be present in the following:
Issued 30 August 2011
1.
Most process gas streams (reactor gases, tailgas, and stack gas).
2.
Sulfur tank gases.
3.
Smoke from any sulfur fire.
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SULFUR BLOCK The maximum allowable concentration in which it is safe to work is 5 PPM. Reactor gases, tailgas, and stack gas may have concentrations up to 10,000 PPM and vapors from sulfur fires may have concentrations up to 100,000 PPM. The most likely source of sulfur dioxide in sufficient concentration to cause problems is a fire in the sulfur storage tank. The simplest way to stop such a fire is to smother it by covering all openings to the air, then putting water into the storage tank. This water will vaporize to steam and help smother the fire. Smothering a sulfur fire with plant steam is also effective.
2.8.3
Sulfur Storage Tank Molten sulfur produced in each SRU flows through the drain seals and is stored in the sulfur surge tanks. These drain seals and tanks present a combination of principle hazards.
2.8.3.1
Poisonous Gases Hydrogen sulfide and sulfur dioxide are present in the vapor space above the molten sulfur. They should not be inhaled as they are extremely toxic.
2.8.3.2
Explosion and Fire The surge tanks are equipped with steam-powered eductors to provide ventilation of the vapor space. Each tank also has a steam-jacketed stack that can provide natural-draft ventilation if its eductor system is not functioning. These ventilation systems are designed to sweep sufficient fresh air through the vapor space to prevent hydrogen sulfide liberated from the sulfur from reaching explosive concentrations. However, common sense dictates that no ignition sources should be allowed near the tanks in case some obstruction of the ventilation system should occur and allow an explosive concentration of H2S to build up. Therefore, tools which might cause a spark or open flame, should not be brought into the area around the sulfur surge tanks without special review and precautions, and smoking must be prohibited in the area. Operators should be aware of the possible existence of an explosive mixture in the sulfur surge tanks, as there is some history of explosions in European sulfur pits and at least one U.S. pit. The breather vents, where the air is sucked into the tanks, should be
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SULFUR BLOCK checked regularly for adequate air flow. The motive steam supply to the eductors, as well as the steam supply to and condensate from the ventilation system jacketing, should also be monitored. Sulfur fires may occur in the tanks. Molten sulfur has an auto-ignition temperature of approximately 450°F (232°C). This is a spontaneous reaction; no spark or flame is required. Steam system temperatures are normally well below the auto-ignition point of sulfur. However, some iron-sulfur corrosion compounds are unstable and can ignite, or decompose, at lower temperatures to create localized hot spots and sulfur burning. SECTIONS 2.9 THROUGH 2.14 LIST SOME IMPORTANT SAFETY CONSIDERATIONS THAT PERSONNEL SHOULD KEEP IN MIND WHEN WORKING IN THE PLANT. THESE SECTIONS ARE NOT A COMPLETE LIST OF SAFETY CONSIDERATIONS AND DO NOT OUTLINE COMPLETE OPERATING OR MAINTENANCE PROCEDURES. ALL PERSONNEL SHOULD FOLLOW THEIR EMPLOYER'S DETAILED SAFETY PROCEDURES FOR ANY WORK DONE IN THE PLANT.
2.9
Hot Work Any work which requires the use of equipment that is capable of being an ignition source in an area where flammable vapors or materials may be present is defined as "Hot Work". Examples of equipment considered as ignition sources are: welding equipment, open lights, gasoline engines, grinders, etc. "Hot Work" normally requires specific approval by plant management and should be implemented by following detailed instructions for obtaining "Hot Work" permits.
2.10 Vessel Entry The procedures used for vessel entry shall be in conformance with ANSI Z117.1 (latest edition), the "American National Standard Safety Requirements for Confined Spaces". The discussion in this section is a general information supplement to ANSI Z117.1. In all cases, consult ANSI Z117.1 and any applicable Samsung Total Petrochemicals policies for specific precautions and procedures regarding each instance of vessel entry. Vessel entry refers to any tank, vessel, equipment, or other enclosed place where there is a hazard of: 1) a toxic, corrosive, or flammable substance;
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SULFUR BLOCK 2) insufficient oxygen; or 3) severe restrictions that would hinder escape or rescue. Vessel entry normally requires specific approval by plant management. Almost all of the vessels in this facility fit at least one of the three categories mentioned above, due to the potential presence of hydrocarbon gas, caustic or corrosive chemicals, or toxic H2S and SO2. All vessels should be assumed unsafe for normal entry until prescribed vessel entry procedures have been followed. Consider the precautions advised for vessel entry when gauging tanks, sampling, and blowing down lines or instruments. Some or all of the following items should be considered for most vessel entry jobs: A.
Disconnect and blank off all lines to the vessel.
B.
Remove all sources of ignition before removing manway covers.
C.
Check all internal lines and liquid traps to verify they are free of hazardous liquid.
D.
Clean the vessel as thoroughly as possible by draining, purging with inert gas, steaming, ventilating, or other suitable means. If steam is used, guard against static electricity by grounding the steam nozzle. After steaming, allow the vessel to cool slowly. Sudden cooling with water spray may cause a static electric charge. Also, it is not good practice to allow the inside surfaces of the sulfur plant process piping and vessels to become water wetted. Excessive corrosion occurs when oxygen and water are present.
E.
Issued 30 August 2011
Test the Atmosphere for: (1)
Oxygen - The atmosphere must contain 19.5-23.5% oxygen and the vessel should have adequate ventilation, either forced or natural.
(2)
Explosive mixture - A vessel may not be entered if the testing instrument indicates an air-vapor mixture that exceeds 10% of the lower explosive limit, or the value specified in your organization's safety procedures.
(3)
Toxic fumes - The presence of any toxic fumes requires the use of respiratory protective equipment, normally an air supplied mask with
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SULFUR BLOCK hand blower, or a self-contained breathing unit; otherwise, additional cleaning or purging of the vessel is indicated. F.
A safety harness and a lifeline shall be worn by the person entering the vessel if respiratory equipment is required.
G.
Personal protective clothing suitable for the job inside the vessel should be worn.
H.
An observer should be stationed outside the vessel. His duty should be to watch the person inside the vessel. When respiratory equipment is required for the person entering the vessel, the observer should also have the suitable respiratory equipment available.
I.
Fire extinguisher and other emergency equipment should be available as required.
2.11 Pipes and Lines In the discussion that follows, line breaking is defined as the opening of any line, the contents of which are flammable, corrosive, toxic, or under high pressure. All other line opening jobs or work are excluded from this definition. Line breaking usually requires specific approval by plant management. The following items should be considered in all work involving lines and valves:
2.11.1
Issued 30 August 2011
General 1.
Know the contents of each line being worked on.
2.
Know the pressure ratings of the pipes and fittings. Never install low pressure connections on high pressure lines.
3.
Never hammer on high-pressure lines.
4.
Use extreme caution when thawing frozen lines.
5.
Never use fire to locate leaks of flammable materials.
6.
Be very cautious when attempting to tighten steam pipe fittings while pressure is on a line.
7.
When opening valves, do so slowly to allow pressure to equalize before opening the valve fully.
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SULFUR BLOCK 8.
2.11.2
2.11.3
When removing blinds, loosen bolts and allow any pressure to bleed down. Gas sometimes leaks into the space between the blind and the valve.
Before Breaking Lines 1.
Drain the contents into a tank or to the lowest point.
2.
Lock out, tag out, and try the pump. All gauges and sight glasses should be checked for zero readings.
3.
Close and tag the nearest upstream and downstream valves.
When Breaking Lines 1.
Wear suitable personal protective equipment, such as full clothing. At times, rubber suits should be worn to guard against chemical splash. Goggles should be worn to protect eyes against chemical splash and flying particles.
2.
Always assume a line is full and under maximum possible pressure.
3.
The placement of a deflector over the flange joint is usually desirable for the initial "cracking" of flanges in lines containing corrosive or toxic material.
4.
The worker should slowly open the bolts on the far side, so that if there is a spray it will be away from him.
5.
Sections that have been removed should be handled carefully until they are inspected for trapped material or residues and flushed if required.
2.12 Electrical Equipment Everyone recognizes that high voltages can be very dangerous. However, some people fail to realize that so-called "low-voltage" can be hazardous and under certain conditions can produce fatal injuries. Deaths have occurred because of contact with circuits of less than 50 volts. It is not voltage but amperage that kills. Under certain conditions, as little as 1/10 ampere is sufficient to cause death. The following may be used as a guide when working with electrical equipment.
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SULFUR BLOCK 2.12.1
Electrical Repairs When electrical equipment is to be repaired, switches must be locked open, tagged, and the circuit "tried" to confirm the power is off. Working on "hot circuits" normally requires the permission of plant management. Refer to detailed plant tag-out procedures before proceeding.
2.12.2
2.12.3
2.12.4
2.12.5
Issued 30 August 2011
Grounding 1.
All electrical equipment is to be grounded.
2.
If it is necessary to move any equipment, the ground should be replaced before the equipment is used.
Conduit, Cables, and Wires 1.
Electrical conduits should not be used to support other equipment.
2.
Exposed ends of electrical wires must be taped.
3.
Unused and abandoned electric wires must be removed or disconnected at each end.
Fuses 1.
Fuses should be replaced only by authorized personnel.
2.
Fuse tongs and/or rubber electrical gloves should be used and the disconnect should be opened. Rubber gloves must always be used for voltages in excess of 150 volts.
3.
Never use coins or tin foil in lieu of fuses.
4.
Never use fuses of greater capacity than is specified by the equipment manufacturer.
Switching 1.
When starting electric motors, handle all switches according to instructions. Make contact so as to prevent arcs. Stand in a safe position.
2.
Never pull a disconnect switch under load except in an emergency.
3.
Always be certain that hands are dry and that the footing is dry when operating switches or plugging in electrical appliances.
4.
Keep rubber mats in front of switchboards where possible.
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SULFUR BLOCK
2.12.6
2.12.7
Issued 30 August 2011
5.
Switch-panel fronts should be kept closed.
6.
Maintain clear access to disconnects/switches.
Hand Tools and Portable Equipment 1.
Extension lights without bulb protectors must not be used. Use only low voltage lights with isolating transformers in boilers and similar places.
2.
All extension cords should be the grounded type. Before each period of use, examine extension cords carefully for any failure of the outer insulation, particularly at terminal points where the cord enters a plug or a fixture.
3.
Lights and tools should not be disconnected from an extension cord while the other end of the cord is in a socket or receptacle.
4.
The ground cable with which each tool is equipped should be secured to a suitable ground before the tool is plugged into a source of electricity.
Miscellaneous 1.
Contact with electrical conductors should be avoided whether they are energized or not.
2.
Fenced sub-station areas should be entered only by authorized personnel.
3.
Faulty electrical equipment must not be used. Report it immediately.
4.
Before changing broken light bulbs, be certain the current is turned off.
5.
No employee may work within 15 feet of a high voltage power line except by special authorization of plant management.
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SULFUR BLOCK
2.13 Boilers and Other Direct-Fired Equipment 2.13.1
2.13.2
General 1.
In this facility, the Waste Heat Boiler, Sulfur Condenser, TGCU Waste Heat Reclaimer, and Thermal Oxidizer Waste Heat Boiler are classified as boilers, but they are not direct-fired. The Reactor Furnace and Thermal Oxidizer are the direct-fired pieces of equipment.
2.
Work on the Waste Heat Boiler, Sulfur Condenser, TGCU Waste Heat Reclaimer, Thermal Oxidizer Waste Heat Boiler, Reactor Furnace, and Thermal Oxidizer should be approved as required by local procedures.
3.
Control valves should be operated only when necessary by the operator in charge.
4.
Refer to detailed vendor instructions for specific descriptions of actual safety procedures and equipment on the direct-fired equipment in this plant.
Boilers
2.13.2.1
Repair and Maintenance a.
Only boiler inspectors or the State boiler agency should determine a new setting for safety relief valves. Seals on safety relief valves should never be removed. If a valve leaks, remove it to a Code-authorized shop for repairs.
b.
Before entering a boiler fire box:
c.
Issued 30 August 2011
(1)
Ventilate the fire box.
(2)
Lock, tag, and try the blower valve.
(3)
Blank or disconnect fuel gas lines.
Before entering the drum or shell: (1)
Feed water lines and blow-off lines should be blinded or suitably locked.
(2)
Blank the steam line between the stop valve and the boiler.
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SULFUR BLOCK (3)
2.13.2.2
2.13.3
Issued 30 August 2011
If blinding is prevented by piping connections, non-return and main stop valves should be locked and vents between valves should be opened.
d.
If valves are to be locked, the man entering the boiler shall supervise the operations and retain the keys to the locks.
e.
After repairs, examine the boiler carefully for tools and other matter before replacing the manhole cover.
f.
Before filling begins, all locks should be removed by the man, or men, who have retained keys to the locks.
Operations a.
Open steam valves very slowly to allow cold lines to heat up and water to drain out before pressure builds.
b.
Open blow-off valves or cocks slowly. Before a boiler is blown out, it is advisable to attain a high water level so that scale and sediment can be blown out without lowering the water to a dangerous level.
Direct-Fired Equipment 1.
Before attempting to light burners, be certain that combustible gases are purged from the system.
2.
Stand to one side of openings when lighting burners.
3.
Ignite each burner or pilot as described in operating instructions.
4.
Observation ports should be used with care when lighting burners because of the chance of high positive pressures and explosion.
5.
Before entering a fire box: a.
Ventilate the fire box.
b.
Lock, tag, and try the blower valve.
c.
Blank or disconnect fuel gas and tailgas lines.
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SULFUR BLOCK
2.14 Laboratory Safety 2.14.1
2.14.2
2.14.3
Issued 30 August 2011
Good Housekeeping 1.
Cleanliness and orderliness are essential to the operations of laboratories.
2.
A continuous program should be in effect to prevent the accumulation of rubbish, rags, partly used samples, dismantled equipment, etc.
Equipment 1.
Inspect all gas hoses for leaks each day that they are used.
2.
Extinguish all gas burners when they are not in use.
3.
Glassware a.
Discard all cracked, broken, or scrap glassware.
b.
Fire-polish all chipped edges on burettes, beakers, graduates, etc.
c.
Avoid thermal shock with all glassware.
d.
Use only glass tubing with fire-polished ends.
e.
Before attempting to insert glass tubing into stopper holes, be certain that the holes are the proper size. Always moisten the stopper hole and the glass tubing with water, and rotate the glass tube as it is inserted, pushing it away from the body. When rubber tubing or stoppers stick on glassware, cut them away.
f.
Do not drink or eat out of laboratory glassware.
Chemical Sorting and Identification 1.
Adequately label or mark bottles and containers to identify the chemical within.
2.
Keep chemicals stored in their proper place. Solvents should not be brought into laboratory in quantities greater than five gallons.
3.
Keep volatile combustible liquids in safety containers and away from direct flames or sources of heat.
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SULFUR BLOCK 2.14.4
Issued 30 August 2011
Chemical Handling 1.
When handling acids or caustics in quantities, always wear protective clothing and eye protection.
2.
Always pour acids and caustics into water, never the reverse.
3.
If acids or caustics enter the eye, flush with plenty of water and report for first aid treatment.
4.
Wash hands immediately after handling chemicals bearing poison labels. Wash hands after handling mercury and clean up mercury spills at once.
5.
Use large quantities of water when disposing of acids or caustic materials through the drains.
6.
Refer to vendor information for specifics on the safe handling of individual types of chemicals and first aid steps for accidents involving them.
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SULFUR BLOCK
2.15 Material Safety Data Sheets (MSDS) This section contains Material Safety Data Sheets (MSDS) for the hazardous chemicals listed below that operating personnel in this part of the complex may encounter while operating the unit and systems described in this manual. Of necessity, these MSDS are generic in nature. As they become available, Samsung Total Petrochemicals Co. should replace and/or supplement the MSDS provided in this manual with those prepared by the manufacturers and/or suppliers of the specific chemicals used in the complex. A.
Hydrogen Sulfide
B.
Sulfur Dioxide
C.
Sulfur
D.
Ammonia
E.
Methyldiethanolamine
F.
Sodium Hydroxide
G.
UOP/ESM S-2001 Sulfur Conversion Catalyst
H.
Criterion 234 Tailgas Treating Catalyst
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MATERIAL SAFETY DATA SHEET HYDROGEN SULFIDE SECTION I - PRODUCT IDENTIFICATION Substance:
HYDROGEN SULFIDE
CAS Number: 7783-06-4
Trade Names / Synonyms:
Hepatic Gas; Hydrosulfuric Acid; Stink Damp; Sulfureted Hydrogen; Sulfur Hydride
Molecular Formula:
H2S
General or Generic ID:
Inorganic Gas
Molecular Weight: 34.08
SECTION II - COMPONENTS Component:
Hydrogen Sulfide
Percent: > 99.0
Other Contaminants:
Methyl Mercaptan; Carbon Disulfide; Oxides of Carbon and Sulfur
Exposure Limits:
Hydrogen Sulfide 20 PPM OSHA acceptable ceiling concentration 50 PPM / 10 minutes OSHA peak 10 PPM ACGIH TWA 10 PPM ACGIH STEL 15 mg/m3 (10 PPM) NIOSH recommended 10 minute ceiling SECTION III - PHYSICAL DATA
Description:
Colorless gas at atmospheric temperature and pressure, with the odor of rotten eggs.
Melting Point:
-122°F (-86°C)
Boiling Point:
-77°F (-60°C)
Liquid Specific Gravity: (water = 1.0)
1.54
Vapor Specific Gravity: (air = 1.0)
1.18
Vapor Pressure:
294 PSI (20 atm) @ 78°F (25°C)
Odor Threshold:
0.05 PPM
Solubility in Water:
4.2 g/l @ 60°F (15°C), 3.2 g/l @ 78°F (25°C)
Other Solvents
Carbon Disulfide, Weak Acids, Ethanol, Gasoline, Kerosene, Crude Oil, Liquid Sulfur
Other Physical Data:
Solubility decreases with increasing temperature or with mechanical disturbance (agitation), causing evolution of dissolved gas.
ISSUE DATE: 06/12/95
SUPERSEDES: 02/19/93
PAGE 1 OF 6
MATERIAL SAFETY DATA SHEET HYDROGEN SULFIDE SECTION IV- FIRE AND EXPLOSION INFORMATION Fire and Explosion Hazard:
Highly flammable gas when exposed to heat, flame, or oxidizers. Moderate explosion hazard. Gas-air mixtures are explosive. Vapors are heavier than air, and may travel a considerable distance to a source of ignition and flash back.
Auto-Ignition Temperature:
500°F (260°C)
Flash Point Temperature: N/A
Explosive Limits in Air:
Lower: 4.3%
Upper: 46%
Extinguishing Media:
Let burn unless leak can be stopped immediately. (1984 Emergency Response Guidebook, DOT P 5800.3). For larger fires, use water spray, fog, or foam. (1984 Emergency Response Guidebook, DOT P 5800.3).
Fire-Fighting Procedures:
Extinguish only if flow can be stopped; use water in flooding amounts as fog. Apply from as far a distance as possible. Avoid breathing poisonous vapors, keep upwind. Evacuate to a radius of 2500 feet for uncontrollable fires. Evacuate downwind areas as required for leaks.
Fire-Fighting Phases:
Stop flow of gas. Use water to keep fire-exposed containers cool and to protect personnel effecting the shut off. (NFPA 49, Hazardous Chemicals Data, 1975). SECTION V - HEALTH HAZARD DATA
Permissible Exposure Level:
10 PPM
Threshold Limit Value:
10 PPM
Health Effects from Exposure Swallowing:
Ingestion of a gas is unlikely.
Inhalation:
Corrosive/Neurotoxin/Toxic. 300 PPM immediately dangerous to life or health. Acute Exposure - Low concentrations may produce nasal and respiratory tract irritation. At 50 PPM, anosmia, anoxia, headache, nausea, dizziness, vomiting, confusion, weakness, ataxia, irritability, and insomnia may occur. Rhinitis, pharyngitis, coughing, bronchitis, and pneumonitis are also possible. At 500-1000 PPM, coma, convulsions, and death may occur within 30 minutes. At extremely high concentrations, respiratory paralysis and death from asphyxia may be immediate. Non-fatal exposures may result in sequelae including residual cough, cardiac dilation, slow pulse, peripheral neuritis, albuminuria, amnesia, psychic disturbances, and permanent brain damage.
ISSUE DATE: 06/12/95
SUPERSEDES: 02/19/93
PAGE 2 OF 6
MATERIAL SAFETY DATA SHEET HYDROGEN SULFIDE SECTION V- HEALTH HAZARD DATA (continued) Inhalation: (continued)
Chronic Exposure - Prolonged or repeated exposure to low concentrations may cause hypotension, nausea, anorexia, weight loss, incoordination, and chronic cough. Prolonged exposure to 250 PPM has led to pulmonary edema.
Eye Contact:
Corrosive. Acute exposure - 50 PPM for one hour has caused conjunctivitis, pain, lacrimation, photophobia, and appearance of haloes around lights. Within a few hours or days, symptoms may progress to keratoconjunctivitis and vesiculation of the corneal epithelium. Higher concentrations may cause severe irritation, lacrimation, and intense pain. Chronic Exposure - Prolonged or repeated exposure may cause conjunctivitis.
Skin Contact:
Corrosive. Acute Exposure - High vapor concentrations may cause severe irritation of the skin. Chronic Exposure - A high incidence of furunculosis has been reported in industrial hydrogen sulfide workers.
First Aid Measures Swallowing:
Treat symptomatically and supportively. Get medical attention immediately. If vomiting occurs, keep head lower than hips to prevent aspiration.
Inhalation:
Remove from exposure area to fresh air immediately. If breathing has stopped, give artificial respiration. Maintain airway and blood pressure and administer oxygen if available. Keep affected person warm and at rest. Administration of oxygen should be performed by qualified personnel. Get medical attention immediately.
Eye Contact:
Wash eyes immediately with large amounts of water, occasionally lifting upper and lower lids, until no evidence of chemical remains (at least 15-20 minutes). In case of burns, apply sterile bandages loosely without medication. Get medical attention immediately.
Skin Contact:
Flush affected areas with large amounts of water. Consult a physician for further treatment.
Antidote:
Amyl nitrite or sodium nitrite can be used to aid in the formation of sulfmethemoglobin, thus removing sulfide from combination in tissues. Pyridoxine 25 mg/kg intravenously, or 10% urea, 1 g/kg intravenously, has been suggested as a sulfide acceptor. Administration of antidotes should be performed by qualified medical personnel. The nitrite antidote is toxic; therapy is dangerous. (Dreisbach, Handbook of Poisoning, 11th ed.)
ISSUE DATE: 06/12/95
SUPERSEDES: 02/19/93
PAGE 3 OF 6
MATERIAL SAFETY DATA SHEET HYDROGEN SULFIDE SECTION VI- REACTIVITY DATA Reactivity:
Stable under normal temperatures and pressures.
Incompatibilities:
Acetaldehyde: Barium Oxide, Mercurous Oxide, and Air: Barium Oxide, Nickel Oxide, and Air: Barium Peroxide: Bromine Pentafluoride: Chlorine Monoxide: Chlorine Trifluoride: Chromic Anhydride: Copper: Copper Powder: Diiron Trioxide Hydrate: Fluorine: Metals: Metal oxides: Lead Dioxide: Nitric Acid: Nitric Acid (Fuming or Concentrated): Nitrogen Trichloride: Nitrogen Trifluoride: Nitrogen Triiodide and Ammonia: Oxidants: Oxygen Difluoride: Perchloryl Fluoride: Phenyl Diazonium Chloride: Rust: Silver Fulminate: Soda Lime and Air: Sodium: Sodium Peroxide:
Violent reaction. Incandescent reaction or explosion. Incandescent reaction or explosion. Ignition reaction. Fire and explosion hazard. Ignition reaction on contact. Explosive reaction. Incandescent reaction on heating. Intense exothermic reaction. Intense reaction. Formation of combustible substance. Ignition reaction. Attacks most metals, especially in the presence of water. Combustion, incandescent reaction, or explosion. Combustion reaction. Incandescent reaction. Violent reaction. Explosive reaction. Formation of explosive mixture. Explosive reaction. Violent reaction. Explosive reaction on mixing. Ignition or explosion at 100-300°C. Formation of explosive substance. Hydrogen sulfide may ignite if passed through rusty iron pipes. Violent reaction at ambient temperatures. Incandescent reaction. Rapid reaction on contact with moist gas. Violent reaction or ignition, even in the absence of air.
Decomposition:
Thermal decomposition products may include toxic and hazardous hydrogen, sulfur, and oxides of sulfur.
Polymerization:
Hazardous polymerization has not been reported to occur under normal temperatures and pressures.
ISSUE DATE: 06/12/95
SUPERSEDES: 02/19/93
PAGE 4 OF 6
MATERIAL SAFETY DATA SHEET HYDROGEN SULFIDE SECTION VII- SPILL OR LEAK PROCEDURES Steps to Be Taken in Case Material is Released or Spilled Shut off ignition sources. Stop leak if you can do it without risk. Use water spray to reduce vapors. Isolate area until gas has dispersed. No smoking, flames, or flares in hazard area! Keep unnecessary people away; isolate hazard area and deny entry. Ventilate closed spaces before entering. Evacuate area endangered by gas. Waste Disposal Method Water used to knock-down vapors is corrosive and toxic, and should be diked for containment. Add suitable agent to neutralize to 7 pH prior to disposal.
SECTION VIII - PROTECTIVE EQUIPMENT TO BE USED Ventilation:
Provide local exhaust or process enclosure ventilation to meet the published exposure limits. Ventilation equipment must be explosion-proof.
Respirator:
The following respirators and maximum use concentrations are recommendations by the U.S. Department of Health and Human Services; NIOSH Pocket Guide to Chemical Hazards or NIOSH Criteria Documents; or, Department of Labor, 29CFR1910, Subpart Z. The specific respirator selected must be based on contamination levels found in the work place and be jointly approved by the National Institute of Occupational Safety and Health and the Mine Safety and Health Administration. Hydrogen Sulfide: 100 PPM Supplied-air respirator. Self contained breathing apparatus.
ISSUE DATE: 06/12/95
250 PPM -
Supplied-air respirator operated in continuous flow mode. Self-contained breathing apparatus.
300 PPM -
Self-contained breathing apparatus. Supplied-air respirator with full facepiece.
Escape -
Air-purifying full facepiece respirator (gas mask) with chin-style or frontor back-mounted canister. Escape-type self-contained breathing apparatus.
SUPERSEDES: 02/19/93
PAGE 5 OF 6
MATERIAL SAFETY DATA SHEET HYDROGEN SULFIDE SECTION VIII - PROTECTIVE EQUIPMENT TO BE USED (continued) Respirator (continued):
For firefighting and other immediately dangerous to life or health conditions: Self-contained breathing apparatus with full facepiece operated in pressure-demand or other positive pressure mode. Supplied-air respirator with full facepiece and operated in pressure-demand or other positive pressure mode in combination with an auxiliary self-contained breathing apparatus operated in pressure-demand or other positive pressure mode.
Clothing:
Wear protective clothing. Prevent any possibility of repeated or prolonged vapor contact with skin.
Gloves:
Wear full protective gloves.
Eye Protection:
Employee must wear splash-proof or dust-resistant safety goggles and a faceshield to prevent contact with this substance. Where there is any possibility that an employee's eyes may be exposed to this substance, the employer shall provide an eye-wash fountain within the immediate work area for emergency use.
SECTION IX - SPECIAL PRECAUTIONS OR OTHER COMMENTS 1.
Odor is not a reliable test for the presence of hydrogen sulfide.
2.
Since hydrogen sulfide is heavier than air, it settles when released into the atmosphere and becomes more concentrated near the ground and in low places.
3.
Hydrogen sulfide dissolves in liquid sulfur and is a hazard in storage tanks and pits.
Disclaimer The information contained herein is believed to be accurate, but is not warranted to be, whether originating within the company or not. Health and safety precautions in this data sheet may not be adequate for all individuals and/or situations. Recipients are advised to confirm in advance of need that the information is current, applicable, and suitable to their circumstances. It is the end user’s responsibility to evaluate and use this product safely, and to comply with all applicable laws and regulations. No statement made in this data sheet shall be construed as a permission or recommendation for use of any product in a manner that might infringe existing patents. No warranty is made, either expressed or implied.
ISSUE DATE: 06/12/95
SUPERSEDES: 02/19/93
PAGE 6 OF 6
MATERIAL SAFETY DATA SHEET SULFUR DIOXIDE SECTION I - PRODUCT IDENTIFICATION Substance
SULFUR DIOXIDE
Trade Names / Synonyms:
Sulfurous Acid Sulfur Oxide
Molecular Formula:
SO2
General or Generic ID:
Inorganic Gas
CAS Number: 7446-09-5
Anhydride;
Sulfurous
Anhydride;
Sulfurous
Oxide;
Molecular Weight: 64.06
SECTION II - COMPONENTS Component:
Sulfur Dioxide
Percent: > 99.0
Other Contaminants:
Hydrogen Sulfide
Exposure Limits:
Sulfur Dioxide 5 PPM OSHA TWA per 8-hour working day 2 PPM ACGIH TWA 0.5 PPM NIOSH recommended TWA SECTION III - PHYSICAL DATA
Description:
Colorless gas at atmospheric temperature and pressure, with an irritating, suffocating odor.
Melting Point:
-104°F (-76°C)
Boiling Point:
14°F (-10°C)
Liquid Specific Gravity: (water = 1.0)
1.43
Vapor Specific Gravity: (air = 1.0)
2.21
Vapor Pressure:
49 PSIA (3.3 atm) @ 70°F (21°C)
Odor Threshold:
0.47 PPM
Solubility in Water:
129 g/l @ 60°F (15°C), 102 g/l @ 68°F (20°C)
Other Solvents:
Sulfur
Other Physical Data:
ISSUE DATE: 02/19/93
SUPERSEDES:
PAGE 1 OF 5
MATERIAL SAFETY DATA SHEET SULFUR DIOXIDE SECTION IV- FIRE AND EXPLOSION INFORMATION Fire and Explosion Hazard:
None
Auto-Ignition Temperature:
N/A
Flash Point Temperature: N/A
Explosive Limits in Air:
Lower: N/A
Upper: N/A
Extinguishing Media:
Material is nonflammable. Use what is appropriate to the surrounding fire. SO2 will form a corrosive acidic mist with water fog or steam.
Fire-Fighting Procedures:
Fire fighters must use full protective clothing, eye protection, and selfcontained breathing equipment when this material is involved in a fire situation.
Fire-Fighting Phases:
N/A
SECTION V - HEALTH HAZARD DATA Permissible Exposure Level:
5 PPM
Threshold Limit Value:
2 PPM
Health Effects from Exposure Swallowing:
Ingestion of a gas is unlikely.
Inhalation:
Chiefly affects the upper respiratory tract and the bronchi, causing irritation, difficulty with breathing, pulmonary edema, and, at high levels, respiratory paralysis. Short exposures above 50-100 PPM can be dangerous, and, above 400-500 PPM, immediately life threatening. Systemic effects of acute or chronic exposure are not fully known. Statistical evidence has been reported to show increased pulmonary function impairment at chronic SO2 levels of 1-4 PPM. Mixture with smoke particulate or aerosols may increase the hazards of SO2 inhalation.
Eye Contact:
At 20 PPM and above, irritation and inflammation of the conjunctiva.
Skin Contact:
At 10,000 PPM, irritating to moist areas within a few minutes.
ISSUE DATE: 02/19/93
SUPERSEDES:
PAGE 2 OF 5
MATERIAL SAFETY DATA SHEET SULFUR DIOXIDE SECTION V- HEALTH HAZARD DATA (continued) First Aid Measures Swallowing:
Treat symptomatically and supportively. Get medical attention immediately. If vomiting occurs, keep head lower than hips to prevent aspiration.
Inhalation:
The victim must be carried at once to an uncontaminated atmosphere and effective artificial respiration started immediately if breathing has ceased. Oxygen (100%) should be administered (by trained personnel only) as soon as possible after a severe exposure, preferably against a positive exhalation pressure of 1.25 inches of water. Oxygen inhalation must be continued as long as necessary to maintain the normal color of the skin and mucous membranes. In cases of severe exposure, the patient should breathe 100% oxygen under positive exhalation pressures for 30 minute periods every hour for at least 3 hours. If there are no signs of lung congestion at the end of this period, and if the breathing is easy and the color is good, oxygen inhalation may be discontinued. Throughout this time, the patient should be kept comfortably warm, but not hot.
Eye Contact:
If sulfur dioxide has contacted the eyes, they should be washed promptly with large quantities of water for at least 15 minutes. Chemical neutralizers are not advisable. It is advisable to irrigate the eyes gently with water at room temperature in order to minimize additional pain and discomfort. Refer the victim at once to a physician, preferably an eye specialist.
Skin Contact:
On skin contact with sulfur dioxide, use an emergency safety shower at once. Clothing and shoes contaminated with sulfur dioxide should be removed under the shower. Sulfur dioxide should be washed off with very large quantities of water. Wash skin areas with large quantities of soap and water. Do not apply salves or ointments to chemical burns for 24 hours.
ISSUE DATE: 02/19/93
SUPERSEDES:
PAGE 3 OF 5
MATERIAL SAFETY DATA SHEET SULFUR DIOXIDE SECTION VI- REACTIVITY DATA Reactivity:
Stable under normal temperatures and pressures.
Incompatibilities:
Acrolein Aluminum Cesium Hydrogencarbide Cesium Oxide Chlorates Chlorine Trifluoride Chromium Ferrous Oxide Fluorine Halogens or Interhalogens Lithium Acetylene Carbide Diammino Lithium Nitrate
Polymerization:
Hazardous polymerization has not been reported to occur under normal temperatures and pressures.
Manganese Metal Acetylides Metal Oxides Metals Polymeric Tubing Potassium Carbide Potassium Chlorate Rubidium Carbide Sodium Sodium Carbide Sodium Hydride Tin Monoxide
SECTION VII- SPILL OR LEAK PROCEDURES Steps to Be Taken in Case Material is Released or Spilled Notify safety personnel of significant leaks. Exclude all from area except those assigned to leak and spill control who are using full protective gear (see Section VIII). Provide ventilation. Locate and control leakage. Waste Disposal Method If water is used to knock-down vapors, it will be corrosive and toxic, and should be diked for containment. Add suitable agent to neutralize to 7 pH prior to disposal.
ISSUE DATE: 02/19/93
SUPERSEDES:
PAGE 4 OF 5
MATERIAL SAFETY DATA SHEET SULFUR DIOXIDE SECTION VIII - PROTECTIVE EQUIPMENT TO BE USED Ventilation:
Provide local exhaust or process enclosure ventilation to meet the published exposure limits. (Treatment of exhausted air to remove SO2 may be necessary before discharge to the outside environment.)
Respirator:
For fire fighting and other immediately dangerous to life or health conditions: Self-contained breathing apparatus with full pressure-demand or other positive pressure mode.
facepiece
operated
in
Supplied-air respirator with full facepiece and operated in pressure-demand or other positive pressure mode in combination with an auxiliary self-contained breathing apparatus operated in pressure-demand or other positive pressure mode. (An approved cartridge respirator can be used when contamination is known to be below 20 PPM.) Clothing:
Wear protective clothing. contact with skin.
Prevent any possibility of repeated or prolonged vapor
Gloves:
Wear full protective gloves.
Eye Protection:
Employee must wear splash-proof or dust-resistant safety goggles and a faceshield to prevent contact with this substance. Where there is any possibility that an employee's eyes may be exposed to this substance, the employer shall provide an eye-wash fountain within the immediate work area for emergency use.
SECTION IX - SPECIAL PRECAUTIONS OR OTHER COMMENTS
Disclaimer The information contained herein is believed to be accurate, but is not warranted to be, whether originating within the company or not. Health and safety precautions in this data sheet may not be adequate for all individuals and/or situations. Recipients are advised to confirm in advance of need that the information is current, applicable, and suitable to their circumstances. It is the end user’s responsibility to evaluate and use this product safely, and to comply with all applicable laws and regulations. No statement made in this data sheet shall be construed as a permission or recommendation for use of any product in a manner that might infringe existing patents. No warranty is made, either expressed or implied.
ISSUE DATE: 02/19/93
SUPERSEDES:
PAGE 5 OF 5
MATERIAL SAFETY DATA SHEET SULFUR SECTION I - PRODUCT IDENTIFICATION Substance:
SULFUR
CAS Number: 7704-34-9
Trade Names / Synonyms:
Asulfa-Supra; Bensulfoid; Brimstone; Colloidal Sulfur; Cosan; Devisulphur; Flowers of Sulfur; Ground Vocle Sulphur; Hexasul; Kumulus; Microwetsulf; Precipitated Sulfur; Precipitated Sulphur; S-590; S-594; S-595; Solid Sulfur; Solid Sulphur; Sublimed Sulfur; Sublimed Sulphur; Sulfex; Sulfran; Sulphur; Uni350
Molecular Formula:
S
General or Generic ID:
Non-metallic Element
Molecular Weight: 32.06
SECTION II - COMPONENTS Component:
Sulfur
Percent: > 99.0
Other Contaminants:
Hydrogen Sulfide, Sulfur Dioxide, Hydrocarbons, Carbon
Exposure Limits:
The Nuisance Dust TLV should govern exposure to solid sulfur in the absence of other standards: 10 mg/m3 (8 PPMW) ACGIH TWA for total dust 5 mg/m3 (4 PPMW) ACGIH TWA for respirable dust Liquid sulfur may release hydrogen sulfide and/or sulfur dioxide as gases. Refer to the specific Material Safety Data Sheets for these substances giving the applicable exposure limits. SECTION III - PHYSICAL DATA
Description:
Solid sulfur is odorless, tasteless, yellow rhombic or monoclinic crystals, lumps, granules, or powder. Sulfur contaminated with hydrocarbon or carbon may be orange, green, tan, brown, or black in color. Liquid sulfur is viscous and odorless, with a color ranging from bright yellow to dark orange (almost red) depending on temperature. Contaminants (particularly hydrogen sulfide) sometimes give sulfur the odor of rotten eggs.
Melting Point:
246°F (119°C)
Boiling Point:
832°F (444°C)
Liquid Specific Gravity: (water = 1.0)
1.80
Solid Specific Gravity: (water = 1.0)
2.07
Vapor Pressure:
0.05 PSIA (2.50 mm Hg) @ 400°F (204°C)
Odor Threshold:
N/A
Solubility in Water:
Negligible
ISSUE DATE: 06/13/95
SUPERSEDES: 02/19/93
PAGE 1 OF 10
MATERIAL SAFETY DATA SHEET SULFUR SECTION III- PHYSICAL DATA (continued) Other Solvents:
Other Solvents: Slightly soluble in Ethyl Alcohol; Ethyl Ether; Benzene; Toluene; Olive Oil.
Other Physical Data:
At temperatures up to about 317°F (158°C), the viscosity of pure liquid sulfur decreases as the temperature increases. As the temperature increases from 317°F to 370°F (158°C to 188°C), the viscosity of pure liquid sulfur rises rapidly to a tremendously high maximum, causing the liquid to become a dark, sticky, plastic material impossible to pump. SECTION IV - FIRE AND EXPLOSION INFORMATION
Fire and Explosion Hazard:
Solid - The primary hazard in handling solid sulfur results from the fact that sulfur dust suspended in the air ignites easily. Even though the explosion hazard is considered moderate, an explosion occurring in a confined area could cause considerable damage. Sulfur, being a very poor conductor of electricity, tends to develop static electric charges when it is in motion. Ignition of sulfur dust by static-caused sparks is not uncommon. Frictional heat in equipment has also been responsible for starting sulfur fires. Liquid - The fire hazards of liquid sulfur result primarily from the low ignition point of sulfur and from the presence of hydrogen sulfide.
Auto-Ignition Temperature:
450°F (232°C) for liquid sulfur 374°F (190°C) for sulfur dust suspended in air
Flash Point Temperature:
405°F (207°C)
Explosive Limits in Air:
Lower: 35 g/m3 (2.9% by wt)
Extinguishing Media:
Small Fires:
Water, dry chemical, soda ash, or sand. (1987 Emergency Response Guidebook, DOT P 5800.4)
Larger fires:
Use water spray, fog, or standard foam. (1987 Emergency Response Guidebook, DOT P 5800.4)
Upper: 1400 g/m3 (53% by wt)
Steam smothering can be used in storage pits and other relatively small enclosures. Carbon dioxide is also a satisfactory fire extinguishing agent. Fire-Fighting Procedures:
Straight streams of water from a nozzle can scatter molten sulfur and disperse sulfur dust into the air. Sulfur dust is a moderate explosion hazard when dispersed in air. As sulfur burns, it generates sulfur dioxide, a toxic gas. Wear self-contained breathing apparatus.
Unusual Hazards:
Small dust explosions may disperse larger quantities of dust into the air, resulting in a serious explosion, particularly in confined areas.
ISSUE DATE: 06/13/95
SUPERSEDES: 02/19/93
PAGE 2 OF 10
MATERIAL SAFETY DATA SHEET SULFUR SECTION V- HEALTH HAZARD DATA Permissible Exposure Level:
None indicated.
Threshold Limit Value:
None indicated.
Health Effects from Exposure Swallowing:
Acute Exposure - A man has survived ingestion of 60 grams of sulfur over a period of 24 hours. Large doses (15 grams) by mouth may lead to hydrogen sulfide production in vivo, chiefly due to bacterial action within the colon. Small particles are generally more toxic than large ones. If high levels of impurities are present, sore throat, nausea, headache, dullness, and possible unconsciousness may occur. Chronic Exposure - In medicine, it is used as a laxative. No adverse effects have been reported.
Inhalation:
Irritant. Acute Exposure - Inhalation of large amounts of dust may cause catarrhal inflammation of the nasal mucosa which may lead to hyperplasia with abundant nasal secretions. Tracheobronchitis is a frequent occurrence, with dyspnea, persistent cough, and expectoration, which may sometimes be streaked with blood. Chronic Exposure - Prolonged inhalation of dust may cause bronchopulmonary disease which, after several years, may be complicated by emphysema and bronchiectasis. Early symptoms in sulfur miners often include upper respiratory tract catarrh, with cough and expectoration which is mucoid and may even contain granules of sulfur. Asthma is a frequent complication. The maxillary and frontal sinuses may be affected; involvement is usually bilateral and pansinusitis may occur. Pulmonary function may be reduced. Radiological examinations have revealed irregular opacities in the lungs and occasionally nodulation has been reported.
Eye Contact:
Irritant. Acute Exposure - 8 PPM has caused irritation of human eyes. Dust may cause irritation, redness and pain with lacrimation, photophobia, conjunctivitis, and blepharoconjunctivitis; cases of damage to the crystalline lens have been reported with the formation of opacities and even cataract and focal chorioretinitis. Chronic Exposure - Low levels may cause conjunctivitis. Higher levels may cause symptoms similar to acute exposure.
ISSUE DATE: 06/13/95
SUPERSEDES: 02/19/93
PAGE 3 OF 10
MATERIAL SAFETY DATA SHEET SULFUR SECTION V - HEALTH HAZARD DATA (continued) Skin Contact:
Irritant. Acute Exposure - In highly purified form, the dust is low in irritation effects, but frequently impurities of hydrogen sulfide are present and may produce irritation or possibly burns. Chronic Exposure - Soaps, ointments, gels, and drugs containing sulfur are used as fungicides and parasiticides in the treatment of cutaneous disorders such as psoriasis, seborrhea, eczema-dermatitis, and scalp disorders. Sulfur possesses a keratolytic property which may be the basis of its therapeutic reaction. Prolonged local use of sulfur may result in characteristic dermatitis venenata, possibly with erythematous and eczematous lesions and signs of ulceration. Molten sulfur - Capable of inflicting severe burns.
First Aid Measures Swallowing:
Give water or fluids. Emesis is not necessary. Treat supportively and symptomatically. If irritation or digestive upset occurs, get medical attention.
Inhalation:
Remove from exposure area to fresh air immediately. If breathing has stopped, perform artificial respiration. Keep person warm and at rest. Get medical attention immediately.
Eye Contact:
Wash eyes immediately with large amounts of water, occasionally lifting upper and lower lids, until no evidence of chemical remains (approximately 15-20 minutes). Get medical attention immediately.
Skin Contact:
Remove contaminated clothing and shoes immediately. Wash affected area with soap or mild detergent and large amounts of water until no evidence of chemical remains (approximately 15-20 minutes). Get medical attention immediately.
ISSUE DATE: 06/13/95
SUPERSEDES: 02/19/93
PAGE 4 OF 10
MATERIAL SAFETY DATA SHEET SULFUR SECTION VI- REACTIVITY DATA Reactivity:
Stable under normal temperatures and pressures.
Incompatibilities:
Alkali Metal Nitrides:
Aluminum Powder: Aluminum Powder: Aluminum and Copper: Aluminum and Niobium Oxide: Ammonia: Ammonia Nitrate: Ammonia Perchlorate: Barium Bromate: Barium Carbide: Barium Chlorate:
Barium Iodate: Boron: Bromine Pentafluoride: Bromine Trifluoride: Cadmium: Calcium: Calcium Bromate: Calcium Carbide: Calcium Chlorate: Calcium Hypochlorite Powder: Calcium Hypochlorite: Calcium Iodate: Calcium Phosphide: Calcium, Vanadium Oxide, and Water: Cesium Nitride: Charcoal, Freshly Calcined: Chlorate and Copper: Chlorine Dioxide: Chlorine Monoxide: ISSUE DATE: 06/13/95
Highly flammable mixture which evolves ammonia and hydrogen sulfide in contact with water. Possible explosion if ignited with a magnesium fuse. Violent reaction. Possible explosion when heated in a closed container. Ignition. Possible formation of an explosive product. Possible explosion on impact. Possible explosion on impact. When both are finely divided, explosion with heat, percussion, or friction. Ignites in sulfur vapor at 150°C and incandesces. Possible spontaneous ignition at 108°C. When both are finely divided, explosion with heat, percussion, or friction. When both are finely divided, explosion with heat, percussion, or friction. Incandesces at 600°C. Violent reaction with possible ignition. Incandescence on contact. Vigorous reaction. Burns in the vapor at 400°C. Explodes on ignition. When both are finely divided, explosion with heat, percussion, or friction. Ignites in the vapor at 400°C. When both are finely divided, explosion with heat, percussion, or friction. Explosion if heated in closed vessel. With damp sulfur, produces a crimson flash with scattering of molten sulfur. When both are finely divided, explosion with heat, percussion, or friction. Incandesces at 300°C. Ignition. Intense reaction. Ignites spontaneously. Probable explosion. Ignition and possible explosion. Violent explosion.
SUPERSEDES: 02/19/93
PAGE 5 OF 10
MATERIAL SAFETY DATA SHEET SULFUR SECTION VI - REACTIVITY DATA (continued) Incompatibilities: (continued)
Chlorine Trifluoride: Chlorine Trioxide: Chromic Anhydride: Chromium Trioxide: Chromyl Chloride: Copper: Copper Alloy: Diarsenic Trisulfide: Dichlorine Monoxide: Diethyl Ether: Fiberglass and Iron Filings: Fluorine: Halogen Oxides: Heptasilver Nitrate Octaoxide: Hydrocarbons: Indium: Interhalogens: Iodine Pentafluoride: Iodine Pentoxide: Lampblack: Lead Chlorate: Lead Chloride: Lead Chlorite: Lead Chromate: Lead Dioxide: Lead (IV) Oxide: Lithium: Lithium dissolved in Ammonia: Lithium Carbide: Magnesium: Magnesium Bromate: Magnesium Chlorate: Magnesium Iodate: Mercuric Nitrate: Mercuric Oxide: Mercurous Oxide: Mercury (I) Oxide: Mercury (II) Oxide: Metal Acetylides of Carbides: Metal Chlorates:
ISSUE DATE: 06/13/95
Violent reaction with possible ignition. Possible violent reaction. Ignition on heating, possible explosion. Ignition on warming. Ignition. Attacked corrosively. Attacked corrosively. Formation of explosion mixture. Probable explosion. Possible explosion on evaporation. Exothermic reaction above 125°C. Ignition at ambient temperatures. Possible explosion. Explosion on impact. Explosive products produced on contact with molten sulfur. Ignition and incandescence on heating. Possible ignition or incandescent reaction. Incandescence on contact. Explosive reaction on warming. Spontaneous ignition. Possible spontaneous ignition at 63°C. Explosion. Explosion. Pyrophoric mixture. Explosion. Ignition on grinding or addition of sulfuric acid. When either is molten, explosively violent reaction. Vigorous reaction, even at -33°C. Burns in sulfur vapor. Vigorous reaction with molten sulfur or its vapor. When both are finely divided, explosion with heat, percussion, or friction. When both are finely divided, explosion with heat, percussion, or friction. When both are finely divided, explosion with heat, percussion, or friction. Possible explosion. Explosion when heated. Ignition on light impact. Ignition on frictional initiation. Explosion on heating. Possible ignition. Powerfully explosive, sensitive to friction or shock.
SUPERSEDES: 02/19/93
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MATERIAL SAFETY DATA SHEET SULFUR SECTION VI - REACTIVITY DATA (continued) Incompatibilities: (continued)
Metal Halogenates: Metal Oxides: Metals: Monorubidium Acetylide: Nickel Powder: Nitrogen Dioxide: Osmium: Oxidants: Palladium: Perchlorates (Inorganic): Permanganates: Phosphorus: Phosphorus, Red: Phosphorus, Yellow: Phosphorus Trioxide: Potassium: Potassium: Potassium Bromate:
Potassium Chlorate:
Potassium Chlorite: Potassium Iodate: Potassium Nitrate and Arsenic Trisulfide: Potassium Nitride: Potassium Perchlorate: Potassium Permanganate: Rhodium: Rubidium (Molten): Rubidium Acetylene Carbide: Selenium: Selenium Carbide: Silver Bromate: Silver Chlorate: Silver Chlorite: Silver Nitrate: ISSUE DATE: 06/13/95
Possible violent or explosive reaction. Possible ignition or explosion on initiation. Possible ignition or explosion. Ignites in molten sulfur. Ignition and incandescence in boiling sulfur or its vapor at 600°C. Sulfur burns vigorously. Ignition and incandescence in boiling sulfur or its vapor at 600°C. Possible ignition or explosion. Ignition and incandescence on heating. Explosive on impact. Formation of an explosive mixture. Ignition or explosion. Violent exothermic reaction or explosion. Ignition or explosion on heating. Violent reaction or explosion. Violent reaction on warming. Vapors of both react with chemiluminescence at 300°C and low pressure. Unstable mixture which may ignite after several hours. When both are finely divided, explosion may occur with heat, percussion, or friction. Ignition at 160-162°C. When both are finely divided, explosion with heat, percussion, or friction. Violent reaction. When both are finely divided, explosion with heat, percussion, or friction. Pyrotechnic formulation. Highly flammable mixture which evolves ammonia and hydrogen sulfide. Explosion on moderately strong impact. Possible explosion on heating. Ignition and incandescence on heating. Ignition in the vapor at 200-300°C. Ignition. Ignition. When heated, incandesces with the vapor. Ignition at 73-75°C. Explosive reaction in presence of water. Possible spontaneous ignition. Ignition at 74°C. Explosion on rubbing. Explosion on percussion.
SUPERSEDES: 02/19/93
PAGE 7 OF 10
MATERIAL SAFETY DATA SHEET SULFUR SECTION VI - REACTIVITY DATA (continued) Incompatibilities: (Continued)
Silver Oxide: Sodium: Sodium Bromate: Sodium Chlorate: Sodium Chlorite: Sodium Hydride: Sodium Iodate: Sodium Nitrate and Charcoal: Sodium Peroxide: Stannic Iodide and Potassium: Stannic Iodide and Sodium: Static Discharges: Steel: Strontium Carbide: Strontium Carbide and Selenium: Sulfur Dichloride: Tetraphenyllead: Thallic Oxide: Thorium: Thorium Carbide: Tin: Uranium: Uranium Carbide: Zinc Bromate: Zinc Chlorate: Zinc Iodate: Zinc Powder:
Ignition on grinding. Violent or explosive reaction with heat or friction. When both are finely divided, explosion with heat, percussion, or friction. When both are finely divided, explosion with heat, percussion, or friction. Ignition in presence of water. Vigorous reaction with vapors. When both are finely divided, explosion with heat, percussion, or friction. Explosion. Explosive mixture. Explosion on impact. Explosion on impact. Easily ignited due to very low minimum ignition energy. Attacked corrosively in presence of moisture. Incandescence or ignition in vapors about 500°C. Incandescence at 500°C. Very violent explosion on impact. Possible explosion. Explosion on grinding. Ignition and incandescence with heating. Incandesces when heated. Ignites in the vapors about 500°C. Vigorous reaction with incandescence. Ignition on heating. Incandescence and ignition with boiling sulfur or its vapor. Ignition in the vapors about 500°C. When both are finely divided, explosion with heat, percussion, or friction. When both are finely divided, explosion with heat, percussion, or friction. When both are finely divided, explosion with heat, percussion, or friction. Explosive reaction on warming.
Decomposition:
Combustion may release toxic oxides of sulfur, some of which may react with air and moisture to produce corrosive sulfurous and sulfuric acids. Toxic and corrosive hydrogen sulfide may be generated by molten sulfur.
Polymerization:
Hazardous polymerization has not been reported to occur under normal temperatures and pressures.
ISSUE DATE: 06/13/95
SUPERSEDES: 02/19/93
PAGE 8 OF 10
MATERIAL SAFETY DATA SHEET SULFUR SECTION VII- SPILL OR LEAK PROCEDURES Steps to Be Taken in Case Material is Released or Spilled Small Spill:
Shut off ignition sources. Do not touch spilled material. With clean shovel, place material into clean, dry container and cover; move containers from spill area.
Large Spill:
Shut off ignition sources. Do not touch spilled material. Wet down with water and dike for later disposal. No smoking, flames, or flares in hazard area! Keep unnecessary people away. Isolate hazard area and deny entry.
Waste Disposal Method Waste should be mixed with four times its weight of crushed limestone, marble, or shell, and then buried at a permitted disposal site. SECTION VIII- PROTECTIVE EQUIPMENT TO BE USED Ventilation:
Provide local exhaust or process enclosure ventilation to meet the published exposure limits. Ventilation equipment must be explosion-proof.
Respirator:
In routine handling of molten sulfur in adequately ventilated premises, respiratory protective equipment is not required, but should be available nearby. For areas containing sulfur dust, the specific respirator selected must be based on the contamination levels found in the work place, must not exceed the working limits of the respirator, and be jointly approved by the National Institute for Occupational Safety and Health and the Mine Safety and Health Administration. The following respirators are recommended based on the data found in the Physical Data and Health Hazard Data sections. They are ranked in order from minimum to maximum respiratory protection: Chemical cartridge respirator with an organic vapor cartridge(s) with a highefficiency particulate filter and full facepiece. High-efficiency particulate respirator with a full facepiece. Powered air-purifying respirator with a high-efficiency filter with a full facepiece. Type "C" supplied-air respirator with a full facepiece operated in pressure-demand or other positive pressure mode, or with a full facepiece, helmet, or hood operated in continuous-flow mode. Self-contained breathing apparatus with a full pressure-demand or other positive pressure mode.
ISSUE DATE: 06/13/95
SUPERSEDES: 02/19/93
facepiece
operated
in
PAGE 9 OF 10
MATERIAL SAFETY DATA SHEET SULFUR SECTION VIII- PROTECTIVE EQUIPMENT TO BE USED Respirator: (continued)
For firefighting and other immediately dangerous to life or health conditions: Self-contained breathing apparatus with a full pressure-demand or other positive pressure mode.
facepiece
operated
in
Supplied-air respirator with a full facepiece operated in pressure-demand or other positive pressure mode in combination with an auxiliary self-contained breathing apparatus operated in pressure-demand or other positive pressure mode. Clothing:
Employees operating equipment containing molten sulfur should wear clothing capable of protecting the chest and arms, trousers without cuffs, and high-top shoes. When making connections or other changes in molten sulfur piping, leather protective clothing may be needed.
Gloves:
Employee must wear heat-resistant gloves when working with molten sulfur.
Eye Protection:
Employee must wear splash-proof or dust-resistant safety goggles to prevent eye contact with this substance. When making connections or other changes in molten sulfur piping, full face shields (in addition to safety glasses or goggles) should be worn.
SECTION IX - SPECIAL PRECAUTIONS OR OTHER COMMENTS
Disclaimer The information contained herein is believed to be accurate, but is not warranted to be, whether originating within the company or not. Health and safety precautions in this data sheet may not be adequate for all individuals and/or situations. Recipients are advised to confirm in advance of need that the information is current, applicable, and suitable to their circumstances. It is the end user’s responsibility to evaluate and use this product safely, and to comply with all applicable laws and regulations. No statement made in this data sheet shall be construed as a permission or recommendation for use of any product in a manner that might infringe existing patents. No warranty is made, either expressed or implied.
ISSUE DATE: 06/13/95
SUPERSEDES: 02/19/93
PAGE 10 OF 10
MATERIAL SAFETY DATA SHEET
AMMONIA SECTION I - PRODUCT IDENTIFICATION Substance:
AMMONIA
CAS Number: 7664-41-7
Trade Names / Synonyms:
Ammonia Anhydrous; Ammonia Gas; Spirit of Hartshorn
Molecular Formula:
NH3
General or Generic ID:
Inorganic Gas
Molecular Weight:
17.03
SECTION II - COMPONENTS Component:
Ammonia
Percent: > 99.0
Other Contaminants: Exposure Limits:
Ammonia 50 PPM OSHA TWA per 8-hour working day 35 PPM ACGIH STEL 50 PPM NIOSH recommended 5 minute ceiling SECTION III - PHYSICAL DATA
Description
Colorless gas at atmospheric temperature and pressure, with a pungent odor.
Melting Point:
-108°F (-78°C)
Boiling Point:
Liquid Specific Gravity: (water = 1.0)
0.77
Vapor Specific Gravity: 0.59 (air = 1.0)
Vapor Pressure:
147 PSIA (10 atm) @ 78°F (25°C)
Odor Threshold:
20 PPM
Solubility in Water:
579 g/l @ 60°F (15°C), 444 g/l @ 68°F (20°C)
-28°F (-33°C)
Other Solvents: Other Physical Data:
ISSUE DATE: 06/29/06
SUPERSEDES: 02/19/93
PAGE 1 OF 5
MATERIAL SAFETY DATA SHEET
AMMONIA SECTION IV - FIRE AND EXPLOSION INFORMATION Fire and Explosion Hazard:
Ammonia is a low fire hazard when exposed to heat or flame because it is difficult to ignite. It is a moderate explosion hazard when exposed to flame or fire. Air-ammonia mixtures can detonate in a fire.
Auto-Ignition Temperature:
1204°F (651°C)
Flash Point Temperature:
N/A
Explosive Limits in Air:
Lower: 15%
Upper:
28%
Extinguishing Media:
Water Fog.
Hazardous Decomposition Products:
Toxic fumes of NH3 and NOX.
Fire-Fighting Procedures:
Stop flow of gas. Wear self-contained breathing apparatus with a full facepiece operated in pressure-demand mode and full body protection when fighting fires.
SECTION V- HEALTH HAZARD DATA Permissible Exposure Level:
50 PPM
Threshold Limit Value:
25 PPM
Health Effects from Exposure
Swallowing:
Ingestion of a gas is unlikely.
Inhalation:
The life hazard from ammonia is due to its damage to the lungs when inhaled. When inhaled, ammonia is both an irritant and an asphyxiant, and can cause respiratory distress. Ammonia can usually be detected at levels of 20-50 PPM. There will be noticeable irritation of the eyes and nasal passages when exposed to 100 PPM, and severe irritation of the throat, nasal passages, and upper respiratory tract at 400 PPM. At 1700 PPM, there will be severe coughing and bronchial spasms, and an exposure of 30 minutes or less may be fatal. Concentrations of 5000 PPM and above are fatal almost immediately, causing serious edema of the lungs, strangulation, and asphyxiation.
Eye Contact:
This gas is dangerous to the eyes, as it causes irritation at 40-100 PPM. Prolonged exposure to 700 PPM or more can cause extensive injuries to the eyes - irritation, hemorrhages, swollen lids, corneal ulcers, even partial or total loss of sight.
Skin Contact:
Ammonia will irritate the skin, particularly if the skin is moist, to the point of causing chemical burns from prolonged exposure.
ISSUE DATE: 06/29/06
SUPERSEDES: 02/19/93
PAGE 2 OF 5
MATERIAL SAFETY DATA SHEET
AMMONIA SECTION V - HEALTH HAZARD DATA (continued) First Aid Measures Swallowing:
Treat symptomatically and supportively. Get medical attention immediately. If vomiting occurs, keep head lower than hips to prevent aspiration.
Inhalation:
Where breathing is weak, administer oxygen or mixtures of carbon dioxide and oxygen, containing not more than 5% carbon dioxide. It should be administered intermittently for periods of two minutes over a total time not to exceed fifteen minutes. If breathing has ceased, start artificial respiration immediately, by trained personnel only. Artificial respiration, when administered by an inexperienced person, is definitely hazardous following exposure to ammonia, and should be avoided where possible. The use of a pulmotor is definitely not recommended as its more violent action will irritate and may severely injure the lungs. A resuscitator used with oxygen and operated by a trained person is recommended. Keep the patient warm and still, and get medical attention immediately.
Eye Contact:
Hold the lids open and pour clean water over the eyeball and lids (or use an eye irrigation fountain). Wash thoroughly in this way for 15 minutes. A doctor, preferably an eye specialist, should be summoned immediately
Skin Contact:
Speed is essential. Strip the ammonia-saturated clothing from the body immediately. Flood affected areas continuously with clean water for at least 15 minutes. Do not cover burns with clothing or dressings. Allow them to remain open to the air.
ISSUE DATE: 06/29/06
SUPERSEDES: 02/19/93
PAGE 3 OF 5
MATERIAL SAFETY DATA SHEET
AMMONIA SECTION VI- REACTIVITY DATA Reactivity:
Stable under normal temperatures and pressures.
Incompatibilities:
Acetaldehyde Acrolein Ammonium Peroxo Disulfate Antimony Antimony Hydride Boron Boron Halides Boron Triiodide Bromine Pentafluoride Chloric Acid Chlorine Azide Chlorine Monoxide Chlorine Trifluoride Chlorites Chlorosilane Chromium Trioxide Chromyl Chloride Dichlorine Oxide Ethylene Dichloride + Liquid Ammonia Ethylene Oxide Gold Gold (III) Chloride Halogens Hexachloromelamine Hydrazine + Alkali Metals Hydrogen Bromide Hydrogen Peroxide Hypochlorous Acid Magnesium Perchlorate Mercury Nitric Acid
Polymerization:
Nitrogen Dioxide Nitrogen Tetraoxide Nitrogen Trichloride Nitrogen Trifluoride Nitryl Chloride Oxygen + Platinum Oxygen Difluoride Phosphorus Pentoxide Phosphorus Trioxide Picric Acid Potassium + Arsine Potassium + Phosphine Potassium + Sodium Nitrite Potassium Chlorate Potassium Ferricyanide Potassium Mercuric Cyanide Silver Silver Chloride Silver Nitrate Silver Oxide Sodium + Carbon Monoxide Sulfur Sulfur Dichloride Tellurium Tellurium Chloride Tellurium Hydropentachloride Tetramethyl Ammonium Amide Thionyl Chloride Thiotrithiazyl Chloride Trichloromelamine Trioxygen Difluoride
Cannot occur. SECTION VII - SPILL OR LEAK PROCEDURES
Steps to Be Taken in Case Material is Released or Spilled Notify safety personnel of significant leaks. Exclude all from area except those assigned to leak and spill control who are using full protective gear (see Section VIII). Provide ventilation. Locate and control leakage. Waste Disposal Method If water is used to knock-down vapors, it will be corrosive and toxic, and should be diked for containment. Add suitable agent to neutralize to 7 pH prior to disposal. ISSUE DATE: 06/29/06
SUPERSEDES: 02/19/93
PAGE 4 OF 5
MATERIAL SAFETY DATA SHEET
AMMONIA SECTION VIII - PROTECTIVE EQUIPMENT TO BE USED Ventilation:
Provide local exhaust or process enclosure ventilation to meet the published exposure limits. Ventilation equipment must be explosion-proof.
Respirator:
If work place exposure limit(s) of product or any component is exceeded (see Section II), a NIOSH/MSHA approved air supplied respirator is advised in absence of proper environmental control. OSHA regulations also permit other NIOSH/MSHA respirators (negative pressure type) under specified conditions (see your safety equipment supplier). Engineering or administrative controls should be implemented to reduce exposure.
Clothing:
To prevent repeated or prolonged skin contact, wear impervious clothing and boots.
Gloves:
Wear resistant gloves such as neoprene, nitrile rubber, butyl rubber.
Eye Protection:
Employee must wear splash-proof or dust resistant safety goggles and a faceshield to prevent contact with this substance. Where there is any possibility that an employee's eyes may be exposed to this substance, the employer shall provide an eye-wash fountain within the immediate work area for emergency use.
SECTION IX - SPECIAL PRECAUTIONS OR OTHER COMMENTS
DISCLAIMER The information contained herein is believed to be accurate, but is not warranted to be, whether originating within the company or not. Health and safety precautions in this data sheet may not be adequate for all individuals and/or situations. Recipients are advised to confirm in advance of need that the information is current, applicable, and suitable to their circumstances. It is the end user's responsibility to evaluate and use this product safely, and to comply with all applicable laws and regulations. No statement made in this data sheet shall be construed as a permission or recommendation for use of any product in a manner that might infringe existing patents. No warranty is made, either expressed or implied.
ISSUE DATE: 06/29/06
SUPERSEDES: 02/19/93
PAGE 5 OF 5
MATERIAL SAFETY DATA SHEET METHYLDIETHANOLAMINE SECTION I - PRODUCT IDENTIFICATION Substance:
METHYLDIETHANOLAMINE
CAS Number: 105-59-9
Trade Names / Synonyms:
MDEA; n-Methyldiethanolamine; n-Methyliminodiethanol; n-Methyl-2,2'-iminodiethanol; N,N-di(2-hydroxyethyl)-N-methylamine; 2,2'(Methylimino) bis-ethanol
Molecular Formula:
CH3-N-(CH2CH2OH)2
General or Generic ID:
Organic Base
Molecular Weight:
119.17
SECTION II - COMPONENTS Component:
Methyldiethanolamine
Percent: > 99.0
Other Contaminants:
Often stored and transported as an aqueous solution containing about 10% water by weight.
Exposure Limits:
Methyldiethanolamine There are no standards or regulations concerning MDEA. SECTION III - PHYSICAL DATA
Description:
Clear, colorless, viscous liquid.
Melting Point:
-6F (-21C)
Boiling Point:
477F (247C)
Liquid Specific Gravity: (water = 1.0)
1.042
Vapor Specific Gravity (air = 1.0)
4.11
Vapor Pressure:
< 0.0002 PSIA (0.01 mm Hg) @ 68F (20C)
Odor Threshold:
MDEA has a slight ammoniacal odor.
Solubility in Water:
MDEA is completely soluble in water.
Other Solvents: Other Physical Data:
ISSUE DATE: 01/25/95
SUPERSEDES:
PAGE 1 OF 3
MATERIAL SAFETY DATA SHEET METHYLDIETHANOLAMINE SECTION IV- FIRE AND EXPLOSION INFORMATION Fire and Explosion Hazard: MDEA is considered a slight fire hazard when exposed to heat or flame. Auto-Ignition Temperature:
N/A
Explosive Limits in Air:
not determined
Extinguishing Media:
Small Fire - dry chemical or CO2. Large Fire - water fog, alcohol foam, polymer foam, ordinary foam.
Fire-Fighting Procedures:
Wear positive pressure, self-contained breathing apparatus. SECTION V - HEALTH HAZARD DATA None established.
Permissible Exposure Level: Threshold Limit Value:
Flash Point Temperature:
260F (127°C)
None established.
Health Effects from Exposure Swallowing:
Single dose oral toxicity is low. The oral LD50 for rats is 4780 mg/kg for MDEA. Amounts ingested incidental to industrial handling are not likely to cause injury; however, ingestion of larger amounts may cause injury. Ingestion of MDEA can cause nausea, vomiting, and abdominal discomfort.
Inhalation::
At room temperature, exposure to vapors is unlikely due to physical properties. Higher temperatures may generate vapor levels sufficient to cause irritation.
Eye Contact:
May cause moderately severe irritation with corneal injury.
Skin Contact:
Prolonged or repeated exposure may cause skin irritation, even a burn. A single prolonged exposure is not likely to result in the material being absorbed through skin in harmful amounts. The dermal LD50 has not been determined.
Systemic Effects:
Repeated excessive exposures may cause kidney effects.
First Aid Measures Swallowing:
Induce vomiting if large amounts are ingested. Consult medical personnel.
Inhalation:
Remove to fresh air if effects occur. Consult a physician.
Eye Contact:
Flush eyes with large amounts of water for at least 15 minutes. Take the patient to a physician, preferably an eye specialist, at once.
Skin Contact:
Flush the affected area with plenty of water. If exposure has produced a burn, it should be treated like a thermal burn, with treatment based on the physician's judgement. Contaminated clothing should be removed and washed before reuse. Contaminated leather articles (shoes, belts, etc.) should be removed and destroyed. SUPERSEDES: PAGE 2 OF 3
ISSUE DATE: 01/25/95
MATERIAL SAFETY DATA SHEET METHYLDIETHANOLAMINE SECTION VI- REACTIVITY DATA Reactivity:
Stable under normal storage conditions.
Incompatibilities:
Incompatible with strong oxidizers and strong acids. Do not allow MDEA to contact sodium nitrite (NaNO2) or other nitrosating agents, as nitrosamines (suspected cancer-causing agents) could be formed.
Hazardous Decomposition Products:
Nitrous oxides, carbon monoxide, and/or carbon dioxide.
Polymerization
Hazardous polymerization will not occur. SECTION VII - SPILL OR LEAK PROCEDURES
Steps to Be Taken in Case Material is Released or Spilled Wear suitable protective equipment, especially eye protection. Collect for disposal. Toxic to fish; avoid discharge to natural waters. Waste Disposal Method Burn in approved incinerator. Follow all local, state, and federal requirements for disposal. SECTION VIII - PROTECTIVE EQUIPMENT TO BE USED Ventilation:
General (mechanical) room ventilation is expected to be satisfactory.
Respirator:
None required in normal use. If irritation of the nose and/or respiratory system is experienced, use an approved air-purifying respirator.
Clothing:
Use protective clothing impervious to this material. Selection of specific items such as boots, apron, or full-body suit will depend on operation.
Gloves:
Use gloves impervious to this material, such as rubber.
Eye Protection:
Use chemical goggles. SECTION IX - SPECIAL PRECAUTIONS OR OTHER COMMENTS
Avoid contact with eyes, skin, and clothing when handling and storing MDEA. handling.
Wash thoroughly after
Disclaimer The information contained herein is believed to be accurate, but is not warranted to be, whether originating within the company or not. Health and safety precautions in this data sheet may not be adequate for all individuals and/or situations. Recipients are advised to confirm in advance of need that the information is current, applicable, and suitable to their circumstances. It is the end user’s responsibility to evaluate and use this product safely, and to comply with all applicable laws and regulations. No statement made in this data sheet shall be construed as a permission or recommendation for use of any product in a manner that might infringe existing patents. No warranty is made, either expressed or implied.
ISSUE DATE: 01/25/95
SUPERSEDES:
PAGE 3 OF 3
MATERIAL SAFETY DATA SHEET SODIUM HYDROXIDE SECTION I - PRODUCT IDENTIFICATION SODIUM HYDROXIDE
Substance:
CAS Number: 1310-73-2
Trade Names / Synonyms:
Caustic; Caustic Soda; Caustic Soda Liquid; Liquid Caustic; Lye; Lye Solution; Soda Lye; Sodium Hydrate; Quaker Caustic Blend; White Caustic
Molecular Formula:
NaOH
General or Generic ID:
Alkali
Component:
Molecular Weight:
SECTION II - COMPONENTS Sodium Hydroxide
40.00
Percent: > 99.0
Other Contaminants:
Often stored and transported as an aqueous solution. Common strengths are 25, 50, and 73 weight percent NaOH.
Exposure Limits:
Sodium Hydroxide 2 mg/m3 (2 PPM) OSHA TWA for an 8-hour working day 2 mg/m3 (2 PPM) ACGIH ceiling 2 mg/m3 (2 PPM) NIOSH recommended ceiling
Description:
SECTION III - PHYSICAL DATA Pure sodium hydroxide is a white solid. When dissolved in water, NaOH forms a clear, colorless or water-white, strongly alkaline liquid. Neither form has an odor.
Melting Point:
Solid: 25 wt% solution: 50 wt% solution:
608°F (320°C) -2°F (-19°C) 50°F (10°C)
Boiling Point:
Solid: 25 wt% solution: 50 wt% solution:
2534°F (1390°C) 232°F (111°C) 288°F (142°C)
Specific Gravity: (water = 1.0)
Solid: 25 wt% solution: 50 wt% solution:
2.13 1.27 1.53
Vapor Pressure:
Solid:
0.02 PSIA (1 mm Hg) @ 1362°F (739°C)
Odor Threshold:
N/A
Solubility in Water:
At 60°F (15°C), more than 50 wt% will dissolve in water.
Other Solvents: Other Physical Data:
ISSUE DATE: 02/19/93
SUPERSEDES:
PAGE 1 OF 5
MATERIAL SAFETY DATA SHEET SODIUM HYDROXIDE SECTION IV- FIRE AND EXPLOSION INFORMATION Fire and Explosion Hazard:
Sodium hydroxide and its water solutions are not flammable. However, adding water to NaOH or solutions of NaOH can cause localized overheating due to its heat of dilution. Sodium hydroxide will generate gaseous hydrogen (which is flammable and/or explosive) when in contact with aluminum, copper, tin, zinc, and their alloys.
Auto-Ignition Temperature:
N/A
Flash Point Temperature:
N/A
Explosive Limits in Air:
Lower: N/A
Upper: N/A
Extinguishing Media:
Not combustible. Use extinguishing agents as may be suitable for material in surrounding fire.
Fire-Fighting Procedures:
Not combustible. Use clothing and safety equipment as may be suitable for sodium hydroxide and materials in the surrounding fire.
SECTION V - HEALTH HAZARD DATA Permissible Exposure Level:
2 mg/m3 (approximately 2 PPMW)
Threshold Limit Value:
2 mg/m3 (approximately 2 PPMW) ceiling
Health Effects from Exposure Swallowing:
Acutely toxic if swallowed, causing severe burns and scarring to the mouth, throat, esophagus, and stomach, and may lead to death. Squamous cell carcinoma of the esophagus can occur years after the exposure.
Inhalation:
Inhalation of dust or mist can cause injury to the entire respiratory tract. The effects of inhalation depend on the severity of the exposure, ranging from mild irritation of the mucous membranes to severe pneumonitis.
Eye Contact:
Contact with the eyes may cause irritation and, with greater exposure, severe burns and possible blindness.
Skin Contact:
Skin contact may cause burns, frequently with deep ulceration and scarring. Prolonged contact, even with dilute solutions, can cause tissue damage.
ISSUE DATE: 02/19/93
SUPERSEDES:
PAGE 2 OF 5
MATERIAL SAFETY DATA SHEET SODIUM HYDROXIDE SECTION V - HEALTH HAZARD DATA (continued) First Aid Measures Swallowing:
Do not induce vomiting - this will cause further damage to the throat and esophagus. Dilute by giving water to the patient immediately. Vinegar, 1% acetic acid solution, citrus fruit juices, or 5% citric acid solution may also be administered to help neutralize the alkaline solution. Follow this with milk, egg white in water, or milk of magnesia. Keep the patient warm and still, and summon a physician immediately.
Inhalation:
Remove the patient to fresh air at once. If breathing has stopped, begin artificial respiration immediately. Keep the patient warm and still, and summon a physician immediately.
Eye Contact:
Immediately begin flushing the eyes with large amounts of water, preferably with an eye wash fountain. Continue flushing for at least 15 minutes, forcibly holding the eyelids apart and rotating the eyeball, to ensure complete irrigation of all eye and lid tissue. A physician, preferably an eye specialist, should be summoned immediately.
Skin Contact:
Immediately flush the affected areas with large amounts of water. If large areas of the body are contaminated, or if clothing has been penetrated to the skin, immediately use a safety shower, preferably removing clothing while under the shower. Continue flushing the areas for at least 15 minutes. If available, follow the water flush with a generous application of vinegar or 1% acetic acid solution to neutralize the residual NaOH. After the acid treatment, apply a good protective dressing as with any other burn and take the patient to a physician. Contaminated clothing should be washed before reuse. Contaminated leather articles (shoes, belts, etc.) should be discarded.
ISSUE DATE: 02/19/93
SUPERSEDES:
PAGE 3 OF 5
MATERIAL SAFETY DATA SHEET SODIUM HYDROXIDE SECTION VI- REACTIVITY DATA Reactivity:
Stable.
Incompatibilities:
Acetaldehyde Acetic Acid Acetic Anhydride Acrolein Acrylonitrile Allyl Alcohol Allyl Chloride Aluminum Chlorine Trifluoride Chloroform + Methanol Chlorohydrin (Chlorhydrin) 4-Chloro-2-methylphenol Chloronitrotoluene Chlorosulfonic Acid (Chlorosulfuric Acid) Cinnamaldehyde Copper Cyanogen Azide Diborane (Boron Hydride) 1,2-Dichloroethylene Difluoroethane Ethylene Cyanohydrin (Hydracrylonitrile) Glyoxal Hydrochloric Acid (Hydrogen Chloride) Hydrofluoric Acid (Hydrogen Fluoride)
Polymerization:
Hazardous polymerization cannot occur.
Other Hazards:
Adding water to sodium hydroxide or sodium hydroxide solutions may cause localized overheating and spattering.
ISSUE DATE: 02/19/93
SUPERSEDES:
Hydroquinone Magnesium Maleic Anhydride Methanol + Tetrachlorobenzene 4-Methyl-2-nitrophenol 3-Methyl-2-penten-4-yn-1-ol Nitric Acid Nitroethane (forms shock-sensitive salts) Nitromethane (forms shock-sensitive salts) Nitroparaffins (forms shock-sensitive salts) Nitropropane (forms shock-sensitive salts) Oleum (fuming Sulfuric Acid) Pentol Phosphorus Phosphorus Pentoxide ß-Propiolactone (2-Oxetanone) Strong Mineral or Organic Acids Sulfuric Acid 1,2,4,5-Tetrachlorobenzene Tetrahydrofuran Tin 1,1,1-Trichloroethanol Trichloroethylene Trichloronitromethane Trifluoride Water Zinc Zirconium
PAGE 4 OF 5
MATERIAL SAFETY DATA SHEET SODIUM HYDROXIDE SECTION VII - SPILL OR LEAK PROCEDURES Steps to Be Taken in Case Material is Released or Spilled Cleanup personnel must wear proper protective equipment (refer to Section VIII). Completely contain spilled material with dikes, sandbags, etc., and prevent run-off into ground or surface waters or sewers. Recover as much material as possible into containers for disposal. Remaining material may be diluted with water and neutralized with dilute hydrochloric acid. Neutralization products, both liquid and solid, must be recovered for disposal. Waste Disposal Method Recovered solids or liquids may be sent to a licensed reclaimer or disposed of in a permitted waste management facility. Consult federal, state, or local disposal authorities for approved procedures.
SECTION VIII - PROTECTIVE EQUIPMENT TO BE USED Ventilation:
Ventilation is not usually required for caustic solutions. Avoid creation of mist or spray. If present, wear appropriate safety clothing and provide local exhaust systems.
Respirator:
Provide mist protection where applicable. respirators.
Clothing:
Employees should wear impervious rubber, neoprene, or vinyl boots, overalls, and/or full-body suits.
Gloves:
Use impervious rubber, neoprene, or vinyl gloves.
Eye Protection:
Use chemical goggles and face shield.
Use NIOSH or MSHA approved
SECTION IX - SPECIAL PRECAUTIONS OR OTHER COMMENTS When diluting sodium hydroxide, use agitation (mixing) and add the concentrated sodium hydroxide to water at a controlled rate to control the heat of dilution and avoid spattering. Never add water to sodium hydroxide.
Disclaimer The information contained herein is believed to be accurate, but is not warranted to be, whether originating within the company or not. Health and safety precautions in this data sheet may not be adequate for all individuals and/or situations. Recipients are advised to confirm in advance of need that the information is current, applicable, and suitable to their circumstances. It is the end user’s responsibility to evaluate and use this product safely, and to comply with all applicable laws and regulations. No statement made in this data sheet shall be construed as a permission or recommendation for use of any product in a manner that might infringe existing patents. No warranty is made, either expressed or implied.
ISSUE DATE: 02/19/93
SUPERSEDES:
PAGE 5 OF 5
MATERIAL SAFETY DATA SHEET 1. CHEMICAL PRODUCT AND COMPANY INFORMATION Product Name:
Activated Alumina S-2001/ESM-221
Product Use:
Alumina
ASM Catalysts, LLC 8550 United Plaza Blvd., Suite 702 Baton Rouge, LA 70809-0200 USA Tel.: +1-225-752-4276 Fax: +1-225-922-4550
Euro Support B.V. Kortegracht 26 3811 KH Amersfoort The Netherlands Tel: +31-33-4650465 Fax: +31-33-4650721
2. HAZARDS IDENTIFICATION Emergency Overview: Repeated or prolonged exposure may irritate eyes, skin and respiratory system. The product gets hot as it first adsorbs water. Form: Spheres Color: White Potential Health Effects: Primary Routes of Exposure: Contact with skin and eyes. Exposure may also occur via inhalation or ingestion if product dust is generated. Eye Contact: Dust and/or product may cause eye discomfort and/or irritation seen as tearing and reddening. Skin Contact: Repeated or prolonged exposure may cause skin irritation. Ingestion: The product is considered to have a low order of oral toxicity. Inhalation: Exposure to dust particles generated from this material may cause irritation of the respiratory tract. Irritation may be accompanied by coughing and chest discomfort. Chronic Effects: Prolonged or repeated inhalation of dust generated from this material may cause lung injury.
Activated Alumina S-2001/ESM-221 Page 1 of 9
Revision Number: 1 June 2008
Carcinogenicity Classification: International Agency for Research on Cancer (IARC): Neither the product nor the components are classified. U.S. National Toxicology Program (NTP): Neither the product nor the components are classified. U.S. Occupational Safety and Health Administration (OSHA): Neither the product nor the components are classified or regulated. American Conference of Governmental Industrial Hygienists (ACGIH): Aluminum oxide – Not Classifiable as a Human Carcinogen (A4).
3. COMPOSITION/INFORMATION ON INGREDIENTS INGREDIENT & CAS NO. Aluminum oxide (non-fibrous) 1344-28-1 Water 7732-18-5
ACGIH TLV-TWA
OSHA PEL-TWA
<95
1(R)
<10
N.E.
15 (TD) 5(R) N.E.
% WEIGHT
Abbreviations: N.A. - Not Applicable N.E. - None Established STEL - Short Term Exposure Limit
RD R F
- Respirable Dust - Respirable Fraction - Respirable Fibers
Fu I TD
- Fume - Inhalable - Total Dust
UNITS mg/m3 N.A.
IS FuD SC
- Insoluble - Fume and Dust - Soluble Compounds
4. FIRST AID MEASURES Eye contact: Flush immediately with plenty of water for at least 15 minutes. If eye irritation persists, consult a physician. Skin contact: Wash off with soap and plenty of water. If skin irritation persists, call a physician. After inhalation: Remove the victim into fresh air. If symptoms persist, call a physician. After ingestion: Drink at least 2 glasses of water. Obtain medical attention. Never give anything by mouth to an unconscious person. Notes to physician: This product is a desiccant and generates heat as it adsorbs water. Symptomatic treatment is advised. The used product can retain material of a hazardous nature. Identify that material and treat symptomatically.
Activated Alumina S-2001/ESM-221 Page 2 of 9
Revision Number: 1 June 2008
5. FIRE FIGHTING MEASURES Suitable extinguishing media: Non-combustible. Use extinguishing media for surrounding fire. Unsuitable extinguishing media: N.A. Fire and explosion hazards: The product itself does not burn. The used product can retain material of a hazardous nature. Identify that material and inform the fire fighters. Special protective equipment: In the case of respirable dust and/or fumes, use self-contained breathing apparatus and dust impervious protective suit. Flash point: N.A.
6. ACCIDENTAL RELEASE MEASURES Personal protection: See Section 8. Environmental precautions: No special environmental precautions required. Clean-up: Sweep, shovel or vacuum spilled product into appropriate containers (do not use a vacuum if material has contacted a hydrocarbon material). Pick-up and arrange disposal without creating dust. Never use spilled product. Spilled product should be disposed of in accordance with all applicable government regulations.
7. HANDLING AND STORAGE Handling: Handle and open container with care. Avoid formation of dust particles. Avoid contact with skin and eyes. Provide an electrical ground connection during loading and transfer operations to avoid static discharge in an explosive atmosphere and to prevent persons handling the product from receiving static shocks. Storage: Store in original container. Keep in a dry place.
8. EXPOSURE CONTROLS/PERSONAL PROTECTION Engineering measures: Where natural ventilation is inadequate, especially in confined areas, use mechanical ventilation, other engineering controls or respiratory protection to prevent inhalation of product dust. Personal protection equipment: Handle in accordance with good industrial hygiene and safety practice. Eye protection: Safety glasses or goggles. Hand protection: Protective gloves. Skin and body protection: Work uniform and gloves to prevent prolonged contact. Respiratory protection: In case of insufficient ventilation, wear suitable respiratory equipment. Air-purifying respirator with NIOSH classification N-95 filter or P-95 (or equivalent) if oil/liquid aerosols are present (42 CFR 84).
Activated Alumina S-2001/ESM-221 Page 3 of 9
Revision Number: 1 June 2008
9. PHYSICAL AND CHEMICAL PROPERTIES These data do not represent technical or sales specifications.
Form: Spheres
Color: White
Odor: None
pH: 9 – 11 (AS)
Boiling point/range: None
Melting point/range: N.A.
Flash point: N.A.
Autoignition temperature: N.A.
Bulk density: 38-60 lbs/ft3
Explosion limits: N.A.
Vapor pressure: N.A.
Relative density/Specific gravity: 3.0
Vapor density: N.A.
Viscosity: N.A.
Water solubility: Insoluble
Solubility: N.D.
10. STABILITY Stability: Stable Hazardous Decomposition Products: No decomposition if used as directed. Hydrocarbons and other materials that contact the product during normal use can be retained on the product. It is reasonable to expect that decomposition products will come from these retained materials of use. If the product is subject to extreme temperatures or chemical conditions, decomposition may occur and he product will include the oxides shown in Section 3. Conditions/Materials to avoid: Reacts violently with chlorine trifluoride, producing flames. May cause ethylene oxide to polymerize violently, releasing heat.
Activated Alumina S-2001/ESM-221 Page 4 of 9
Revision Number: 1 June 2008
11. TOXICOLOGICAL INFORMATION Acute toxicity: LD50/oral/rat: No data available. LD50/dermal/rabbit: No data available. LD50/inhalation/rat: No data available. Chronic toxicity: Classification of Ingredients EC Carcinogenic: Not listed.
Carcinogenicity (ACGIH): A4 (Aluminum oxide)
EC Mutagenic: Not listed.
IARC classification: Not listed.
EC Toxic for Reproduction: Not listed. Routes of exposure: Exposure may occur via inhalation, contact with skin and eyes. Irritation: Skin (rabbit): No data available. Eye (rabbit): No data available. Additional product information: Avoid repeated exposure. Additional component information: No data available.
12. ECOLOGICAL INFORMATION Mobility: No data available.
Biodegradation: No data available.
Bioaccumulation: No data available.
Aquatic toxicity: No data available.
Further Information: No information available.
Activated Alumina S-2001/ESM-221 Page 5 of 9
Revision Number: 1 June 2008
13. DISPOSAL CONSIDERATIONS Provisions relating to waste: EPA – Resource Conservation and Recovery Act (RCRA) Hazardous and Solid Waste Management Regulations. Disposal information: This product (in its fresh unused state) is not listed by generic name or trademark name in the U.S. EPA’s RCRA regulations and does not possess ay of the four identifying characteristics of hazardous waste (ignitability, corrosivity, reactivity or toxicity). Materials of a hazardous nature that contact the product during normal use may be retained on this product. The user of the product must identify the hazards associated with the retained material in order to assess the waste disposal options.
14. TRANSPORT INFORMATION Proper shipping name: Not applicable.
UN-No.: N.A.
Packing group: N.A.
Transport mode
Class
U.S. DOT:
Not regulated.
Reportable N.A. Quantity: Marine Pollutant DOT: No
N.A.
ADR/RID:
Not regulated.
Danger Code:
N.A.
N.A.
IMDG:
Not regulated.
Marine pollutant: EmS:
No N.A.
N.A.
IATA:
Not regulated.
Instr. Passenger: Instr. Cargo:
N.A. N.A.
N.A.
Additional Information
Activated Alumina S-2001/ESM-221 Page 6 of 9
Remarks
Revision Number: 1 June 2008
15. REGULATORY INFORMATION United States Toxic Substances Control Act (TSCA): All the ingredients of this mixture are registered on the TSCA Chemical Substance Inventory. CERCLA (Comprehensive Environmental Response, Compensation, and Liability Act) Reportable Quantity: The following component(s) of this product is/are subject to release reporting under 40 CFR 302 when release exceeds the Reportable Quantity (RQ): --None— SARA Title III (Superfund Amendments and Reauthorization Act of 1986): Section 302 (Extremely Hazardous Substances): The following component(s) of this product is/are subject to the emergency planning provisions of 40 CFR 355 when there are amounts equal to or greater than the Threshold Planning Quantity (TPQ): --None— Section 313 (toxic Chemicals): The following component(s) have been specified as Toxic Chemicals under SARA Section 313 and may be subject to the Toxic Release Inventory (TRI) reporting requirements under 40 CFR 372: --None— The following components are listed in U.S. State Regulations: State Reg Reference: State Reg Reference: California – Proposition 65:
None.
Massachusetts Right-to-Know:
Aluminum oxide
New Jersey Right-To-Know:
Aluminum oxide
Pennsylvania Right-to-Know:
Aluminum oxide
Note: Other U.S. State Regulations may exist, check your local sources if available.
Activated Alumina S-2001/ESM-221 Page 7 of 9
Revision Number: 1 June 2008
Canada Canadian Hazardous Products Act: This product is not classified as a controlled product under regulations pursuant to the Federal Hazardous Product Act (e.g. WHMIS). Canadian Environmental Protection Act: All the ingredients of this mixture are notified to CEPA and on the DSL (Domestic Substances List).
European Union (EU) European Inventory of Existing Commercial Chemical Substances: All components of this product are included in EINECS/ELINCS. Council of European Communities Directive on Classification, Packaging and Labeling of Dangerous Substances/Preparation (67/548/EEC & 1999/45/EC, as amended): No Dangerous Goods Label Required. Additional Governmental Inventories Australia – Inventory of Chemical Substances (AICS): All the ingredients of this mixture appear on the AICS. China – All the ingredients of this mixture appear on the China Inventory. Japan – Existing and New Chemical Substances (ENCS): All the ingredients of this mixture appear on the ENCS. Korea – Existing and Evaluated Chemical Substances (ECL): All the ingredients of this mixture appear on the ECL. Philippines – Inventory of Chemicals and Chemical Substances (PICCS): All the ingredients of this mixture appear on the PICCS.
Activated Alumina S-2001/ESM-221 Page 8 of 9
Revision Number: 1 June 2008
16. OTHER INFORMATION HMIS™ - Hazardous Material Identification System: HMIS™ Ratings: 0-minimal hazard, 1-slight hazard, 2-moderate hazard, 3-serious hazard, 4-severe hazard
HEALTH: FLAMMABILITY: REACTIVITY:
1 0 1
For additional information concerning this product, contact the following: ASM Catalysts, LLC 8550 United Plaza Blvd., Suite 702 Baton Rouge, LA 70809-0200 USA Tel: +1-225-752-4276, Fax: +1-225-922-4550
Euro Support B.V. Kortegracht 26 3811 KH Amersfoort The Netherlands Tel: +31-33-465-0465, Fax: +31-33-465-0721
The data and recommendations presented in this data sheet concerning the use of our product and the materials contained therein are believed to be accurate and are based on information which is considered reliable as of the date hereof. However, the customer should determine the suitability of such materials for his purpose before adopting them on a commercial scale. Since the use of our products by others is beyond our control, no guarantee, express or implied, is made and no responsibility assumed for the use of this material or the results to be obtained therefrom. Information on this form is furnished for the purpose of compliance with Government Health and Safety Regulations and shall not be used for any other purposes. Moreover, the recommendations contained in this data sheet are not to be construed as a license to operate under or a recommendation to infringe, any existing patents, nor should they be confused with state, municipal or insurance requirements, or with national safety codes.
Activated Alumina S-2001/ESM-221 Page 9 of 9
Revision Number: 1 June 2008
Material Safety Data Sheet (MSDS) MSDS Number: 6179-12
01/26/2010
EMERGENCY ASSISTANCE
CHEMTREC (US): 1-800-424-9300
CANUTEC (Canada): 613-996-6666
CHEMTREC (International): +1-703-527-3887 (Call Collect)
SECTION I. PRODUCT:
MATERIAL IDENTIFICATION
CRITERION 234 CATALYST
COMMON NAME: PRODUCT USE:
Metal Oxide Hydrotreating Catalyst
SECTION 2. COMPOSITION/INFORMATION ON INGREDIENTS COMPONENTS OF THE MATERIAL Component Chemical CAS Formula Al2O3 1344-28-1 Aluminum oxide CoO 1307-96-6 Cobalt oxide MoO3 Molybdenum oxide 1313-27-5
SECTION 3.
Concentration 74 - 98 % 1-5% 10 - 19 %
HAZARDS IDENTIFICATION
EMERGENCY OVERVIEW Physical Appearance: Blue Extrudates or Spheres. Odorless Human Health Hazards: Irritating to eyes and respiratory system. May cause allergic reaction (rash) with skin contact and asthma-like allergic reaction by inhalation in sensitive individuals. Physical Hazards: No specific hazards. Environmental Hazards: Toxic to aquatic organisms, may cause long-term adverse effects in the aquatic environment.
Page 1 of 8
CRITERION 234 CATALYST
MSDS Number:
6179
Potential Health Effects Eye: Mildly irritating to eyes. Skin: Mildly irritating to the skin. May cause contact dermatitis (allergic skin rash) in cobalt sensitive individuals.
Inhalation: Dusts may be irritating to the nose, throat and respiratory tract. May cause sensitization by inhalation due to presence of a cobalt compound. Existing respiratory diseases may be aggravated by exposure to this material. Ingestion: Low-level cobalt ingestion is known to cause effects on the heart after a short-term exposure. The symptoms of heart damage may be a swelling of the feet (edema) and shortness of breath on exertion or when lying flat on the back (supine). Other Health Effects: Molybdenum compounds have a low order of toxicity, may be irritating and may cause anemia. SECTION 4. FIRST AID MEASURES Eye Contact: Flush eyes with water. If persistent irritation occurs, get medical attention. Skin Contact: Wash skin with water and, if available, soap. If persistent irritation occurs, get medical attention. Inhalation: Move to fresh air. If rapid recovery does not occur, get medical attention. Ingestion: Do not induce vomiting. Give nothing by mouth. Get medical attention immediately. Note to Physicians: Treat symptomatically. If skin sensitization has developed and a causal relationship has been confirmed, further exposure should not be allowed. SECTION 5. FIRE FIGHTING MEASURES Extinguishing Media: Material will not burn; use an extinguishing medium appropriate for the surrounding fire.
SECTION 6. ACCIDENTAL RELEASE MEASURES Precautionary Measures: Do not breathe dust. Avoid contact with skin and eyes. Avoid dust generation. Wear suitable protective clothing and gloves. Wear a NIOSH approved respirator if there is a possibility of exposures above the established occupational exposure limits. (See Section 8 for exposure limits.) Spill Management: Prevent contamination of soil and water. Do not wash spills into sewers or other public water systems. Prevent further leakage or spillage and prevent from entering drains.
Page 2 of 8
CRITERION 234 CATALYST
MSDS Number:
6179
Spill Disposal: Shovel up and place in a labeled, sealable container for subsequent safe disposal. Environmental Compliance: Refer to latest state or local regulations to determine if there are disposal or reporting requirements.
SECTION 7. HANDLING AND STORAGE Handling Recommendations: Avoid contact with skin and eyes. Avoid dust generation. Do not breathe dust. Do not eat, smoke or drink in areas where catalyst is present. Use only in well ventilated areas. Use local exhaust extraction. Take precautionary measures against static discharge. Ground all equipment. Storage Recommendations: Keep container tightly closed and dry. Reseal plastic liner.
SECTION 8. EXPOSURE CONTROLS/PERSONAL PROTECTION Engineering Controls: Use only in well ventilated areas. Use local exhaust extraction. Hygiene Measures: Avoid contact with material. Wash hands thoroughly after handling. Do not reuse clothing if contaminated until thoroughly decontaminated. Respiratory Protection: Use either an atmosphere-supplying respirator or an air-purifying respirator for particulates. Eye Protection: Wear safety goggles or glasses to prevent eye contact. Hand Protection: Wear neoprene, nitrile, PVC or latex gloves to prevent contact. Body Protection: When there is a possibility of exposure wear a one piece coated overall with integral hood, safety boots, chemical-resistant without lace holes. Chemical Name
Authority
Limits
Special Notations
Aluminum oxide Aluminum oxide Aluminum oxide Cobalt oxide
OSHA OSHA ACGIH OSHA
PEL 15 mg/m³ PEL 5 mg/m³ TWA 10 mg/m³ PEL 0.1 mg/m³
Cobalt oxide Cobalt oxide Cobalt oxide Molybdenum oxide
ACGIH ACGIH ACGIH OSHA
TWA 0.02 mg/m³ BEI 15 µg/m³ BEI 20 µg/m³ PEL 15 mg/m³
total dust respirable dust total dust metal dust & fumes; as Co; Cancer: 3 as Co as creatinine BEI as Mo; total dust
Page 3 of 8
CRITERION 234 CATALYST
Molybdenum oxide Molybdenum oxide
SECTION 9.
OSHA ACGIH
PEL 5 mg/m³ TWA 10 mg/m³
MSDS Number:
6179
as Mo; respirable dust as Mo; total dust
PHYSICAL AND CHEMICAL PROPERTIES Product
Physical & Chemical Properties Appearance and Odor: Solubility in water: Bulk density (solids): Melting point:
Characteristics Blue Extrudates or Spheres. Odorless <5% 0.48 g/cc ~3700
SECTION 10. STABILITY AND REACTIVITY Stability: Stable. Hygroscopic. Materials To Avoid: Strong acids, strong bases, strong oxidizing agents.
SECTION 11. TOXICOLOGICAL INFORMATION The hazard determination and the information presented below is based on available data derived from testing for the material, hazardous components of this material and/or a testing on a substantially similar material(s). The material tested is indicated in the data.
Route Dermal
Acute Lethality Material Tested Molybdenum oxide
Route Dermal Inhalation
Sensitization Material Tested Cobalt oxide Cobalt oxide
LD/LC50 >2000 mg/kg
Description Sensitizer Sensitizer
Species Rat
Species Human Human
Other Health Effects: Cobalt was used as a defoaming agent in beer at 1 ppm. After a few weeks of exposure beer drinkers were found to have myocardial effects. Deaths were reported. Medical evaluations found myocardial infarction. In a lifetime feeding study with cobalt in hamsters, no statistically significant increases in tumors were seen. Carcinogenicity: Cobalt oxide is classified by: IARC as a possible human carcinogen (Group 2B)
Page 4 of 8
CRITERION 234 CATALYST
MSDS Number:
6179
SECTION 12. ECOLOGICAL INFORMATION Ecotoxicological data have not been determined specifically for this material. The information given below is based on knowledge of the components and the ecotoxicology of similar products. Toxicity to Aquatic Organisms: Toxic to aquatic organisms, may cause long-term adverse effects in the aquatic environment. Persistence & Bioaccumulation: Not inherently biodegradable. Mobility: Sinks in water. If product enters soil, one or more constituents will be mobile and may contaminate groundwater. Sewage Treatment: Not toxic at the limit of water solubility.
SECTION 13. DISPOSAL CONSIDERATIONS Product disposal: Recover or recycle, if possible. Otherwise: Send to an approved contractor for regeneration or metal recovery or dispose with a licensed disposal contractor. Waste Disposal: If product is unused, see above. If used, evaluate the toxicity and physical properties of the material you have generated and dispose of the material in accordance with local, state and federal regulations. Container Disposal: Empty containers may contain residues. Ensure container is properly cleaned. Remove all packaging for recovery or waste disposal. DO NOT USE CONTAINER FOR OTHER PURPOSES. Regulatory Controls: Comply with all federal, state and local laws regulating the handling and disposal of wastes. SECTION 14. TRANSPORTATION INFORMATION Transport Statement: Not dangerous for conveyance under USA DOT, Canadian TDG, and IATA/ICAO codes. Consult local laws to determine transportation regulations. U. S. A. - DEPARTMENT OF TRANSPORTATION (DOT) Not regulated by DOT (USA). CANADA - TRANSPORTATION OF DANGEROUS GOODS (TDG) Not dangerous for conveyance under Canadian TDG. Maritime transport (IMO) UN No. Proper Shipping Name Class Packing Group Hazard symbol
UN 3077 ENVIRONMENTALLY HAZARDOUS SUBSTANCE, SOLID, N.O.S. ( Cobalt compounds ) 9 III , MARINE POLLUTANT MISCELLANEOUS DANGEROUS SUBSTANCES AND ARTICLES ENVIRONMENT
Page 5 of 8
CRITERION 234 CATALYST
MSDS Number:
Air transport ICAO/IATA Not dangerous for conveyance under IATA/ICAO codes. SECTION 15.
REGULATORY INFORMATION
National Authority EINECS/ELINCS TSCA MITI DSL/NDSL TCCL AICS PICCS IECS
National Inventories Country EC USA Japan Canada Korea Australia Philippines China
Status All ingredients listed. All ingredients listed. All ingredients listed. All ingredients listed. All ingredients listed. All ingredients listed. All ingredients listed. All ingredients listed.
PRODUCT SAFETY CLASSIFICATIONS Canada WHMIS Canadian - Workplace Hazardous Materials Information System (WHMIS) Class D - Toxic and Infectious Materials Division 2 - Materials Causing other Toxic Effects Subdivision A - Very Toxic Materials
California Proposition 65 Name on List Cobalt oxide
Classification Carcinogen
Massachusetts Aluminum oxide
Right-To-Know Substances List
Pennsylvania Aluminum oxide Molybdenum oxide
Right-To-Know Hazardous Substance PA Environmental Hazard E (1 % threshold)
Page 6 of 8
6179
CRITERION 234 CATALYST
MSDS Number:
6179
European Community CONTAINS COBALT OXIDE / MOLYBDENUM OXIDE Xn: Harmful N: Dangerous to the Environment Harmful Dangerous to the Environment R48/20/22: Harmful: danger of serious damage to health by prolonged exposure through inhalation and if swallowed. R42/43: May cause sensitization by inhalation and skin contact. R36/37: Irritating to eyes and respiratory system. R51/53: Toxic to aquatic organisms, may cause long-term adverse effects in the aquatic environment. S22: Do not breathe dust. S24: Avoid contact with skin. S37/39: Wear suitable gloves and eye/face protection. S61: Avoid release to the environment. Refer to special instructions/Safety data sheets.
Label Name Hazard Symbols Classification Risk Phrases
Safety Phrases
NATIONAL ENVIRONMENTAL AND SAFETY REGULATIONS
Superfund Amendments and Reauthorization Act (SARA) SARA 311/312 Classification: Immediate (acute) health hazard Delayed health hazard SARA 313 Chemicals: Cobalt compounds Molybdenum oxide SECTION 16.
OTHER INFORMATION
COMPANY NAME:
Criterion Catalysts & Technologies L.P. 16825 Northchase Drive, 2 Greenspoint Plaza Houston, Tx. 77060 (USA) +1 281 874 2600 +1 281 874 2641 (FAX)
MSDS Prepared By:
CRI/Criterion, Inc. 16825 Northchase Drive, Suite #1110
Houston, TX 77060 (USA) +1 281-874-2600 (USA CST) [email protected] Uses and restrictions: Use as a raw material/intermediate for catalyst manufacture, as a catalyst for refinery processing or for petrochemicals manufacture. MSDS Distribution: The information in this document should be made available to all who may handle the product.
Page 7 of 8
CRITERION 234 CATALYST
MSDS Number:
6179
Amendment Notation: Amendments from the previous version of the MSDS are indicated by two vertical bars in the left margin and the section is highlighted. Disclaimer: This information is based on our current knowledge and is intended to describe the product for the purposes of health, safety and environmental requirements only. It should not, therefore, be construed as guaranteeing any specific property of the product.
Issue Date: 01/25/2010 US/Canada - (English)
Page 8 of 8
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
Table of Contents 3. GENERAL .................................................................................................................... 3-1 3.1 ORGANIZATION ................................................................................................... 3-1 3.2 GENERAL PRECOMMISSIONING PROCEDURES ............................................. 3-2 3.2.1 Mechanical ..................................................................................................... 3-2 3.2.2 Electrical ......................................................................................................... 3-3 3.2.3 Instrumentation ............................................................................................... 3-5 3.3 DESIGN BASIS ..................................................................................................... 3-7 3.3.1 Plant Capacity ................................................................................................ 3-7 3.3.2 Sulfur Block Feed Streams ............................................................................. 3-7 3.3.3 Effluent Stream Conditions ........................................................................... 3-12 3.3.4 Other Design Requirements ......................................................................... 3-13 3.3.5 Utility Information .......................................................................................... 3-14 3.3.6 Plant Site Conditions .................................................................................... 3-16
Issued 30 August 2011
General
Page 3-i
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
3. GENERAL 3.1
Organization This manual discusses the startup and operation of the new Sulfur Block, consisting of an Amine Treating Unit, an Amine Regeneration Unit, a Sour Water Stripping Unit, two Sulfur Recovery Units, a common Tailgas Thermal Oxidation Unit, Tailgas Cleanup Unit, and Sulfur Degassing Unit, on a systems basis. The systems are discussed individually, but are also grouped together into two main categories. The categories and systems, in order of presentation, are: A.
B.
UTILITY SYSTEMS 1.
Power Distribution
2.
Plant Control Systems
3.
Utility Systems
PROCESS SYSTEMS 1.
Amine Treating / Amine Regeneration
2.
Sour Water Stripping
3.
Sulfur Recovery
4.
Tailgas Thermal Oxidation
5.
Tailgas Cleanup
6.
Sulfur Degassing and Transfer
7.
Solvent Storage and Drain
The systems are presented in the sequence required for a normal startup. That is, electric power is usually the first system commissioned and the Sulfur Degassing system is usually the last.
Issued 30 August 2011
General
Page 3-1
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
3.2
General Precommissioning Procedures Prior to placing each of the Amine Treating, Sour Water Stripping, Sulfur Recovery, Tailgas Thermal Oxidation, Tailgas Cleanup, Sulfur Degassing, and associated systems in operation, check-out of the various systems should be made in as much detail as practical. This will help eliminate problems during startup and familiarize personnel with the plant equipment.
3.2.1
Mechanical A complete check of all plant construction should be made to assure it is in accordance with the Piping & Instrument Diagrams and equipment manufacturer's recommendations. Any discrepancies or defects should be corrected before attempting to put the plant in operation. Each piece of equipment should be checked against the vendor's recommendations and guidelines. Some of the steps that should be taken to ensure the plant is mechanically ready for startup include:
Issued 30 August 2011
A.
Make an internal check of vessels for correct installation of mist pads, support grids, trays, vortex breakers, etc.
B.
Check to ensure suction strainers are installed in all pump suction lines before the pumps are operated for any reason.
C.
Perform all necessary pressure tests. After tests, remove the test blinds, giving special attention to those below relief valves.
D.
Check the nameplate on each relief valve to ensure it has been installed in the proper location.
E.
Clear the plant area involved in startup of construction equipment and debris that could cause fire or injuries.
F.
Check for proper rotation of all motors.
G.
Check all motors and rotating equipment to ensure proper lubrication and that belts are free and properly aligned.
H.
Check pumps for packing where required (follow manufacturer's instructions).
I.
Check filters to ensure they contain properly installed filter elements or charcoal media and that adequate spare elements are on hand.
General
Page 3-2
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK J.
Prior to commencement of startup, the following items should be on hand: (1)
Spare parts
(2)
Lubricants, greases, etc.
(3)
Chemicals, or provisions to provide chemicals
(4)
Spare filter elements
(5)
Any special tools required
(6)
Fire extinguishers
(7)
Safety equipment
(8)
Oxygen analyzer
(9)
Laboratory test equipment
(10) Pertinent test procedures
3.2.2
Electrical The purpose of commissioning electrical components and control systems prior to the startup of a plant is to ensure correct performance per specifications under simulated operating conditions.
WARNING
POWER SHOULD NOT BE APPLIED TO ANY ELECTRICAL DEVICE, CONTROL PANEL, CONTROL SYSTEM, OR MOTOR IN THE FACILITY UNTIL SUCH TIME THAT ALL POWER AND CONTROL WIRING FOR THE FACILITY HAS BEEN TERMINATED AND PROPERLY MADE-UP ON EACH CONDUCTOR END. Electrical power circuits must be energized in order to make an electrical check-out prior to startup. Some of the following procedures may be accomplished during construction; however, before the plant is put in operation the following should be completed:
Issued 30 August 2011
General
Page 3-3
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
Issued 30 August 2011
A.
Test each circuit phase-to-ground.
with
B.
Test the motor feeder with the motor out of the circuit. After motors are connected, make phase-to-ground tests on the motor circuit.
C.
Test the control circuit with the push-buttons and over-current devices connected.
D.
Test the feeders to the panel-boards with the branch circuits open.
E.
Test the power feeder with switches and circuit breakers in place.
F.
Megger the power and control circuits of the switchgear and motor control centers.
G.
Check the control switches, alarm and shutdown devices, indicating lights, and meters for proper operation.
H.
Install thermal overload heaters where required after checking them against the manufacturer's heat tables and motor nameplate data to ensure the heaters are of the proper size and rating. Check operation of time-delay under-voltage devices for proper timing, proper restart, and dropout action.
I.
Megger motor windings and transformer windings for ground. Examine them for moisture accumulation. If evidence of moisture accumulation is found, the equipment must be dried before being placed in operation.
J.
Check circuit breakers, motor starters, switches, relays, and other equipment for loose connections (both mechanical and electrical) and to see that contacts and working parts are correctly aligned and free from dust and foreign material.
K.
Check motors for proper rotation, lubrication, and alignment.
L.
For circuit breakers with adjustable trips, check the thermal rating against the value shown on the drawings and adjust the magnetic setting to the "LO" position. On magnetic-only (instantaneous trip) breakers in combination starters, the instantaneous setting should be adjusted so that the setting is just above the motor in-rush current. Lower the setting to the point where the contacts open when the motor is started, then raise the setting in small increments to the point where the breaker allows the motor to start.
General
a
megger,
phase-to-phase
and
Page 3-4
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
3.2.3
M.
Ensure that all individual motor starter and feeder breakers are in the "OFF" position.
N.
Provide power to the MCC by engaging the main feeder breaker.
O.
Turn the MCC feeder breakers to the "ON" positions, applying power to all individual circuit breakers, contactors, and motor switches.
P.
In order to initially energize any motor, pump, or fan, the shutdown control system should first be energized and the emergency shutdown system reset.
Instrumentation The purpose of commissioning instruments prior to the startup of the facility is to ensure correct performance per specifications under simulated operating conditions. Handling of instruments after calibration should be kept to a minimum. The instruments have been ordered pre-calibrated and set. It should be necessary only to verify the factory calibration and zero of the instruments. In the event that an instrument requires re-calibration or major mechanical adjustments, the manufacturer's recommendations and guidelines should be adhered to, and will be considered the applicable standard. All instruments, components, and accessory devices (including charts, scales, dials, gauges, switches, etc.) should be checked against their specification sheets for agreement. Specific steps that should be taken to ensure the plant pneumatic instrumentation system is ready for startup include:
Issued 30 August 2011
A.
The instrument air system must be put into operation in order to check-out the instrument loops. The individual block valves for each air user should be closed as the air system is pressurized. Once operating pressure is reached, dirt and pipe scale should be blown from the headers. The individual instrument lines should then be disconnected at the instruments and any debris blown from the entire tubing run.
B.
All air supply regulators should be adjusted to the recommended settings.
C.
Once the instrument air system is pressurized, the piping and tubing should be checked for leaks.
General
Page 3-5
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
Issued 30 August 2011
D.
All instrument loops should be checked to ensure the instruments and control devices are properly interconnected. The controllers should be set to the proper control action with the proper control modes and tuning characteristics.
E.
"Stroke" the control valves to ensure the valves move in the proper direction.
F.
Check orifice plates for proper bore and direction of installation.
G.
Level switches and transmitters should be put in service and checked for proper actuation. Calibration of level devices may be completed after liquid levels are established.
H.
Check the tag numbers on the steam traps to confirm that each trap has been installed in the proper location.
I.
In plants controlled by a distributed control system (DCS), confirm that the range stored in the DCS for each field instrument matches the actual range of the instrument. This is particularly important for flow meters used in ratio control loops, as an incorrect range may prevent the control loop from functioning properly. It is also important on flow loops to confirm that either the transmitter or the DCS (and not both) is extracting the square root of the signal.
General
Page 3-6
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
3.3
Design Basis The information used to design the Sulfur Block is given in this section. Unless stated otherwise, the design conditions presented below are assumed to be available at the battery limits for the new units.
3.3.1
Plant Capacity The feedstock basis for the Sulfur Block is a nominal sulfur production of 35 MT/D. In order to provide a design margin for the Sulfur Recovery Units, each unit is designed for 75% of the normal feed rates, which results in a nominal sulfur production of 52 MT/D.
3.3.2
Sulfur Block Feed Streams
3.3.2.1
Amine Treating Unit Feed Gas (Max Contaminate Case) Composition, mol fraction H2 H2S NH3 Methane Ethane Propane i-Butane n-Butane i-Pentane n-Pentane nC6 H2O
0.008757
Naphtha + Total, kgmol/hr Total, kg/hr
463.85 9902 38 6
Temp, °C Press, kg/cm2(g)
Issued 30 August 2011
Combined Sour Offgas 0.583538 0.133806 0.000146 0.023661 0.018913 0.016896 0.008563 0.115412 0.057487 0.030181 0.00264
General
Page 3-7
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 3.3.2.2
Rich Amine to Amine Regeneration Unit Composition, kmol/hr H2O MDEA H2S NH3 CO2 H2 Methane Ethane Propane i-Butane n-Butane Heptane C1/C2 RSH Total Total, kg/hr
Rich MDEA from DHT RGS 752.79 61.32 14.31 0.00088 0.51 0.01 0.004 0.002 0.0004 0.0004 0.0006 828.95 21358
0.04 1130.75 29231
63 4.5
41 4.5
Temp, °C Press, kg/cm2(g)
Issued 30 August 2011
Rich MDEA from LPG Absorber 1027.14
General
83.56 11.49 8.24 0.04 0.09 0.04 0.12
Page 3-8
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 3.3.2.1
Sour Water to SWS (Max Contaminant Case) Sour Water from NHT (1)
Sour Water from KHT
Sour Water from DHT
Sour Water from CFU
Sour Water from UOP Guard Bed
H2 NH3 H2S
--0.03 0.53
0.23 0.06 0.58
0.16 0.22 0.50
--0.02 0.02
--0.0005 0.0010
H2O
834.34
425.94
320.09
447.70
0.7986
Total Total - kg/hr
834.90 15050
426.81 7695
320.97 5788
447.75 8067
0.8000 14
52
55
54
60
38
3.0
3.0
3.0
3.0
3.0
Composition kgmol/hr
Temp, °C Press, kg/cm2(g) Note
Issued 30 August 2011
(1) The maximum NHT sour water rate is 19585 kg/h containing 35 wt ppm H2S and 18 wt ppm NH3 when running 100% NWS Narrow feed.
General
Page 3-9
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 3.3.2.2
Fuel Gas Streams Fuel gas for the Sulfur Block is supplied from the treated fuel gas header. The treated fuel gas is used only for the fuel to the Thermal Oxidizer Burner. Vaporized C4 LPG is supplied to the Acid Gas Burner, Acid Gas Burner Pilot, and the Thermal Oxidizer Burner Pilot. Composition, mole % Hydrogen
67.353
H2S
0.010
Water Vapor
1.067
Methane
2.729
Ethane
2.180
Propane
1.948
i-Butane
0.988
n-Butane
13.306
i-Pentane
6.633
n-Pentane
3.481
C6 +
0.305
Totals
100.000
Temperature, °C
38
Pressure, kg/cm2(g) (min)
3.5 10,425
LHV, kcal/kg
Issued 30 August 2011
Treated Fuel Gas
General
Page 3-10
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 3.3.2.3
Hydrogen Stream (Reducing Gas) Composition, mole % Hydrogen
99.9
Nitrogen
--20 ppm
CO & CO2 Methane
0.1
Ethane
---
Propane
---
i-Butane
---
n-Butane
---
Totals
Issued 30 August 2011
PSA Hydrogen
100.0
Temperature, °C
40
Pressure, kg/cm2(g) (min)
25
General
Page 3-11
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 3.3.3
Effluent Stream Conditions
3.3.3.1
Treated Fuel Gas from ATU Temperature °C
3.3.3.1
2
normal / max
38 / 40
kg/cm (g)
min / max
3.5 / 4.2
H2S
ppmv
max (dry)
100
Stream:
Treated water
max
60
Treated Water from SWS °C 2
Pressure
kg/cm (g)
min
5.0
H2S
ppmw
max
20
NH3
ppmw
max
20
Incinerated Effluent from TTO Min. 232
Temperature
°C
Pressure SO2
kg/cm2 (g)
H2S (1)
CO NOX
Note
Issued 30 August 2011
Treated Gas
Pressure
Temperature
3.3.3.1
Stream:
(1)
Norm. 288
Max. 400
atm.
ppmv (dry, 0% oxygen)
200
ppmv ppmv ppmw
10 50 65
For oxidation of H2S to SO2, the normal operating temperature for the Tailgas Thermal Oxidizer (TTO) is about 650°C. If CO emissions must be limited and, therefore, the CO must be oxidized to CO2, then the normal operating temperature for the TTO is about 816°C.
General
Page 3-12
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 3.3.3.1
Molten Sulfur Temperature
3.3.4
°C
Min.
Norm.
119
138
2
Pressure Purity H2S
kg/cm (g) % (dry basis) ppmw
Carbon Color
%
Max.
atm. 99.9 10 0.2 “Texas Bright”
Other Design Requirements
3.3.4.1
The Lean Amine from the Amine Regeneration Unit is a 35 wt% MDEA solution with a residual loading of 0.01 mole acid gas / mole MDEA.
3.3.4.2
The Rich Amine from the DHT, LPG Absorber and Amine Treating Unit will go to the Amine Regeneration Unit for regeneration. The maximum Rich Amine loading will be 0.40 mole acid gas / mole MDEA.
3.3.4.3
Liquid sulfur from the SRU is to be degassed to convert H2SX species to H2S and reduce the concentration of H2S to less than 10 PPMW for safe handling.
3.3.4.4
In general, the Sulfur Block is to be designed for a 3-4 year run length between turnarounds. Mechanical turnaround duration is usually 3-7 days for each unit.
3.3.4.5
All units are to be designed individually for a 98% or better on-stream factor.
3.3.4.6
Critical equipment is to be spared, to permit on-line maintenance.
Issued 30 August 2011
General
Page 3-13
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 3.3.5
Utility Information
3.3.5.1
Electricity
Service
Voltage
Phase
Cycles
Motors above 132 kW
6,600 V
3
60
Motors 0.2 kW up to and including 132 kW
440 V
3
60
Fractional kW motors up to 0.2 kW
440 V
3
60
3.3.5.2
Steam Operating Temp. °C
Operating Pressure: kg/cm²(g)
Mechanical Design
Min
Norm
Max
Min
Norm
Max
Press: kg/cm²(g)
HP Steam MP Steam
44 16
45 17
46 17.5
380 275
400 280
420 300
50 20
427 350
IP Steam
13.7
14.4
15.1
202
204
206
16.7
227
LP Steam
3
3.5
4
190
195
210
5.5
300
3.3.5.3
Condensate Condensate Destination or Designation
Grade Level Battery Limit Pressure: kg/cm²(g)
HP Steam MP Steam
HP Condensate MP Condensate
19 6
IP Steam
LP Condensate
1.5
LP Steam
LP Condensate
1.5
3.3.5.4
Boiler Feed Water Min.
Normal
Max.
Design
BFW Temperature, °C
132
132
132
160
BFW Pressure, kg/cm2(g)
57
57
58
63
Dissolved Solids, PPMW (avg)
<5
Conductivity, µS/cm (avg)
<20
Issued 30 August 2011
Temp: °C
General
Page 3-14
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 3.3.5.5
Cooling Water Normal 2
Min.
Design
2
2
kg/cm (g)
°C
kg/cm (g)
°C
kg/cm (g)
°C
Supply
5(1)
--
--
32
8
60
Return
2(1)
--
--
42
8
60
TSS ppmw
20 max
Chlorides ppmw
1200
Ammonia ppmw
nil
Note
3.3.5.6
(1) These conditions are not necessarily the conditions at the inlet or outlet connections of the equipment. Instrument Air and Plant Air
Plant Air, kg/cm2(g) 2
Instrument Air, kg/cm (g)
Min.
Normal
Max.
Design
5.5
5.5
6
10
4
7
8
10
Plant Air Dewpoint °C
---
Instrument Air Dewpoint °C
-40
Issued 30 August 2011
General
Page 3-15
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 3.3.5.7
Gaseous Nitrogen
Pressure, kg/cm2(g)
Min.
Normal
Max.
Design
4
6
8
10
Composition, mole % Nitrogen
99.5
Oxygen
20 ppmv (max)
CO
20 ppmv (max)
CO2
20 ppmv (max)
Other C Compounds
5 ppmv (max)
Chlorine
1 ppmv (max)
H2O
5 ppmv (max)
Hydrogen
20 ppmv (max)
Noble Gases
Remainder
Total
3.3.6
100.0
Plant Site Conditions
3.3.6.1
Barometric Pressure:
760 mm Hg (average)
3.3.6.2
Air Temperature:
37°C (dry bulb) maximum summer design 30°C (dry bulb) for air blower design -10°C (dry bulb) minimum winter design -14.3°C (dry bulb) winterizing
3.3.6.3
Issued 30 August 2011
5.6 m above mean sea level
Site Elevation:
General
Page 3-16
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
Table of Contents 4. POWER DISTRIBUTION .............................................................................................. 4-1 4.1 PURPOSE OF SYSTEM ....................................................................................... 4-1 4.2 SAFETY ................................................................................................................. 4-1 4.2.1 General ........................................................................................................... 4-1 4.2.2 Hazardous (Classified) Areas ......................................................................... 4-1 4.3 EQUIPMENT DESCRIPTION ................................................................................ 4-2 4.3.1 Motors and Motor Controls ............................................................................. 4-2
Issued 30 August 2011
Power Distribution
Page 4-i
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
4. POWER DISTRIBUTION 4.1
Purpose of System This utility system supplies electrical power to all users in the Amine Treating, Amine Regeneration, Sour Water Stripping, Sulfur Recovery, Tailgas Cleanup, Tailgas Thermal Oxidation, and Sulfur Degassing units including motors, instruments, controls, lights, receptacles, and heat tracing.
4.2
Safety
4.2.1
General Only authorized and qualified personnel should maintain and repair electrical equipment. All operator controls and adjustments are accessible without opening electrical equipment enclosures. Maintain extreme care when operating electrical equipment and machinery driven by electrical motors. Equipment may start without warning. Observe company safety rules and permit-to-work system. If you suspect a person has been electrocuted, DO NOT approach the victim until the source of power has been turned off or it is obvious the victim is no longer in contact with the source. If possible, drag victim clear of any metal or potential electrical sources using victim's clothing or by wearing insulating gloves. If the victim is still in contact with the electrical source and skin contact is made, you may also be electrocuted.
4.2.2
Hazardous (Classified) Areas Most of the process areas in the Amine Treating, Amine Regeneration, Sour Water Stripping, Sulfur Recovery, Tailgas Cleanup, Tailgas Thermal Oxidation, and Sulfur Degassing units have been classified as Zone 2, Gas Group IIA/IIB for electrical installation. The only exceptions to this are any below-grade vaults which have been classified as Zone 1, Gas Group IIA/IIB. Locations are classified depending on the properties of the flammable vapors, liquids, or gases which may be present and the likelihood that a flammable or combustible concentration or quantity is present. The electrical equipment and installation in classified areas conforms to the
Issued 30 August 2011
Power Distribution
Page 4-1
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK International Electrotechnical Commission (IEC) Standards. Special precautions are required when operating electrical equipment in classified areas. The equipment should be approved for the area classification or a "hot-work" permit system should be followed during the period a non-approved piece of equipment is used in the classified area.
4.3
Equipment Description
4.3.1
Motors and Motor Controls A.
In general, the electric motors are TEFC, 444 VAC, 3 Ø, 60 Hz with the exception of: (1)
B.
Issued 30 August 2011
The motors on the Process Air Blower, A2-GB1530A/B, are TEFC, 6600 VAC, 3 Ø, 60 Hz.
The motor control circuits for the Process Air Blower (A2-GB1530A/B), Thermal Oxidizer Air Blower (A2-GB1570A/B), and TGCU Start-Up Blower (A2-GB1560) include provisions that allow the blowers to "ride-through" brief power interruptions.
Power Distribution
Page 4-2
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
Table of Contents 5. PLANT CONTROL SYSTEMS ..................................................................................... 5-1 5.1 5.2 5.3 5.4
DISTRIBUTED CONTROL SYSTEM .................................................................... 5-1 PROGRAMMABLE LOGIC CONTROL SYSTEM ................................................. 5-2 EMERGENCY SHUTDOWN SYSTEMS ............................................................... 5-3 LOCAL CONTROL PANELS ................................................................................. 5-3
Issued 30 August 2011
Plant Control Systems
Page 5-i
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
5. PLANT CONTROL SYSTEMS This section of the manual describes the various control systems associated with the new Amine Treating, Amine Regeneration, Sour Water Stripping, Sulfur Recovery, Tailgas Cleanup, Tailgas Thermal Oxidation, and Sulfur Degassing units. Most of the process control functions are performed by a Distributed Control System (DCS). The DCS, with its operator interface screens and keyboards, allows the control room operator to monitor and control nearly all of the systems within the new units. The safety system interlocks and sequential control functions are performed by a programmable logic controller (PLC). A PLC is a solid-state microprocessor that performs the functions of a traditional relay logic system. The PLC for the new units will communicate with the DCS to allow the operator to monitor the PLC using the operator interface screens of the DCS.
5.1
Distributed Control System The Distributed Control System (DCS) provides control, monitoring, recording, alarming, and all other functions required for dependable and effective process control of the facility. It is a microprocessor based, fully engineered system of hardware and software products integrated into an industrially-proven DCS design capable of both functional and geographic distribution. A communication system links these locations to a centralized operating center with video displays configured as operator workstations. The system has been designed so that control and monitoring functions are distributed on a modular basis to minimize control and data information loss in the event of a failure anywhere within the system. Control functionality does not depend on a single centrally-based device or communication system to assure that on a single failure the system will remain operative to allow continued control and monitoring of the remainder of the process. To achieve this, redundancy has been included for controllers, power supplies, communication modules and cables, and operator workstations.
Issued 30 August 2011
Plant Control Systems
Page 5-1
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
5.2
Programmable Logic Control System A Programmable Logic Control (PLC) system is used for the new Amine Treating, Amine Regeneration, Sour Water Stripping, Sulfur Recovery, Tailgas Cleanup, Tailgas Thermal Oxidation, and Sulfur Degassing units to perform the functions of traditional relay logic systems. The logic control systems for each unit are all contained in one or more PLCs. Each logic control system will be discussed in more detail in later sections of the manual: a.
Amine Treating Unit Emergency Shutdown System (see Section 7.4.2).
b.
Sour Water Stripper Unit Interlocks (see Section 8.4).
c.
Sulfur Recovery Unit Emergency Shutdown System (SRU ESD) and Burner Management System (see Sections 9.5.2 and 9.5.8).
d.
Sulfur Degassing Unit Startup Interlock and Emergency Shutdown System (SDU ESD) (see Sections 10.5.3 and 10.5.7).
e.
Sulfur Loading Emergency Shutdown System (see Section 10.5.8).
f.
Tailgas Cleanup Unit Emergency Shutdown System (TGCU ESD) (see Section 11.5.5).
g.
Tailgas Thermal Oxidation Emergency Shutdown System (TTO ESD) and Burner Management System (see Sections 12.5.1 and 12.5.5).
The PLC hardware and programs are fail-safe by design. Loss of power to the PLC will de-energize all its outputs and send devices (control valves, etc.) to their "fail" position. The restoration of power to the PLC will restart the PLC, but program interlocks will "lock-out" control actions until the respective ESD systems are reset. Similarly, the PLC logic has been designed such that open circuits in field wiring or open field contacts will de-energize their respective outputs and render equipment and process to a "safe" status. The PLC system is connected by both "hard-wired" cables and software "links" that allow it to communicate with the DCS. This enables the DCS operator interface to be used by the operators to monitor the status of the PLC and its safety and sequential control systems.
Issued 30 August 2011
Plant Control Systems
Page 5-2
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
5.3
Emergency Shutdown Systems The purpose of the Amine Treating Unit Emergency Shutdown (ATU ESD), Sulfur Recovery Unit Emergency Shutdown (SRU ESD), Tailgas Cleanup Unit Emergency Shutdown (TGCU ESD), Tailgas Thermal Oxidation Unit Emergency Shutdown (TTO ESD), and Sulfur Degassing Unit Emergency Shutdown (SDU ESD) systems is to shut down the appropriate equipment and divert the appropriate streams to the flare when serious problems occur. Each of these ESD systems can be initiated either by a system response or by an operator. Refer to the Instrumentation and Control Systems sections of these guidelines for complete discussions of these emergency shutdown systems. These ESD systems are mostly independent of each other, with the exception of the TGCU ESD system, which is activated when both of the SRU ESD systems are activated. Except for this situation, activation of the ESD system in a particular unit will not cause any other ESD systems to be directly activated. Of course, depending on the particular circumstances, the effects that result when a particular ESD system is activated may indirectly cause another ESD system to be activated due to the process upset that occurs.
5.4
Local Control Panels There are three local control panels that are used for startup of each Sulfur Recovery Unit and the Tailgas Thermal Oxidation Unit. The functions of these local panels are described in the Instrumentation and Control Systems sections of these guidelines for the Sulfur Recovery system and the Tailgas Thermal Oxidation system.
Issued 30 August 2011
Plant Control Systems
Page 5-3
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
Table of Contents 6. UTILITY SYSTEMS ...................................................................................................... 6-1 6.1 PURPOSE OF SYSTEM ....................................................................................... 6-1 6.2 SYSTEM DESCRIPTION ...................................................................................... 6-1 6.2.1 Nitrogen Supply .............................................................................................. 6-1 6.2.2 C4 LPG and Treated Fuel Gas Supply .......................................................... 6-2 6.2.3 Hydrogen Supply ............................................................................................ 6-2 6.2.4 Plant Air .......................................................................................................... 6-3 6.2.5 Instrument Air ................................................................................................. 6-3 6.2.6 Sour Water Disposal....................................................................................... 6-3 6.2.7 Steam, Condensate, Boiler Feed Water, and Blowdown ............................... 6-4 6.2.7.1 Purpose of Systems ................................................................................ 6-4 6.2.7.2 Safety ...................................................................................................... 6-4 6.2.7.3 Process Description ................................................................................ 6-5 6.2.7.4 Boiler Feed Water ................................................................................... 6-5 6.2.7.5 HP Steam ................................................................................................ 6-6 6.2.7.6 LP Steam................................................................................................. 6-7 6.2.7.7 Condensate Return ................................................................................. 6-7 6.3 PRECOMMISSIONING, STARTUP, AND SHUTDOWN PROCEDURES............. 6-8
Issued 30 August 2011
Utility Systems
Page 6-i
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
6. UTILITY SYSTEMS 6.1
Purpose of System The utility headers supply the fluids necessary for plant operation and maintenance.
6.2
System Description The Piping and Instrument Diagrams show the utility system tie-ins for this project. Some of the more important or complex systems are discussed in more detail in the sections below.
6.2.1
Nitrogen Supply The SRUs and TGCU have two sections of equipment or piping that are stagnant during certain modes of operation. One of these, the SRU warmup bypass line(s), would cause undesirable effects on sulfur recovery and/or severe corrosion if leakage occurred in the line. The other one, the TGCU Start-Up Blower, could suffer corrosion if exposed to wet process gases when it is not running. The most positive means of preventing these problems is to isolate the section in question and purge it with inert gas (such as nitrogen). If the pressure of the purge gas is higher than the process operating pressure, then any leakage through the isolation valves will be the inert purge gas leaking out rather than process gas leaking in. Nitrogen is used in this manner at each of these locations within the new unit. Nitrogen is also used for several other purposes within the new units: 1) to purge instruments (flame scanners, pyrometers, flow meters, etc.) exposed to process gas containing sulfur vapor or ammonia; 2) to empty out and purge vessels before opening them for maintenance; 3) to prevent a vacuum from forming in several overhead lines; 4) as the motive fluid for the aspirator in the air demand analyzer; and 5) as a cool-down medium for the SRUs and the front-end of the TGCU. A dedicated low pressure header is used for purges permanently connected to low pressure sulfur plant equipment; a high pressure header operating at about 7.0 kg/cm2(g) provides nitrogen for the other users.
Issued 30 August 2011
Utility Systems
Page 6-1
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 6.2.2
C4 LPG and Treated Fuel Gas Supply When the refractory in the Reactor Furnace, A2-BA1530 (A2-BA1540), must be heated in a controlled fashion according to its cure-out schedule, fuel is fired in the Acid Gas Burner, A2-BA1531 (A2-BA1541), on manual control. Variable fuel gas quality could lead to temperature "run-aways" if there is not close operator attention throughout the heating cycle. For this reason, vaporized C4 LPG is used as the fuel gas for the Acid Gas Burner. The heating value of vaporized LPG normally varies much less than the heating value of a typical treated fuel gas stream, so vaporized LPG should be much less likely to cause temperature control problems during this manual operation. The fuel gas to the Thermal Oxidizer Burner, A2-BA1571, is automatically adjusted to maintain the desired temperature in the Thermal Oxidizer, A2-BA1570. In addition, this burner normally operates with considerable excess air, since the oxygen to oxidize the sulfur compounds entering the Thermal Oxidizer comes from the burner combustion products. As a result, the variable nature of treated fuel gas can be tolerated by this burner much more easily than the Acid Gas Burner, so this burner is designed to burn treated fuel gas. The pilot burners for the Acid Gas Burner and the Thermal Oxidizer Burner are not as reliable if variable quality fuel gas is used. For this reason, vaporized LPG is used for both pilots to ensure reliable light-off and good service life. During normal operation, loss of the treated fuel gas supply will cause the Thermal Oxidizer to shut down. However, the SRU should continue to operate. The Thermal Oxidizer shutdown will be due to "flame failure" of the Thermal Oxidizer Burner. Loss of LPG will normally not affect either unit, but it will not be possible to restart either unit should a shutdown occur until the LPG supply is restored.
6.2.3
Hydrogen Supply The TGCU Unit is designed to use an external supply of reducing gas to hydrogenate the sulfur compounds in the SRU tailgas back into H2S, rather than generate its own reducing gas. High-purity hydrogen is imported into the Sulfur Block, let-down to low pressure, and combined with the SRU tailgas upstream of the TGCU Reactor Feed Mixer, A2-ME1560. If the hydrogen supply is interrupted, it is likely that the TGCU Unit will have to be bypassed until the hydrogen supply is restored.
Issued 30 August 2011
Utility Systems
Page 6-2
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 6.2.4
Plant Air The Plant Air system provides compressed air for the utility air stations throughout the plant. It can be used for operating pneumatic tools and other pneumatic equipment such as air movers, spray guns, and sand blasting apparatus. Plant air is also used in the Tailgas Cleanup Unit for catalyst passivation.
6.2.5
Instrument Air Dry instrument air is used to provide the motive force to operate the control valves and shutdown valves in the Sulfur Block. Loss of the air supply for brief periods will probably not cause any operational problems. However, if the instrument air pressure falls below about 4.2 kg/cm2(g), some of the large process gas valves may begin to move. If one of the process gas valves that is in the open flowpath through the SRUs, the TGCU, and the TTO should begin to close, the ESD system for that SRU and/or the TGCU will be activated, resulting in an SRU and/or TGCU shutdown.
6.2.6
Sour Water Disposal Sour water is produced at several points in the SRU and TGCU, such as in the Acid Gas Knock-Out Drums, A2-FA1530 (A2-FA1540), the SWS Gas Knock-Out Drum, A2-FA1531 (A2-FA1541), and the excess water condensed in the TGCU Quench Column, A2-DA1560. Some of this sour water is intermittent in nature, like the knock-out drum liquids, whereas the excess quench water will be a continuous flow. The sour water from the Acid Gas Knock-Out Drum is pumped to the Rich Amine Flash Drum, A2-FA1513, while the remaining sources are sent to the Sour Water Flash Drum, A2-FA1520. Sour water must also be drained from equipment items periodically (pump cases, level instruments, etc.). The Closed Drain Tank, A2-FA1582, has an underground header system to collect these liquids and hold them. As the tank fills, the Closed Drain Pump, A2-GA1581A/B, can be used to send the collected sour water to Sour Water Stripping Unit.
Issued 30 August 2011
Utility Systems
Page 6-3
Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
WARNING
THE LIQUID DRAINED INTO THE CLOSED DRAIN TANK AND ITS UNDERGROUND HEADER SYSTEM CONTAINS DISSOLVED H2S. ALWAYS OBSERVE PROPER PROCEDURES AND PRECAUTIONS WHEN DRAINING LIQUID FROM THESE ITEMS OR PERFORMING MAINTENANCE ON THEM. THE "GENERAL SAFETY" SECTION OF THIS MANUAL SHOULD BE CONSULTED IF THERE IS ANY DOUBT ABOUT HOW TO WORK SAFELY WHEN H2S MAY BE PRESENT.
6.2.7 6.2.7.1
Steam, Condensate, Boiler Feed Water, and Blowdown Purpose of Systems The Steam system provides heating media for plant systems and equipment and motive driving power for each vent ejector. The Condensate system is designed to collect and return the steam which has been condensed by the users to the Steam system. The Boiler Feed Water system provides suitably conditioned water to the steam generators located within the Sulfur Block. The Blowdown system collects the blowdown water from the boilers in the Sulfur Block for safe disposal.
6.2.7.2
Safety Use appropriate safety precautions when handling the boiler feed water chemicals (sulfite, amine, phosphate, etc.). The normal operating temperatures in the Steam, Condensate, and Boiler Feed Water systems are high enough to cause burns: Steam Pressure
Steam Temperature
48.5 kg/cm2(g) 45.0 kg/cm2(g) 4.2 kg/cm2(g)
262°C 400°C superheated 153°C
Personnel should take the appropriate precautions to avoid burns when working around open vents, open drains, steam traps, or any
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SULFUR BLOCK un-insulated piping in the Steam, Condensate, and Boiler Feed Water systems. It is common for hot water to drip from steam tracing connections, steam traps, etc. Steam leaks and steam vent streams can cause severe burns and lacerations. Also, refer to the discussion concerning boilers in the General Safety section of this manual, Section 2.13. 6.2.7.3
Process Description There are three Steam headers (saturated 48.5 kg/cm2(g), superheated 45 kg/cm2(g) and saturated 3.5 kg/cm2(g)), a low pressure Condensate Return header, a high pressure Condensate Return Header, a Cold Condensate Header, a Boiler Feed Water header, and an atmospheric pressure Blowdown header. There are six steam generators in the Sulfur Block: A2-BF1530
Waste Heat Boiler (sat. 48.5 kg/cm2(g) steam)
A2-BF1540
Waste Heat Boiler (sat. 48.5 kg/cm2(g) steam)
A2-EA1531
Sulfur Condenser (sat. 4.2 kg/cm2(g) steam)
A2-EA1541
Sulfur Condenser (sat. 4.2 kg/cm2(g) steam)
A2-EA1561
TGCU Waste Heat Reclaimer (sat. 4.2 kg/cm2(g) steam)
A2-BF1570
Thermal Oxidizer Waste Heat Boiler (superheated 45.0 kg/cm2(g) steam)
The different subsystems are described below. 6.2.7.4
Boiler Feed Water In accordance with the ASME Section I Code for Power Boilers, boiler feed water must be provided to the Waste Heat Boiler, A2-BF1530 (A2-BF1540), and the Thermal Oxidizer Waste Heat Boiler, A2-BF1570, at 58.3 kg/cm2(g) or higher (i.e., 6% above the relief valve settings). The BFW supply header must be maintained at or above this pressure to safely satisfy this requirement.
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SULFUR BLOCK In accordance with the ASME Section VIII Code for Unfired Steam Boilers, boiler feed water must be provided to the Sulfur Condenser, A2-EA1531 (A2-EA1541), and the TGCU Waste Heat Reclaimer, A2-EA1561, at 5.8 kg/cm2(g)or higher (i.e., 6% above the relief valve settings). 6.2.7.5
HP Steam The Waste Heat Boiler, A2-BF1530 (A2-BF1540), generates HP steam at a normal operating pressure of about 48.5 kg/cm2(g). A small portion of this steam is consumed in the reactor feed heaters to reheat the feed streams to the catalytic reactors in the SRUs. The rest of the HP steam is combined with the steam from the Thermal Oxidizer Waste Heat Boiler, A2-BF1570, enters the Steam Knock-Out Drum, A2-FA1570, to remove any entrained water droplets, and is then routed to the superheat passes in the Thermal Oxidizer Waste Heat Boiler. The Thermal Oxidizer Waste Heat Boiler includes a water-tube boiler that uses part of the waste heat from the Thermal Oxidizer to generate 48.5 kg/cm2(g) saturated steam. The remainder of the waste heat is used to superheat the steam from this boiler after it combines with the HP steam produced by the Waste Heat Boiler. The Thermal Oxidizer Waste Heat Boiler allows a major portion of the heat required to incinerate the sulfur compounds to SO2 to be recovered as useful steam. The superheated steam is exported to the refinery HP steam header at about 400°C and 45.0 kg/cm2(g). Note that the Thermal Oxidizer Waste Heat Boiler is the only source of superheat for the HP steam produced in the Sulfur Block. If the Thermal Oxidizer shuts down and begins to cool, the steam will no longer be sufficiently superheated to satisfy the requirements of the users located outside of battery limits. Under this circumstance, the steam from the superheat passes of the TTO Waste Heat Boiler will instead be vented to atmosphere automatically until the Thermal Oxidizer is restarted and the steam is once again superheated to the proper temperature. HP steam is used as motive fluid for the Sulfur Surge Tank Vent Ejector, A2-EE1530 (A2-EE1540). The steam for this service is normally supplied from the steam produced within the process train. When the HP steam is being vented to atmosphere as described
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SULFUR BLOCK above, however, steam must be imported into the Sulfur Block for this equipment item. 6.2.7.6
LP Steam The Sulfur Condenser, A2-EA1531 (A2-EA1541), in the sulfur plant and the TGCU Waste Heat Reclaimer, A2-EA1561, in the tailgas cleanup unit generate LP steam at a normal operating pressure of about 4.2 kg/cm2(g). This LP Steam is used for heating amine acid gas in the Acid Gas Preheater, A2-EA1530 (A2-EA1540), reboiling the solvent in the ARU Stripper Reboiler, A2-EA1512A/B, the water in the Sour Water Stripper Reboiler, A2-EA1521, and the TGCU solvent in the TGCU Stripper Reboiler, A2-EA1565, miscellaneous steam tracing and steam jacketing of process gas lines, sulfur rundown lines, sulfur vapor valves, etc., and for the heating coils in the Sulfur Surge Tank, A2-EA1531 (A2-EA1531), and Sulfur Storage Tank, A2-FB1550. The remaining LP Steam is exported to the refinery.
6.2.7.7
Condensate Return The HP condensate produced from the HP Steam used in the Sulfur Block is collected and routed to the HP Condensate return system. The LP condensate produced from the LP Steam used in the Sulfur Block is collected and routed to the LP Condensate return system.
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SULFUR BLOCK
6.3
Precommissioning, Startup, and Shutdown Procedures The utility equipment and piping may be put into service as required by the process systems they serve. Normal procedures should be followed after completion of construction to ensure that the lines have been adequately blown or flushed clean before being commissioned. Other than checking for cleanliness and possible leaks, and following good practice in venting lines while they are being filled, no other special procedures should be required to commission the utility systems.
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SULFUR BLOCK
Table of Contents 7. AMINE TREATING & AMINE REGENERATION ......................................................... 7-1 7.1 PURPOSE OF SYSTEM ....................................................................................... 7-1 7.2 SAFETY ................................................................................................................. 7-1 7.3 PROCESS DESCRIPTION.................................................................................... 7-2 7.3.1 General ........................................................................................................... 7-2 7.3.2 Water Washing ............................................................................................... 7-2 7.3.3 Sour Gas Contacting ...................................................................................... 7-3 7.3.4 Solvent Regeneration ..................................................................................... 7-3 7.4 EQUIPMENT DESCRIPTION ................................................................................ 7-6 7.4.1 Wash Water Column, A2-DA1510 .................................................................. 7-6 7.4.2 Amine Absorber, A2-DA1511 ......................................................................... 7-6 7.4.3 Flash Gas Contactor, A2-DA1512 .................................................................. 7-6 7.4.4 Stripper, A2-DA1513 ...................................................................................... 7-6 7.4.5 Wash Water Column Packing, A2-DB1510 .................................................... 7-7 7.4.6 Amine Absorber Trays, A2-DB1511 ............................................................... 7-7 7.4.7 Stripper Trays, A2-DB1513 ............................................................................ 7-7 7.4.8 Amine Absorber Overhead Cooler, A2-EA1510 ............................................. 7-8 7.4.9 Lean/Rich Exchanger, A2-EA1511A/B ........................................................... 7-8 7.4.10 Stripper Reboiler, A2-EA1512A/B .................................................................. 7-8 7.4.11 Stripper Reflux Condenser, A2-EC1511......................................................... 7-8 7.4.12 Lean Amine Cooler, A2-EC1510 .................................................................... 7-8 7.4.13 Wash Water Feed Knock-Out Drum, A2-FA1510 ........................................... 7-8 7.4.14 Amine Absorber Feed Knock-Out Drum, A2-FA1511 ..................................... 7-9 7.4.15 Amine Absorber Overhead Knock-Out Drum, A2-FA1512 ............................. 7-9 7.4.16 Rich Amine Flash Drum, A2-FA1513 ............................................................. 7-9 7.4.17 Stripper Reflux Accumulator, A2-FA1514..................................................... 7-10 7.4.18 Stripper Reboiler Condensate Pot, A2-FA1515A/B ...................................... 7-10 7.4.19 ATU Skim Oil Sump, A2-FA1516 ................................................................. 7-10 7.4.20 ATU Skim Oil Pump Sump, A2-FA1517A/B ................................................. 7-10 7.4.21 ATU Amine Drips Tank, A2-FA1580............................................................. 7-11 7.4.22 MDEA Storage Tank, A2-FB1580 ................................................................ 7-11 7.4.23 Wash Water Filter, A2-FD1510A/B ............................................................... 7-11 7.4.24 Rich Amine Filter, A2-FD1511A/B ................................................................ 7-11 7.4.25 Lean Amine Filter, A2-FD1512 ..................................................................... 7-11 7.4.26 Lean Amine Carbon Filter, A2-FD1513 ........................................................ 7-12 7.4.27 Lean Amine After-Filter, A2-FD1514 ............................................................ 7-12 7.4.28 ATU Amine Drips Filter, A2-FD1580 ............................................................ 7-12
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SULFUR BLOCK 7.4.29 Wash Water Pump, A2-GA1510A/B ............................................................. 7-13 7.4.30 Lean Amine Pump, A2-GA1511A/B ............................................................. 7-13 7.4.31 ATU Skim Oil Pump, A2-GA1512A/B ........................................................... 7-13 7.4.32 Rich Amine Pump, A2-GA1513A/B .............................................................. 7-13 7.4.33 Lean Amine Booster Pump, A2-GA1514A/B ................................................ 7-13 7.4.34 Stripper Reflux Pump, A2-GA1515A/B ......................................................... 7-13 7.4.35 MDEA Transfer Pump, A2-GA1580.............................................................. 7-14 7.5 INSTRUMENTATION AND CONTROL SYSTEMS ............................................. 7-15 7.5.1 Treated Fuel Gas H2S Analyzer ................................................................... 7-15 7.5.2 ATU Emergency Shutdown Systems ........................................................... 7-15 7.5.2.1 Causes of ATU ESD.............................................................................. 7-15 7.5.2.2 Effects of ATU ESD ............................................................................... 7-17 7.5.2.3 Non-ESD Shutdowns and Alarms ......................................................... 7-17 7.6 PROCESS PRINCIPLES AND OPERATING TECHNIQUES ............................. 7-19 7.6.1 Amine Absorber Operation ........................................................................... 7-19 7.6.1.1 Low Temperature .................................................................................. 7-19 7.6.1.2 Acid Gas Loading .................................................................................. 7-20 7.6.1.3 High Amine Concentration .................................................................... 7-20 7.6.2 Stripper Operation ........................................................................................ 7-22 7.6.3 Amine Water Balance ................................................................................... 7-24 7.6.4 Amine Loss ................................................................................................... 7-27 7.6.5 Operation at Low Flow Rates ....................................................................... 7-29 7.7 PRECOMMISSIONING PROCEDURES ............................................................. 7-30 7.7.1 Preliminary Check-out .................................................................................. 7-30 7.7.2 Shutdown System Check-out ....................................................................... 7-31 7.7.3 Leak Testing the Process Piping and Equipment ......................................... 7-31 7.7.4 Washing the Wash Water System ................................................................ 7-33 7.7.4.1 Water Flush ........................................................................................... 7-33 7.7.4.2 Acid Wash ............................................................................................. 7-35 7.7.4.3 Alkaline Wash........................................................................................ 7-36 7.7.4.4 Initial Water Fill ...................................................................................... 7-37 7.7.5 Washing the Amine System ......................................................................... 7-38 7.7.5.1 Water Flush ........................................................................................... 7-38 Acid Wash ............................................................................................. 7-43 7.7.5.2 7.7.5.3 Weak Amine Wash ................................................................................ 7-45 7.7.5.4 Initial Solvent Fill ................................................................................... 7-46 7.7.6 Purging the Low Pressure Columns ............................................................. 7-50 7.7.6.1 Purging the Columns ............................................................................. 7-50 7.8 STARTUP PROCEDURES.................................................................................. 7-52 7.8.1 Wash Water and Amine Systems ................................................................. 7-52
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SULFUR BLOCK 7.8.2 Sour Fuel Gas Flow to the Columns............................................................. 7-53 7.9 SHUTDOWN PROCEDURES ............................................................................. 7-56 7.9.1 Planned Shutdown - ATU ............................................................................ 7-57 7.9.2 Planned Shutdown - ATU and ARU ............................................................. 7-60 7.9.3 Emergency Shutdown .................................................................................. 7-62 7.9.4 Effects of Shutdowns and Outages in Other Systems.................................. 7-63 7.9.4.1 Steam System Outage .......................................................................... 7-63 7.10 ANALYTICAL PROCEDURES ............................................................................ 7-64 7.10.1 General Procedures for Analyzing ATU/ARU Solvent, ................................. 7-64 7.10.2 Determination of Amine Concentration in ATU/ARU Solvent ....................... 7-68 7.10.3 Determination of Total Acid Gas Loading in ATU/ARU Solvent ................... 7-70 7.10.4 Determination of H2S and CO2 Loading in ATU/ARU Solvent ...................... 7-72 7.10.5 Determination of Foaming Tendency of ATU/ARU Solvent .......................... 7-76 7.10.6 H2S Conc. in Amine Absorber Ovhd by the Tutweiler Method ..................... 7-78 7.10.7 H2S Conc. in Amine Absorber Ovhd Using Gas Detector Tubes ................. 7-79 7.10.7.1 Operating Principles .............................................................................. 7-79 7.10.7.2 Sampling the Amine Absorber Overhead Gas ...................................... 7-80 7.10.7.3 Calculations ........................................................................................... 7-81
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SULFUR BLOCK
7. AMINE TREATING & AMINE REGENERATION 7.1
Purpose of System The purpose of the Amine Treating system is to remove essentially all the H2S from the sour fuel gas stream using an aqueous amine solvent, MDEA (methyldiethanolamine). The H2S is absorbed in the amine solvent and the treated fuel gas stream, containing with less than 100 ppmv of H2S, is returned to the complex for consumption as fuel. The purpose of the Amine Regeneration system is to strip the H2S from the rich amine solvent produced in the Amine Treating, LPG Treating and DHT units. The H2S-laden acid gas is sent to the Sulfur Recovery Unit (SRU) for disposal and the lean amine is recycled back to the upstream process units.
7.2
Safety
WARNING
ALL PIPING AND VESSELS INCLUDED IN THIS UNIT EITHER CONTAIN OR HAVE THE POTENTIAL FOR CONTAINING HAZARDOUS GAS THAT MAY CAUSE SERIOUS INJURY OR DEATH. THE GAS THAT IS MOST COMMON AND HAZARDOUS IN A TOXIC WAY IS HYDROGEN SULFIDE. CLOSE ATTENTION SHOULD BE PAID TO THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES AS TO THE NATURE AND ABILITY OF THIS GAS TO CONTAMINATE OTHER ELEMENTS IN THIS UNIT. AN EMPLOYEE'S KNOWLEDGE OF THE HAZARDOUS CHEMICALS AND COMPOUNDS WITH WHICH HE WILL BE WORKING IS ONE OF THE MOST BASIC PREREQUISITES FOR HIS OWN SAFETY, THE SAFETY OF OTHERS, AND THE PROTECTION OF EQUIPMENT. ALL EMPLOYEES SHOULD REVIEW THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES OCCASIONALLY TO REFRESH THEIR MEMORIES. NEW EMPLOYEES SHOULD STUDY IT UNTIL THE INFORMATION IS THOROUGHLY UNDERSTOOD. PEOPLE WHO HAVE NOT BEEN PROPERLY TRAINED SHOULD NOT BE ALLOWED TO OPERATE OR WORK IN AND AROUND THIS PLANT.
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7.3
Process Description
7.3.1
General The Systems Diagram, Material Balance and Process Flow Diagrams, Dwg. Nos. 507000-7000-01, through -04, are contained in the "Process Flow Diagrams" Section of the Basic Engineering Package. Please refer to these drawings to follow this description of the process. The Amine Treating Unit (ATU) uses an aqueous amine solvent, MDEA (methyldiethanolamine), to remove essentially all the H2S from the sour fuel gas stream. The normal solvent concentration is 45 wt % MDEA in water. The ATU is designed to treat 10,397 Nm3/hr of sour fuel gas. The treated gas stream is returned to the refinery for consumption as fuel, and the acid gas (H2S, plus CO2) is routed to the Sulfur Recovery Units (SRUs). Less than 100 PPMV of H2S remains in the treated fuel gas.
7.3.2
Water Washing Sour fuel gas streams in chemical complexes are often contaminated with various gaseous, liquid, and even solid substances. In order to prevent these contaminants from causing operating problems (foaming, poor treating, corrosion, etc.) in the amine solvent system, the sour fuel gas streams are washed with water to remove the contaminants upstream of the amine contactors. Some of the more common contaminants are ammonia (NH3), hydrogen cyanide (HCN), and hydrocarbon liquids. The sour fuel gas enters Wash Water Feed Knock-out Drum, A2-FA1510, at 38°C [100°F] and 6.0 kg/cm2(g) [85 PSIG]. Any entrained liquids are removed automatically on level control and routed to the sour liquids system. The scrubbed gas enters the bottom of the Wash Water Column, A2-DA1510, and passes upward through a packed bed where it is countercurrently contacted with a stream of circulating water. The washed sour gas stream leaves the top of the column and flows to Amine Absorber Feed Knock-out Drum, A2-FA1511, to remove any wash water that may be carried over with the gas. The scrubbed gas proceeds to the Amine Absorber, A2-DA1511, while any wash water carry-over is routed to the Closed Drain system on level control. The wash water leaving the bottom of the column is pumped by the Wash Water Pump, A2-GA1510A/B, to the Wash Water Filter, A2-FD1510A/B, for removal of any particulates or other solid material removed from the sour gas feed. Most of the filtered water is returned to the top of Wash
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SULFUR BLOCK Water Column on flow control, after being mixed with fresh makeup water. The remainder of the filtered water is directed to the Sour Water Stripping Unit (SWS) to purge the gaseous and liquid contaminants removed by the wash water from the system. The makeup water rate can be adjusted as necessary to control the contaminants (primarily ammonia in most cases) at an acceptable concentration, and the level control on the column bottoms will automatically adjust the purge rate to balance the water added to the system with the makeup water flow control.
7.3.3
Sour Gas Contacting The washed sour refinery fuel gas enters the bottom of the Amine Absorber at 37°C [98°F] and 5.8 kg/cm2(g) [82 PSIG] and passes upward through 30 trays to be contacted countercurrently with lean MDEA solvent. As the sour gas is contacted by the amine, the acidic H2S (and CO2, if present) in the gas reacts with the basic amine solution: (1)
H2S + CH3(CH2OHCH2)2N
CH3(CH2OHCH2)2NH+ + HS–
(2)
CO2 + CH3(CH2OHCH2)2N + H2O
CH3(CH2OHCH2)2NH+ + HCO3–
This is an acid-base reaction, forming an amine "salt" that remains dissolved in the aqueous solution. The rich amine leaves the bottom of the column at 58°C [136°F] on level control and is routed to the Rich Amine Flash Drum, A2-FA1513. The treated gas leaves the top of the column and flows to the Amine Absorber Overhead Cooler, A2-EA1510, where it is cooled to 37°C [98°F] before flowing to the Amine Absorber Overhead Knock-out Drum, A2-FA1512, where any solvent carry-over is recovered and returned to the rich solvent stream on level control. The scrubbed treated gas at 37°C [98°F] and 4.5 kg/cm2(g) [64 PSIG] is then routed to the treated fuel gas header for consumption elsewhere in the complex.
7.3.4
Solvent Regeneration The combined rich solvent stream from the Amine Treating Unit, the LPG Treating Unit, and the DHT Unit enters the Rich Amine Flash Drum at 54°C [130°F]. This vessel is operated at low pressure (0.64 kg/cm2(g) [9 PSIG]) to maximize the vaporization and removal of any light hydrocarbons that may be entrained or dissolved in the amine solvent. A small amount of H2S will be liberated from the rich amine by the pressure reduction, so the resulting flash gases enter the bottom of the Flash Gas Contactor, A2-DA1512, and flow upward through its packed bed to be
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SULFUR BLOCK countercurrently contacted with a small stream of lean amine. The amine will remove most of the H2S from the flash gas, so that the treated gas flowing to the flare will contain 200 PPMV or less of H2S. The rich amine from the bottom of the packed bed falls into the flash drum to join the other rich solvent. The flash drum is large enough to provide 30-40 minutes or more of residence time for the rich solvent. This allows time for any heavy hydrocarbons entrained in the solvent to separate as a second liquid phase that spills over the internal weir at the inlet end of the drum, collecting in the ATU Skim Oil Sump, A2-FA1516. The ATU Skim Oil Pump, A2-GA1512A/B, sends the collected hydrocarbon to the Condensate Feed Tank on start/stop level control. After removal of any liquid hydrocarbon, the heavier amine phase passes under the internal weir at the outlet end of the drum to be pumped through the Rich Amine Filter, A2-FD1511A/B, by the Rich Amine Pump, A2-GA1513A/B, on level/flow cascade control. The filter removes particulates from the solvent before it enters the tube side of the Lean/Rich Amine Exchanger, A2-EA1511A/B. The Rich Amine is preheated to 105°C [221°F] by cooling the lean solvent before flowing to the Stripper, A2-DA1513, entering between trays #4 and #5. The Stripper contains 30 valve trays (4 wash water trays, 26 stripping trays) and one chimney draw tray. As the solvent flows down the column, the absorbed H2S and CO2 are stripped from the MDEA by countercurrent contact with stripping steam rising upward. This stripping steam is generated in the Stripper Reboiler, A2-EA1512A/B, using LP (3.5 kg/cm2(g) [50 PSIG]) steam as the heat input. The heat input to the reboilers is adjusted by flow control of the steam. The steam flow controllers can be reset by the Stripper overhead temperature, which will maintain the desired overhead temperature of 114°C [238°F] by varying the heat input in proportion to the amount of acid gas contained in the Rich Amine. The stripping steam supplies the heat of reaction required to reverse reactions (1) and (2), and carries the H2S and CO2 stripped from the solvent overhead to the Stripper Reflux Condenser, A2-EC1511, where the steam is condensed as the stream is cooled to 49°C [120°F]. The condensed water is removed by the Stripper Reflux Accumulator, A2-FA1514, and returned as reflux to the wash water trays in the tower by the Stripper Reflux Pump, A2-GA1515A/B. The acid gas (H2S and CO2,
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SULFUR BLOCK along with the uncondensed water) stripped from the solvent exits the reflux drum at 0.85 kg/cm2(g) [12 PSIG] and flows to the SRUs. The Lean Amine Booster Pump, A2-GA1514A/B, pumps the regenerated lean MDEA solvent from the bottom of the Stripper through the shell side of the Lean/Rich Amine Exchanger, cooling the lean solvent from 259°F to 78°C [172°F] by countercurrent heat exchange with the cool rich amine. A slipstream of the lean amine then flows through the Lean Amine Filter, A2-FD1512, to remove accumulated solids from the solvent and through the Lean Amine Carbon Filter, A2-FD1513, where the activated carbon adsorbs contaminants such as hydrocarbons and degradation products from solvent. The Lean Amine After-Filter, A2-FD1514, catches any carbon "fines" before the filtered slipstream rejoins the main solvent stream. A portion of the lean amine flows to the DHT unit on temperature control while the remainder flows to the Lean Amine Cooler, A2-EC1510, where it is cooled to 50°C [122°F]. A small stream of cool lean amine is directed on flow control to the top of the Flash Gas Contactor as described previously. A portion of the cool lean amine flows to the LPG Treating Unit and a portion flows to the DHT unit on temperature control. The remaining lean amine is pumped to higher pressure by the Lean Amine Pump, A2-GA1511A/B before being directed on flow control to the top of the Amine Absorber.
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SULFUR BLOCK
7.4
Equipment Description
7.4.1
Wash Water Column, A2-DA1510 The Wash Water Column contains a single bed of random packing to provide good contact between the sour fuel gas and the circulating wash water. The tower has a 304 S.S. woven wire mist eliminator above the packed bed to remove entrained water droplets from the gas before it leaves the tower.
7.4.2
Amine Absorber, A2-DA1511 The Amine Absorber contains a 30 valve trays to provide good contact between the sour fuel gas and the amine solvent to remove H2S from the fuel gas. The tower has a 304 S.S. woven wire mist eliminator above the top bed to remove entrained solvent droplets from the gas before it leaves the tower.
7.4.3
Flash Gas Contactor, A2-DA1512 As lighter hydrocarbons are allowed to disengage from the amine in the Rich Amine Flash Tank, a small amine flow scrubs these lighter hydrocarbons of acid gas as the amine and hydrocarbon flow counter currently. The Flash Gas Contactor contains a single bed of random packing which provides good contact between the light hydrocarbon gas entering below it and the amine fed above it.
7.4.4
Stripper, A2-DA1513 The Stripper contains 28 valve trays to provide good contact between the rich amine solvent and the reboiler vapors to strip H2S and CO2 from the solvent. The rich amine enters on the fifth tray from the top; the four trays above that are "water wash" trays that allow the reflux water (entering on the top tray) to remove traces of MDEA from the overhead vapor and minimize solvent losses. A chimney tray is located below the bottom valve tray to gather all of the column liquids to feed the Stripper Reboiler. The column section located below this chimney tray serves to separate the outlet steam and lean amine from the reboiler and to provide surge for the solvent circulating system.
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SULFUR BLOCK 7.4.5
Wash Water Column Packing, A2-DB1510 This bed of random packing provides good contact between the sour fuel gas entering below it and the wash water fed above it inside the Wash Water Column. The packing has a bed limiter above it and rests on a bed support. The quench water is distributed over the packing by a distributor tray. The packing is 304 S.S.; the other internals are 304 S.S. Gaskets are installed where the bed support and distributor tray bolt to the support ring and clips inside the Wash Water Column to prevent direct contact between the stainless steel internals and the carbon steel vessel. This electrically isolates the dissimilar metals from each other to prevent direct contact that could lead to galvanic corrosion.
7.4.6
Amine Absorber Trays, A2-DB1511 These 1-pass valve trays provide good contact between the fuel gas entering below it and lean amine fed above it inside the Amine Absorber. The tray decks and tray downcomers are 304L S.S., and the valves are fabricated from 304 S.S. to resist corrosion and to prevent "sticking" to the tray decks.
7.4.7
Stripper Trays, A2-DB1513 These 1-pass valve trays provide good contact between the rich amine solvent fed above them and the reboiler vapors fed below them inside the Stripper. The tray decks are 304L S.S., and the valves are fabricated from 304 S.S. to resist corrosion and to prevent "sticking" to the tray decks. The chimney tray deck is 304L S.S. The bottom valve tray has a seal pan for its downcomer to maintain a liquid seal and prevent gas from blowing up the downcomer. The chimney tray gathers the tower liquids to feed the reboiler. The outlet from the reboiler reenters the column below the chimney tray, with the vapor produced by the reboiler flowing upward through the chimneys in order to reach the valve trays above. The top four trays in the column are located above the rich amine feed point and serve as water-wash trays to minimize the amount of amine carried-over in the tower overhead. Since these trays have only the reflux water flowing over them, the liquid rates for these trays are much lower than for the trays lower in the column. For this reason, these four trays are designed for minimum leakage (i.e., picket fence weirs, minimum downcomer clearance, etc.).
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SULFUR BLOCK 7.4.8
Amine Absorber Overhead Cooler, A2-EA1510 This shell and tube exchanger is used to provide the final cooling of the treated fuel gas, with cooling water from the complex as the cooling medium.
7.4.9
Lean/Rich Exchanger, A2-EA1511A/B These shell and tube exchangers conserve energy by providing heat exchange between the rich amine and the lean amine, so that the hot lean amine leaving the Stripper can preheat the rich amine before it feeds the Stripper. This cross exchange saves reboiler duty by preheating the rich amine, and reduces the load on the Lean Amine Cooler by partially cooling the hot lean amine.
7.4.10
Stripper Reboiler, A2-EA1512A/B The Stripper Reboilers are a fixed tubesheet shell and tube heat exchangers. The exchangers are arranged as once-through vertical thermosiphon reboilers, mounted on the side of the Stripper. The static head of the solvent above the inlet nozzle on the lower channel provides the driving force to circulate the solvent through the tubes. LP steam on the shell of the exchangers heats the solvent inside the tubes, partially vaporizing it to create stripping steam to remove the H2S and the CO2 from the solvent flowing down the Stripper.
7.4.11
Stripper Reflux Condenser, A2-EC1511 This forced-draft aerial exchanger provides cooling to condense the majority of the water from the acid gas stream leaving the overhead of the Stripper. Fans are used to circulate air across the finned tubes to remove heat from the overhead stream and condense the water to be used as reflux for the tower.
7.4.12
Lean Amine Cooler, A2-EC1510 This forced-draft aerial exchanger provides the final cooling of the lean amine stream returning from the regeneration section of the process. Fans are used to circulate air across the finned tubes to remove heat from the solvent.
7.4.13
Wash Water Feed Knock-Out Drum, A2-FA1510 This vertical vessel is installed in the inlet sour fuel gas line to remove liquids from the gas stream before it is routed to the Wash Water Column.
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SULFUR BLOCK The liquid produced in this vessel is routed to the closed drain on automatic start/stop control. The vessel is equipped with high level alarms to warn of a rising level in the drum, and a high-high level shutdown to activate the ATU ESD system before liquids can reach the column. The shutdown requires that 2 out of 3 transmitters have a high-high level indicated.
7.4.14
Amine Absorber Feed Knock-Out Drum, A2-FA1511 This vertical vessel is installed in the overhead line from the Wash Water Column to remove liquids from the gas stream before it is routed to the Amine Absorber. The liquid produced in this vessel is routed to the closed drain on automatic start/stop control. The vessel is equipped with high level alarms to warn of a rising level in the drum, and a high-high level shutdown to activate the ATU ESD system before liquids can reach the absorber. The shutdown requires that 2 out of 3 transmitters have a high-high level indicated.
7.4.15
Amine Absorber Overhead Knock-Out Drum, A2-FA1512 This vertical vessel is installed in the overhead line from the Amine Absorber to remove liquids from the treated fuel gas stream before it is routed to the complex fuel gas system. The liquid produced in this vessel is combined with the rich amine stream leaving the Amine Absorber on automatic start/stop control.
7.4.16
Rich Amine Flash Drum, A2-FA1513 This horizontal vessel allows for the removal of hydrocarbons that may be carried out of the various upstream processes with the amine. The rich amine enters the vessel through a slotted, vertical distributor. Any hydrocarbon that may be carried with the amine from the upstream processes will accumulate in the center section of this vessel. When a sufficient amount of hydrocarbon has accumulated, the hydrocarbon will overflow the partition and flow into the hydrocarbon section. Lighter hydrocarbons are disengaged from the amine and exit through the Flash Gas Contactor where they are washed free of any acid gases. Hydrocarbon-free amine then passes under another partition, at the opposite end of the vessel, and into the amine outlet section, where the amine is pumped to the Stripper.
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SULFUR BLOCK 7.4.17
Stripper Reflux Accumulator, A2-FA1514 This vertical pressure vessel removes condensed water from the stream leaving the Stripper Reflux Condenser so that the water can be used as reflux for the Stripper. The vessel has a 304 S.S. woven wire mist eliminator in the top to remove entrained liquid droplets from the gas before it leaves the vessel.
7.4.18
Stripper Reboiler Condensate Pot, A2-FA1515A/B These two vertical pressure vessels collect the condensate from the Stripper Reboiler and return it to the condensate system on level control. This method of removing condensate from the exchanger provides much smoother control of the heat input to the reboiler than a conventional steam trap could. As stated above, this vessel is simply a very good steam trap. During normal operation, the steam pressure required to provide the necessary reboil heat to the Stripper may be much less than the 3.5-4.2 kg/cm2(g) steam pressure available in the LP steam system. The normal steam pressure in the shell of the reboiler may be such that the water level in the condensate pot will rise upwards from the pot, perhaps even within the shell of the reboiler. During these periods, the level valve will remain fully open and the sight glass will indicate a full water level. This is a normal operating condition for this vessel. The vessel will usually operate with a visible level only when the Stripper Reboiler is operating near its maximum capacity with full steam pressure on the shell of the exchanger. Under these conditions, the level control and level valve will function normally and maintain a water level in the vessel.
7.4.19
ATU Skim Oil Sump, A2-FA1516 This horizontal vessel is located in a below-ground concrete vault. It collects the heavy hydrocarbons from the Rich Amine Flash Tank. The collected hydrocarbon liquid is pumped back to the Condensate Feed Tank on stop/start level control.
7.4.20
ATU Skim Oil Pump Sump, A2-FA1517A/B These vertical vessels house the ATU Skim Oil pumps. Hydrocarbon liquids from the ATU Skim Oil Sump flow into this vessel and are pumped out by the ATU Skim Oil Pump.
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SULFUR BLOCK 7.4.21
ATU Amine Drips Tank, A2-FA1580 This horizontal pressure vessel is located in a below-ground concrete vault. It collects solvent from the ATU via headers when equipment is drained for maintenance, etc. The vessel will normally operate with little or no pressure so that gravity-flow is sufficient to cause solvent to drain into the vessel. The collected solvent is pumped back to the solvent system in the ATU for reuse when the vessel gets full.
7.4.22
MDEA Storage Tank, A2-FB1580 This vertical, cylindrical, cone roof storage tank holds fresh MDEA solvent unloaded from transport trucks until it is needed for make-up to the ATU solvent system.
7.4.23
Wash Water Filter, A2-FD1510A/B These filters are designed to remove solid particles 5 microns and larger from the circulating wash water.
7.4.24
Rich Amine Filter, A2-FD1511A/B These full-flow filters are designed to remove solid particles 5 microns and larger from the circulating rich solvent, which will help prevent fouling of the downstream heat exchangers.
WARNING THESE FILTERS HANDLE LIQUID CONTAINING H2S AND OTHER HARMFUL SUBSTANCES. ALWAYS OBSERVE PROPER PROCEDURES AND PRECAUTIONS WHEN PERFORMING MAINTENANCE ON THIS FILTER. THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES SHOULD BE CONSULTED IF THERE IS ANY DOUBT ABOUT HOW TO WORK SAFELY WHEN H2S MAY BE PRESENT.
7.4.25
Lean Amine Filter, A2-FD1512 This full-flow filter is designed to remove solid particles 5 microns and larger from the circulating lean solvent.
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SULFUR BLOCK 7.4.26
Lean Amine Carbon Filter, A2-FD1513 This full-flow filter is designed to remove organic contaminants (trace hydrocarbons, degradation products, etc.) from a slipstream of the circulating lean solvent using a bed of activated carbon.
7.4.27
Lean Amine After-Filter, A2-FD1514 This filter is designed to remove solid particles, particularly carbon fines, 5 microns and larger from the lean solvent leaving the Lean Amine Carbon Filter.
7.4.28
ATU Amine Drips Filter, A2-FD1580 This filter is designed to remove solid particles 5 microns and larger from the recovered solvent drained from equipment, etc. in the ATU. The recovered solvent is filtered as it is routed back to the ATU.
CAUTION SINCE THE PUMPS DESCRIBED IN THE FOLLOWING SECTIONS ARE CONSTRUCTED OF STAINLESS STEEL, DO NOT HYDROTEST THE ASSOCIATED VESSELS OR PIPING WITH WATER CONTAINING HIGH LEVELS OF CHLORIDES. AVOID ALLOWING WATER CONTAINING MORE THAN 50 PPM CHLORIDES TO COME IN CONTACT WITH THESE PUMPS TO PREVENT STRESS CORROSION CRACKING OF THE STAINLESS STEEL.
WARNING THE LIQUID IN THESE PUMPS CONTAINS DISSOLVED H2S. THIS H2S CAN BE RELEASED TO THE SURROUNDINGS WHEN LIQUID IS DRAINED FROM THESE PUMPS OR FROM THE PIPING CONNECTED TO THE PUMPS. ALWAYS OBSERVE PROPER PROCEDURES AND PRECAUTIONS WHEN DRAINING LIQUID FROM THESE PUMPS OR PERFORMING MAINTENANCE ON THEM. THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES SHOULD BE CONSULTED IF THERE IS ANY DOUBT ABOUT HOW TO WORK SAFELY WHEN H2S MAY BE PRESENT.
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SULFUR BLOCK 7.4.29
Wash Water Pump, A2-GA1510A/B These centrifugal pumps are used to circulate wash water to which is used to remove contaminates from the sour gas feed stream. Each pump is designed for the total duty; the other pump is a 100% spare. These pumps are equipped with tandem seals to reduce the likelihood of releasing H2S to the surroundings.
7.4.30
Lean Amine Pump, A2-GA1511A/B These centrifugal pumps are used to send the lean amine from the Amine Regeneration Unit to the Amine Absorber. Each pump is designed for the total duty; the other pump is a 100% spare. These pumps are equipped with tandem seals to reduce the likelihood of releasing H2S to the surroundings.
7.4.31
ATU Skim Oil Pump, A2-GA1512A/B These vertical sump-type pump is mounted in the ATU Skim Oil Pump Sump to transfer the recovered hydrocarbons back to the Condensate Feed Tank.
7.4.32
Rich Amine Pump, A2-GA1513A/B These centrifugal pumps are used to send the rich amine from the Rich Amine Flash Drum to the Stripper. Each pump is designed for the total duty; the other pump is a 100% spare. These pumps are equipped with tandem seals to reduce the likelihood of releasing H2S to the surroundings.
7.4.33
Lean Amine Booster Pump, A2-GA1514A/B These centrifugal pumps are used to send the lean amine from the Amine Regeneration Unit to the DHT Unit, the LPG Treating Unit, and to the suction of the Lean Amine Pumps in the Amine Treating Unit. Each pump is designed for the total duty; the other pump is a 100% spare. These pumps are equipped with tandem seals to reduce the likelihood of releasing H2S to the surroundings.
7.4.34
Stripper Reflux Pump, A2-GA1515A/B These centrifugal pumps are used to send the reflux from the Stripper Reflux Accumulator to the Stripper. Each pump is designed for the total duty; the other pump is a 100% spare. These pumps are equipped with
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SULFUR BLOCK tandem seals to reduce the likelihood of releasing H2S to the surroundings.
7.4.35
MDEA Transfer Pump, A2-GA1580 This single-stage centrifugal pump is used to transfer amine from the MDEA Storage Tank to the ATU solvent system. This pump does not run continuously so no spare is provided.
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SULFUR BLOCK
7.5
Instrumentation and Control Systems
7.5.1
Treated Fuel Gas H2S Analyzer Analyzer A2-AE15057 measures the H2S concentration in the treated fuel gas leaving Amine Absorber Overhead Knock-out Drum, A2-FA1512. If the H2S concentration exceeds the specification for fuel gas (200 PPMV), DCS relay A2-AY15057 should start ramping down the signal that pressure controller A2-PC15057 is supplying to control valve A2-PV15057. As this valve closes, the pressure will start to rise, until it reaches the setpoint (6.0 kg/cm2(g)) of the over-ride pressure controller, A2-PC15059, which will then open control valve A2-PV15059 to divert the fuel gas to the flare header. The duration of the ramping should be about 60 seconds or so, so that the pressure in the system does not change too rapidly. Once the H2S concentration is back on-specification, A2-AY15057 should start ramping up the signal from A2-PC15057 to A2-PV15057. As this control valve opens and the pressure starts to drop back to its normal value (5.0 kg/cm2(g)), the over-ride pressure controller will then close A2-PV15059, so that the fuel gas is flowing to the fuel gas header once again. The duration of this ramping should again be about 60 seconds or so, so that the pressure in the system does not change too rapidly. A2-HS15057 in the DCS is a bypass to disable relay A2-AY15057 and prevent it from changing the control signal to A2-PV15057. This switch can be used to prevent upset of process operations when calibrating or performing maintenance on the analyzer.
7.5.2
ATU Emergency Shutdown Systems The purpose of the ATU ESD system is to shut off the flow of sour fuel gas to the treating system when serious problems occur. The Cause and Effect Diagrams are contained in the Instrumentation and Controls Drawings section of the Basic Engineering Package. These diagrams describe the ATU ESD system in block format. For reference, the causes and effects of the ESD system shown on these diagrams is explained below.
7.5.2.1
Causes of ATU ESD Any one of the devices listed below will activate the ATU ESD system:
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SULFUR BLOCK a.
Manual Shutdown Switch, A2-HS15022 An operator can activate the ATU ESD system using these guidelines shutdown switch in the DCS, a "timed pulse" switch.
b.
Wash Water Feed Knock-out Drum High-High Liquid Level, A2-LT15008A/B/C. This device prevents liquids in this vessel from entering the wash water system for the sour refinery fuel gas and contaminating it, since this could then lead to contamination of the solvent system. It is set to actuate if the liquid level reaches 1,050 mm above the bottom seam of the vessel. Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD (i.e., at least two transmitters must show high-high level) to avoid spurious "trips" due to the malfunction of a single transmitter.
c.
Amine Absorber Feed Knock-out Drum High-High Liquid Level, A2-LT15030A/B/C. This device prevents liquids in this vessel from entering the Amine Absorber and contaminating the solvent system. It is set to actuate if the liquid level reaches 1,200 mm above the bottom seam of the vessel. Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD.
d.
Amine Absorber Low-Low Liquid Level, A2-LT15040A/B/C. If the solvent level drops too low in the Amine Absorber, large amounts of high pressure gas could blow through control valve A2-LV15040 into the Rich Solvent Flash Drum, A2-FA1513, and other equipment and piping in the ATU/ARU with a lower design pressure than this column. Loss of solvent in this column could also result in the treated fuel gas going sour. This device is set to actuate if the liquid level drops to 450 mm above the bottom seam of the vessel. To reduce the chances of blow-through, this device will also de-energize solenoid valve A2-NY15040 to close the control valve. Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD.
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SULFUR BLOCK 7.5.2.2
Effects of ATU ESD A shutdown of the Amine Absorber, activated either manually or automatically, has the following effects on the ATU/ARU: a.
Closes A2-NV15002, blocking the flow of high pressure sour fuel gas into the ATU.
b.
If the ESD system is activated by low-low level in the Amine Absorber, closes A2-LV15040 to prevent possible blow-through of high pressure gas into the low pressure sections of the ATU/ARU.
When S/D valve A2-NV15002 closes to stop the gas flow into the ATU, the pressure of the incoming sour fuel gas will begin to rise. When it reaches the setpoint (6.3 kg/cm2(g)) of over-ride pressure controller A2-PC15001, the controller will open control valve A2-PV15001 to divert the sour gas to the flare header. 7.5.2.3
Non-ESD Shutdowns and Alarms In addition to the devices listed in Section 7.5.2.1 that activate the ATU ESD system, there are several interlocks of significance that either generate an alarm or shut down an individual piece of equipment. These devices/interlocks and their effects are described in this section. a.
Wash Water Column Low-Low Level, A2-LT15014A/B/C The Wash Water Pump (A2-GA1510A/B) could be damaged if the pump loses suction because the level in the Wash Water Column drops too low. This device will protect the pump by stopping it before this can occur. The setpoint is 450 mm above the bottom seam of the column. Note that there are three independent transmitters and 2oo3 voting logic is used for the shutdown.
b.
Treated Fuel Gas High-High H2S, A2-AE15057 This device closes pressure control valve A2-PV15057 to the treated fuel gas header and opens pressure control valve A2-PV15059 to the flare header when the H2S concentration for the treated fuel gas exceeds 200 ppmv.
a.
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SULFUR BLOCK The Rich Amine Pump (A2-GA1513A/B) could be damaged if the pump loses suction because the level in the Rich Amine Flash Drum drops too low. This device will protect the pump by stopping it and closing the downstream flow control valve before this can occur. The setpoint is 685 mm above the bottom of the vessel. Note that there are three independent transmitters and 2oo3 voting logic is used for the shutdown. c.
Lean Amine Cooler Fan High Vibration, A2-WSH15080 Each fan on the Lean Amine Cooler (A2-EC1510) is provided with its own vibration switch. If the vibration sensed by the switch exceeds the preset level, the switch will trip to stop the associated fan and activate an alarm in the DCS.
d.
Stripper Low-Low Level, A2-LT15108A/B/C The Lean Amine Booster Pump (A2-GA1514A/B) could be damaged if the pump loses suction because the level in the Stripper drops too low. Likewise, the Lean Amine Pump (A2-GA1511A/B) could be damaged if the pump loses suction because the Lean Amine Booster Pump has stopped. This device will protect these pumps by stopping both pumps before this scenario can occur. The setpoint is 450 mm above the bottom seam line of the column. Note that there are three independent transmitters and 2oo3 voting logic is used for the shutdown.
e.
Stripper Reflux Condenser Fan High Vibration, A2-WSH15118 Each fan on the Stripper Reflux Condenser (A2-EC1511) is provided with its own vibration switch. If the vibration sensed by the switch exceeds the preset level, the switch will trip to stop the associated fan and activate an alarm in the DCS.
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SULFUR BLOCK
7.6
Process Principles and Operating Techniques The more important considerations involved in startup, operation, shutdown, maintenance, and emergency procedures for the ATU and ARU are discussed in the remaining sections of this portion of the operating guidelines. The operator should also be thoroughly acquainted with the equipment and the "Process Description" section of these guidelines before attempting to operate the plant in accordance with the operating techniques that follow. If the function of each portion of the plant equipment is understood, the sequence of steps outlined in the "procedures" sections will be more easily understood. In addition, the following general discussion of principles and techniques will clarify the reasons for some of the procedures.
7.6.1
Amine Absorber Operation The main requirement for the Amine Absorber is to consistently produce treated fuel gas which contains a low level of residual H2S. The absorption of H2S in the amine solution is favored by: 1. Low temperature 2. Acid gas loading 3. High amine concentration 4. High H2S partial pressure in the feed stream 5. Intimate contacting In general practice, items 4 and 5 are not operating variables, having been fixed by the design criteria for the unit and choice of equipment in the absorber design.
7.6.1.1
Low Temperature The lower the temperature of the lean amine solution, the better the H2S removal. When treating a hydrocarbon gas, however, the lean amine temperature is limited by the temperature of the gas being treated. The lean amine temperature must be maintained 3-6°C higher than that of the gas feed stream to avoid any possible condensation of these vapors. The circulating lean amine temperature before it enters the absorber is commonly between 27°C and 49°C.
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SULFUR BLOCK 7.6.1.2
Acid Gas Loading Good acid gas removal efficiency depends on good amine solution regeneration, as will be discussed in the following sections. However, it also depends on restricting the H2S loading in the rich amine to favor the forward direction of reaction (1) given in section 7.3.3. The loading of the amine solution is controlled by adjustment of the amine circulation rate. In most cases, unless special design considerations have been employed, the rich amine acid gas loading (H2S plus CO2) should not exceed 0.3 to 0.4 mols total acid gas per mol of amine present.
7.6.1.3
High Amine Concentration The concentration of uncombined amine ion is favored by high amine concentration in the amine solution, good regeneration, and freedom from strong acids. Practical and economic considerations confirmed by field experience have generally shown that the optimum amine concentration is between 15 and 50 wt-% amine depending upon the type of amine used. This is based on the lowest heat requirement for the desired H2S removal, the lowest chemical losses, and the fewest operational problems. The free amine ion concentration in the lean amine is mainly affected by the efficiency and control of amine regeneration. The fewer the sulfide ions in the lean amine, the greater the free amine ion concentration available for removal of H2S. In most cases, lean amine should not contain more than 0.03 mol H2S per mol amine nor more than 0.1 mol CO2 per mol amine. The amine strength should be monitored and the amine content of the circulating amine should be maintained close to the 45% (by weight) design value. Should the amine concentration decrease (normally due to blowdown and other amine losses), it will be necessary to add fresh amine to compensate. Laboratory procedures for analyzing amine are given in a later section of these guidelines. The amine should also be checked periodically for heat-stable salt content. Heat-stable salts form when the amine in the amine solution (a base) reacts with strong acids to form salts that do not decompose at the normal amine regeneration temperature. The most common heat-stable salts encountered in amine systems are SO2 salts, although oxygen contamination of the amine is another common culprit for heat-stable salts in these systems. Heat-stable salts
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SULFUR BLOCK increase the corrosivity of the amine (particularly at higher temperatures, like in the Stripper Reboiler) and increase the foaming tendencies of the amine. (Interestingly, heat-stable salts sometimes improve the H2S-removal capability of the amine, but the higher corrosion rate caused by the salt far outweighs this advantage.) A heat-stable salt content of 2 wt % or lower is desirable. Salt contents in the 5-20 wt % range can be corrosive and should be avoided if possible. The only way to reduce the heat-stable salt content of the amine is by dilution, blowing down some of the circulating amine and making up with fresh amine. There is no means for regenerating heat-stable salt from the amine while it is in the ATU/ARU, as vacuum distillation is required. (In recent years, however, several companies have successfully reclaimed amine on-line using ion exchange on a slipstream of the amine.) There are firms that specialize in reclaiming amine (usually off-site), and it may be economical to use such a firm if a large amount of amine has been contaminated with heat-stable salts. The best practice, however, is to avoid forming heat-stable salt in the first place by proper operation of the ATU, and gas-blanketing the fresh amine to avoid oxygen contamination.
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SULFUR BLOCK 7.6.2
Stripper Operation The lean amine must remain comparatively free of H2S and CO2 to assure attainment of the fuel gas specification. These acid gases are removed from the rich amine in the Stripper by stripping them out with steam. The stripping steam supplies heat to reverse the acid-base reaction between the H2S/CO2 and the amine, and also reduces the H2S/CO2 partial pressure in the vapor phase inside the column to promote mass transfer from the liquid. The stripping steam is produced by vaporizing some of the water in the amine in the Stripper Reboiler, using LP (3.5-4.2 kg/cm2(g)) steam for the heat input. The steam rate to the reboiler (and, hence, the amine stripping rate) is controlled by A2-FC15112A. Adjust this steam rate as needed to keep the H2S and CO2 loading in the lean amine low. See Section 7.10 in these guidelines for appropriate laboratory procedures. For a given column operating pressure, the overhead temperature is a direct indication of the stripping rate: the higher the temperature, the more stripping. Column bottoms temperature should not be used as a guideline for degree of stripping, as it is a function only of amine concentration and column pressure.
CAUTION THE DESIGN STRIPPING STEAM RATE SHOWN ON THE PROCESS FLOW DIAGRAM SHOULD BE CLOSE TO OPTIMUM. ALTHOUGH IT MAY BE POSSIBLE TO REDUCE THIS SOMEWHAT WITHOUT GOING OUT OF COMPLIANCE (I.E., WITH LITTLE CHANGE IN THE H2S LOADING OF THE LEAN SOLVENT), REDUCING THE STRIPPING STEAM RATE SIGNIFICANTLY CAN CAUSE ACCELERATED CORROSION DUE TO HIGH CO2 LOADINGS IN THE LEAN SOLVENT. SEVERAL PLANTS HAVE REPORTED UNEXPECTEDLY HIGH CORROSION RATES IN THE HOT, HIGH VELOCITY AREAS OF THE LEAN SOLVENT SYSTEM, SUCH AS THE OUTLET ENDS OF THE REBOILER TUBES AND THE LEAN SOLVENT PUMPS, AFTER REDUCING THE REBOILER STEAM.
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SULFUR BLOCK IF IT IS NECESSARY TO OPTIMIZE THE STEAM TO THE STRIPPER REBOILER, REDUCE THE STEAM BY SMALL INCREMENTS AND CHECK THE LEAN SOLVENT LOADINGS (BOTH H2S AND CO2) AFTER EACH CHANGE. DO NOT REDUCE THE STEAM FURTHER IF EITHER LOADING BEGINS TO RISE SIGNIFICANTLY, AND BE PREPARED TO PERFORM MORE EXTENSIVE CORROSION MONITORING WHEN OPERATING THE STRIPPER IN THIS MANNER. REFER TO SECTION 7.10 OF THESE GUIDELINES FOR THE PROCEDURES TO BE USED TO DETERMINE THE LEAN SOLVENT LOADINGS. The withdrawal of lean amine from the bottom of the Stripper is on flow control to the Amine Absorber. As a result, the level in the bottom of the Stripper, which serves as the "surge" for the system, will usually indicate if adjustments of water makeup to the amine system (or water "bleed" from the system) are required to maintain the proper water balance, as discussed later in Section 7.6.3 Even if water must be bled from the system by diverting some of the column reflux to Sour Water Stripping, the amine content of that waste stream should be low and only infrequent makeup of fresh amine should be required. It may also be necessary to "purge" ammonia from the reflux water periodically by routing some of the reflux water to the Sour Water Stripping Unit. Although ammonia is usually removed by the circulating water in the Wash Water Column, over a period of time, however, some of the ammonia may carry over into the Amine Absorber and dissolve in the amine. When this ammonia-containing amine reaches the Stripper, the ammonia becomes "trapped" because it is too light (volatile) to leave in the column bottoms and too heavy to leave in the overhead (the acid gas). As a result, the ammonia will become concentrated in the reflux water, to the point where it exceeds its solubility limits and begins to cause plugging problems. If this problem is suspected, simply "bleed" a small amount of the reflux water to the disposal header to purge the ammonia from the system, using the bleed water flow controller in the DCS to control the bleed water rate while monitoring the reflux flow rate to ensure that adequate reflux is maintained to the Stripper. Operating experience will show how often (and how much) the reflux must be purged in this manner to prevent excessive ammonia concentrations for a particular plant.
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SULFUR BLOCK There is full-flow of rich amine through the Rich Amine Filter, and full-flow of lean amine flow through the Lean Amine Filter, the Lean Amine Carbon Filter, and the Lean Amine After-Filter. These four filters will remove solids and organic contaminants from the circulating amine, such as degradation or corrosion products. The filter elements should be changed as soon as the "change" pressure drop is reached, to remove as many solids from the amine as possible. Finely divided solids can cause foaming and thereby limit column capacity. While it is possible to reduce foaming to some extent with anti-foam agents, the presence of such agents may also reduce H2S/CO2 selectivity in the Amine Absorber, so it is preferable that they not be used as an alternative to regular conscientious filter maintenance
7.6.3
Amine Water Balance The water content of the circulating amine is determined by the following factors: 1.
The water content of the feed gas to the Amine Absorber (the overhead from the Wash Water Column).
2.
The water content of the treated gas leaving the Amine Absorber.
3.
The water content of the acid gas leaving the Stripper Reflux Accumulator.
4.
The amount of water makeup to (or water "bleed" from) the amine system.
For given operating pressures, the water content of each gas stream will be determined by the temperature at the top of the respective vessel (Water Wash Column, Amine Absorber, and Stripper Reflux Accumulator, respectively), and will increase as the temperature increases. Since the Amine Absorber inlet gas is at a slightly higher pressure than the outlet treated gas, the inlet gas will normally contain less water than is contained in the outlet gas (if both gas streams are at the same temperature), thus requiring water makeup to maintain the proper water content of the amine. This situation will be reversed if the Amine Absorber overhead temperature is lower than the Wash Water Column overhead temperature, requiring a "bleed" of water to maintain water balance.
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SULFUR BLOCK Since the lean amine to the Amine Absorber is on flow control and withdrawal of the rich amine from the bottom of the Amine Absorber is on level control, a net gain or loss in the amine water balance will be reflected by an increase or decrease, respectively, of the liquid level in the bottom of the Stripper. Observation of this liquid level can thus guide adjustment of water makeup/bleed rate or operating conditions to maintain the desired water concentration of the circulating amine. Since the degree of H2S removal can depend on the amine concentration of the amine, the concentration should be maintained close to the design value (45 wt %) by appropriate maintenance of water concentration. It is usually possible to control the water balance without adding fresh water or "bleeding" water to the Sour Water Stripping Unit by adjusting the operating temperatures in the unit, as discussed in the following paragraphs. Following the steps outlined below will allow controlling the water balance with minimum usage of treated makeup water and minimum impact on the sour water system. A persistently increasing liquid level in the bottom of the Stripper at constant flow rates and conditions for Amine Absorber feed gas and amine indicates a gain in the amine water content. To reduce the water content of the amine, the preferred sequence of gradual adjustments is: A.
Reduce or terminate water makeup to the amine. Makeup water is cold condensate. (1)
Begin "bleeding" water (or increase the "bleed" water rate) from the amine system with the flow controller on the discharge line of the Stripper Reflux Pump. Be careful, however, not to starve the Stripper for reflux by withdrawing too much water. Use the DCS flow indicator for the reflux water to monitor the operation so that adequate reflux is maintained to the Stripper when bleeding water from the amine system.
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SULFUR BLOCK
CAUTION
UNDER NORMAL CONDITIONS, THE REFLUX WATER CONTAINS LITTLE OR NO AMINE BECAUSE OF THE "WASH WATER" TRAYS ABOVE THE SOLVENT FEED TRAY IN THE STRIPPER. HOWEVER, IF THE STRIPPER IS FLOODING OR FOAMING (AS INDICATED BY HIGH OR ERRATIC COLUMN DIFFERENTIAL PRESSURE), THE REFLUX CAN CONTAIN LARGE AMOUNTS OF AMINE. IF THE "BLEED" WATER LINE IS IN USE AT SUCH TIMES, A SIGNIFICANT QUANTITY OF SOLVENT CAN BE LOST TO THE SOUR WATER SYSTEM, AND WILL HAVE TO BE REPLACED WITH FRESH AMINE FROM THE STORAGE TANK. FOR THIS REASON, THE "BLEED" WATER SYSTEM SHOULD BE BLOCKED-IN DURING UPSETS IN THE STRIPPER. (2)
Increase the Amine Absorber overhead temperature by raising the setpoint of the lean solvent temperature controller to increase the lean solvent temperature. This will increase the amount of water leaving in the fuel gas, and it will also reduce the H2S-removal capability of the solvent. An increase in solvent flow rate will probably be needed to maintain the same H2S content in the vent gas, increasing the load on the Stripper and the other process equipment associated with the circulating solvent.
(3)
Increase the acid gas temperature by increasing the temperature setpoint of the reflux temperature controller to raise the outlet temperature from the Stripper Reflux Condenser. Although this will increase the water content of this stream and reduce the water in the solvent, the effect will be small because the quantity of acid gas is small relative to the fuel gas. This adjustment is the least effective and would not normally be considered during routine operations.
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SULFUR BLOCK (4)
B.
7.6.4
Should the solvent inventory be difficult to control due to continuing problems with an excessive amount of water in the solvent, the steam-heated Stripper Reboiler should be checked for tube leaks.
Conversely, a persistently decreasing liquid level in the bottom of the Stripper indicates a loss in the solvent water content. To increase the water content of the solvent, the preferred sequence of gradual adjustments is: 1.
Reduce or terminate the "bleed" water from the Stripper Reflux Accumulator.
2.
Decrease the Amine Absorber overhead temperature by lowering the lean solvent temperature with the lean solvent temperature controller to reduce the amount of water leaving in the fuel gas.
3.
Decrease the acid gas temperature with the aerial cooling from the Stripper Reflux Condenser to reduce the water loss in the stream as much as possible.
4.
Begin water makeup (or increase the makeup water rate) to the solvent system using the make-up flow controller to add condensate to the system..
Amine Loss The loss of MDEA by chemical degradation in the ATU/ARU is expected to be negligible because the upstream Wash Water Column should wash out any acids or other contaminates that enter with the sour fuel gas. Amine degradation can occur, however, under abnormal operating conditions. Amine degradation occurs via reactions with acids which can enter the Amine Absorber when the Wash Water Column is experiencing an upset. Any traces of acid entering the Amine Absorber will react with the MDEA to form a thermally non-regenerable complex (i.e., heat-stable salt). If present in sufficient quantity, this salt can alter the H2S-amine equilibrium and prevent removal of H2S to the desired level in the Amine Absorber overhead. Heat-stable salts also increase the corrosivity of the amine. Amine quality can be restored by treatment with an amount of caustic equivalent to the non-regenerable salt present but, if repeated caustic
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SULFUR BLOCK treatments are necessary due to repeated mal-operation, the potential for salt deposition in the system may rise. The equipment in the ATU/ARU, including the seals of pumps and blowers, should be operated at positive pressure to minimize the potential for oxygen (air) ingress into the amine. Oxygen will react with the amine to produce carboxylic acids that cause the solution to be corrosive. For this same reason, it is important to maintain an inert gas "blanket" on the MDEA storage tank to prevent oxygen contamination of the fresh amine. Amine losses due to entrainment in the treated fuel gas or the acid gas can be minimized by proper process operation (avoidance of column overloading, foaming, etc.) and routine inspection of the vessel internals. Amine losses in the water "bleed" from the Stripper reflux should be negligible if the rectifying trays (the "wash water" trays above the amine feed point) in the Stripper are operating properly (no flooding or foaming, no mechanical damage). The primary source of amine loss will likely be the mechanical losses from pump drips, cleaning of filters, etc. Good housekeeping practices, including prompt replacement or repair of leaking pumps, together with proper collection of amine drips for reuse (via the ATU Drips Tank, A2-FA1580), will minimize the mechanical loss of amine.
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SULFUR BLOCK 7.6.5
Operation at Low Flow Rates The ATU/ARU contains four columns: the Wash Water Column and the Flash Gas Contactor, which contain structured packing; and the Amine Absorber and Stripper, which contain valve trays. In general, the liquid feed rate to packed towers can decrease in proportion with the gas flow rate down to about 50% of design gas flow rate. Below this point, the liquid rate cannot be allowed to drop any further without risking poor column performance due to uneven liquid distribution and wetting of the packing. Trayed towers typically offer somewhat better turndown, allowing the liquid rate to drop to 30-40% of design before "weeping" of the trays begins to significantly affect performance. In the case of the Wash Water Column, decrease the wash water rate in proportion with the gas flow rate down to about 50% of design should maintain adequate performance. (It should be noted, however, that there is really no detrimental effect if the wash water circulation is simply left at the design value at all times. The only drawback is slightly higher power consumption by the pump and aerial cooler.) In the packed Amine Absorber, circulating more amine relative to the gas flow rate should maintain performance. The liquid flow rate should be maintained at a minimum of about 50%.
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SULFUR BLOCK
7.7
Precommissioning Procedures Prior to the initial startup, there are a number of precommissioning activities that are necessary to ensure that the newly constructed plant is ready to be placed in service. The activities outlined below should serve as a guide, but there may be others required as a part of your normal plant procedures.
7.7.1
Preliminary Check-out Check all equipment to ensure that it is properly installed. This will probably require consulting Manufacturer's literature as well as construction drawings.
Issued 30 August 2011
A.
Check and lubricate all equipment, in accordance with the Manufacturer's recommendations.
B.
Check the rotation of the following pumps by "bumping" them: (1) (2)
Wash Water Pump. Rich Amine Pump.
(3) (4) (5) (6) (7)
Stripper Reflux Pump. Lean Amine Pump.
Lean Amine Booster Pump ATU Skim Oil Pump MDEA Transfer Pump
C.
Check the rotation of the fans on the Lean Amine Cooler and the Stripper Reflux Condenser, by operating each fan for a short period.
D.
Check all piping and equipment to be sure that all blinds have been removed and that no valves are vented to atmosphere.
E.
Place the Instrument Air System in service to all instruments and check the action of controllers and control valves.
F.
Check all relief valves to ensure that they are installed in the proper locations, the inlet and outlet block valves (if provided) are open, the bypass valves (if provided) are closed, and the relief valves are set for the correct relieving pressure.
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SULFUR BLOCK 7.7.2
7.7.3
Shutdown System Check-out A.
Physically check all shutdown activating devices to ensure that they activate the ESD system.
B.
Physically check all devices activated by the ESD system to ensure that they operate properly.
C.
Check all relief valves to ensure that they are installed in the proper locations and set for the correct relieving pressures.
D.
The low-low level shutdowns for the pumps in the wash water and amine systems will be tested while washing these systems as described in the following sections.
Leak Testing the Process Piping and Equipment The process piping and equipment in the ATU can be checked for leaks by using a temporary nitrogen “jumper” to pressurize the process side of the equipment and piping to about 0.6-0.7 kg/cm2(g), then checking flanges, etc. for leaks (usually by applying masking tape or "Snoop" to the flanges, and by listening for other leaks). This same procedure can be used to leak test the ATU following maintenance, before restarting the unit. Whenever plant maintenance requires opening one or more of the flanged connections in the ATU it is good practice to leak test the unit before returning it to service. This allows detecting any leaking connections that may have resulted from the maintenance operations before sour fuel gas is reintroduced into the unit. To perform leak testing in the ATU, proceed as follows:
Issued 30 August 2011
A.
Reduce the output from the sour fuel gas hand control in the DCS to 0% to close the Sour Fuel Gas inlet valve.
B.
Confirm that the Wash Water Column is isolated from the wash water circulation loop by confirming that the following valves are all closed: (1)
The bypass valve and downstream block valve at the wash water flow control valve.
(2)
The suction valves at the Wash Water Pumps.
(3)
The drain valve on the suction line to the pumps.
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SULFUR BLOCK (4)
C.
The bypass valve and downstream block valve at the make-up water flow control valve.
Confirm that the Amine Absorber is isolated from the solvent circulation loop by confirming that the following valves are all closed: (1)
The bypass valve and downstream block valve at the lean solvent flow control valve.
(2)
The bypass valve and upstream block valve at the Absorber level control valve.
(3)
The drain valve upstream of the level control valve.
(4)
The block valves in the water makeup line.
(5)
The bypass valve and upstream block valve at the Absorber overhead pressure control valve to the SRUs.
(6)
The bypass valve and upstream block valve at the Absorber overhead pressure control valve to the flare.
D.
Use a temporary "jumper" to connect a nitrogen supply to one of the level bridles on the Wash Water Feed Knock-out Drum and establish a flow of nitrogen into the unit.
E.
Continue adding 0.6-0.7 kg/cm2(g).
nitrogen
until
the
pressure
reaches
Due to the volume inside the ATU, it will take several minutes for the pressure to build up in the unit.
Issued 30 August 2011
F.
Once the desired pressure has been achieved close the valve where the nitrogen "jumper" is connected to stop the flow of nitrogen. Check all of the equipment and piping connections for visible or audible signs of leakage.
G.
Disconnect the nitrogen jumper.
H.
Re-open valves as necessary to restore the wash water and solvent circulation loops that were isolated from the columns in the previous steps.
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SULFUR BLOCK 7.7.4
Washing the Wash Water System The following procedure is intended to remove grease, rust, scale, dirt, and trash from the equipment and piping in the Wash Water system before it is placed in operation. Washing of the system consists of three steps: an initial water flush to remove dirt and trash from the system; an acid wash to remove grease, rust, and scale; and a caustic wash to acclimate the equipment and piping to alkaline pH. Failure to clean the system properly prior to startup can lead to operating problems (heat exchanger fouling, rapid filter plugging, etc.).
WARNING
THIS PROCEDURE REQUIRES WORKING WITH ACIDIC AND ALKALINE CHEMICALS AND SOLUTIONS. EMPLOYEES MUST OBSERVE ALL APPLICABLE SAFETY PROCEDURES AND ENVIRONMENTAL REGULATIONS CONCERNING USAGE OF PERSONAL PROTECTIVE EQUIPMENT, HANDLING OF HAZARDOUS MATERIALS, DISPOSAL OF WASTE STREAMS, ETC.
7.7.4.1
Issued 30 August 2011
Water Flush A.
Place the Wash Water flow controller in the DCS in "manual" and set its output to 100% to fully open the Wash Water flow control valve.
B.
Place the Wash Water Column level controller in the DCS in "manual" and set its output to 0% to fully close the level control valve.
C.
Confirm that the Sour Fuel Gas inlet hand control in the DCS is set to 0% output so that the Sour Fuel Gas inlet valve is fully closed.
D.
Verify that the Wash Water flow control valve is fully open. Open both of its isolation block valves and its bypass valve.
E.
Verify that the Wash Water Column level control valve is fully closed. Close both of its isolation block valves and its bypass valve.
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SULFUR BLOCK F.
Verify that the Sour Fuel Gas inlet valve is fully closed. (This will prevent water from entering the upstream equipment if the Wash Water Column is accidentally over-filled.)
G.
The Wash Water Filters will not be used to filter solids during this time, but the filter vessels and their piping are to be flushed and cleaned. Remove the filter elements, then bolt-up the filters. Open the inlet and outlet block valves on the filters, and open the bypass valve around the filters.
H.
Add water to the top of the Wash Water Column by placing the Make-up Water flow control valve in manual and setting its output to 100% to fully open the make-up water flow control valve. If make-up water is not available from the Sour Water Stripping unit, use a temporary jumper to supply water (cold condensate) to the Wash Water Column.
Issued 30 August 2011
I.
Once there is an adequate level in the column, all the way to the top of its level gauge open the suction valve on a Wash Water Pump and use its drain valve to be sure the pump is flooded with water. Start the pump, then open its discharge valve.
J.
Watch the level in the Wash Water Column while placing the pump in service to be sure the pump does not lose suction while filling the downstream piping and equipment. If the level disappears in the column, shut the pump down until enough water (or condensate) is added to reestablish the level, then restart the pump.
K.
Once circulation is achieved and the level in the Wash Water Column is adequate (about halfway up in the level gauge), discontinue the addition of water (or condensate).
L.
Use the low point drain valves to flush out each section of the system. Leave the drain valves open until the water is clear.
M.
Briefly open the bypass valve on the Wash Water Column level control valve to flush this section of piping to The Sour Water Stripping Unit. Open the upstream block valve, open the Wash Water Column level control valve with the level controller in the
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SULFUR BLOCK DCS, and use the downstream drain valve to flush the control station. Once the flush water clears up, close the Wash Water Column level control valve and the upstream block valve. N.
Circulate the water and blow down the low point drains until all of the drain water is clear. Add more water ( or condensate) as necessary to maintain the level in the Wash Water Column. At some point during the washing procedure, the standby pump should be placed in service while the other pump is shut down. This will ensure cleaning out both pumps and their associated piping.
7.7.4.2
O.
Once the drain water is clear, completely drain the system. Drain the system as quickly as possible, so that the water velocity helps to flush the solids from all parts of the system.
P.
Allow the pump to continue running while the system drains, but watch the pump closely to verify that the low-low level shutdown shuts the pump down below the shutdown setpoint. If the level drops completely out of the gauge glass before the pump shuts down, stop the pump manually and correct the problem with the low-low level shutdown before proceeding further.
Acid Wash A weak (0.1 wt %) citric acid solution is used next to remove grease, rust, and scale from the equipment and piping. The citric acid will chelate with the iron in the rust and scale so that it dissolves in the solution.
Issued 30 August 2011
A.
Reestablish a level in the Wash Water Column.
B.
Once a level is established, start a Wash Water Pump to begin circulating the water.
C.
Add concentrated citric acid to the circulating water to make a 0.1 wt % citric acid solution.
D.
After circulating for about 3 hours, start the other Wash Water Pump and shut down the first one.
E.
Circulate the solution for a total of about 6 hours, blowing down the low point drains occasionally. Add more water (or
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SULFUR BLOCK condensate) if necessary to maintain the level in the Wash Water Column.
7.7.4.3
F.
Briefly open the bypass valve on the Wash Water Column level control valve to flush this section of piping to The Sour Water Stripping Unit. Then open both block valves and use the level controller in the DCS to open the Wash Water Column level control valve briefly and flush the control station. Close the Wash Water Column level control valve and the block valves.
G.
After 6 hours, shut down the pump and completely drain the system. Drain the system as quickly as possible, so that the liquid velocity will help flush any remaining solids from the system.
Alkaline Wash The washing operation is completed by circulating a weak alkaline solution through the system. This will neutralize any citric acid left in the system, and acclimate the system to high pH operation so that no further scale is removed from the equipment and piping when the normal Wash Water (8.0-9.5 pH) is circulated.
Issued 30 August 2011
A.
Reestablish a level in the Wash Water Column.
B.
Once a level is established, start a Wash Water Pump to begin circulating the water.
C.
Add caustic to the circulating water to make a 0.02 wt% solution. This should give a pH in the range of 11-22.
D.
Check the pH of the circulating water. If the pH is less than 11, add more caustic until the pH is 11 or higher.
E.
After circulating for about 1 hour, start the other Wash Water Pump and shut down the first one.
F.
Circulate the solution for a total of about 2 hours, blowing down the low point drains occasionally. Add more water (or condensate) if necessary to maintain the level in the Wash Water Column.
G.
Briefly open the bypass valve on the Wash Water Column level control valve to flush this section of piping to the sour water header. Then open both block valves and use the level
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SULFUR BLOCK controller in the DCS to open the Wash Water Column level control valve briefly and flush the control station. Close the Wash Water Column level control valve and the block valves. H.
7.7.4.4
After 2 hours, shut down the pump and completely drain the system. Drain the system as quickly as possible, so that the liquid velocity will help flush any remaining solids from the system.
Initial Water Fill The Wash Water system should now be clean and ready to place in service. All that remains is to refill the system with water and establish the proper operating conditions.
Issued 30 August 2011
A.
Close the inlet and outlet block valves on the Wash Water Filters (but leave the bypass valve open), then install the proper element(s) in the filters. Leave the block valves closed for now.
B.
Reestablish a level in the Wash Water Column.
C.
Once a level is established, start a Wash Water Pump to begin circulating the water.
D.
Place the Wash Water Filters in service as follows: (1)
Open the vent valves on the top of the filters.
(2)
"Crack" the filter inlet block valves open slightly and allow the filters to fill with water. When the filter is full, close the vent valve.
(3)
Open the filter inlet block valves fully and open the outlet block valves, then close the filter bypass valve.
E.
Place the Wash Water flow controller in the DCS in service and set its setpoint to its normal value. Close the bypass valve on the Wash Water flow control valve.
F.
Confirm that the Wash Water Column level control valve is closed, then open both of its block valves. Place the level controller in the DCS in service and set its setpoint to its normal value.
G.
Establish cooling water flow to the Amine Absorber Overhead Cooler.
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SULFUR BLOCK The Wash Water system is now ready for service. It can remain in this operating mode indefinitely while the rest of the ATU is prepared for startup. Check the system periodically for indications of plugging, etc. (low flow, erratic pump discharge pressure, high filter pressure drop), as solid materials may accumulate at various points in the system over time.
7.7.5
Washing the Amine System The following procedure is intended to remove grease, rust, scale, dirt, and trash from the equipment and piping in the solvent system before it is placed in operation. Washing of the system consists of three steps: an initial water flush to remove dirt and trash from the system; an acid wash and rinse to remove grease, rust, and scale; and a weak amine wash and rinse to acclimate the equipment and piping to alkaline pH. Failure to clean the system properly prior to startup can lead to operating problems (column foaming, poor treating, heat exchanger fouling, rapid filter plugging, etc.).
WARNING
THIS PROCEDURE REQUIRES WORKING WITH ACIDIC AND ALKALINE CHEMICALS AND SOLUTIONS. EMPLOYEES MUST OBSERVE ALL APPLICABLE SAFETY PROCEDURES AND ENVIRONMENTAL REGULATIONS CONCERNING USAGE OF PERSONAL PROTECTIVE EQUIPMENT, HANDLING OF HAZARDOUS MATERIALS, DISPOSAL OF WASTE STREAMS, ETC.
7.7.5.1
Water Flush A.
Issued 30 August 2011
Place the following controllers in the DCS in "manual" with their outputs set as indicated: (1)
Set the output from the lean solvent flow controller to 100% to fully open the lean solvent flow control valve.
(2)
Open the manual block valve upstream of the lean solvent filters.
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SULFUR BLOCK (3)
Set the output from the lean solvent filter bypass flow controller to 100% to fully open the filter bypass flow control valve.
(4)
Set the output from the Amine Absorber level controller to 100% to fully open the Amine Absorber level control valve.
(5)
Set the output from the Rich Amine flow controller to 100% to fully open the rich amine flow control valve.
(6)
Set the output from the amine flow controller to the Flash Gas Contactor to 100% to fully open the flow control valve.
(7)
Set the output from the Stripper Reboiler steam flow controller to 0% to fully close the steam flow control valve.
(8)
Set the output from the Stripper Reflux Accumulator level controller to 0% to fully close the Stripper Reflux Accumulator level control valve.
(9)
Set the output from the bleed water flow controller to 0% to fully close the bleed water flow control valve.
(10) Set the output from the flow controller on the spill-back line to the lean amine cooler to 0% to fully close the spill-back flow control valve. (11) Set the output from the makeup water flow controller to 0% to fully close the makeup water flow control valve. (12) Set the output from the Stripper pressure controller to 0% to fully close the overhead pressure control valve to the SRU. (13) Set the outputs from the two temperature controllers to 0% to fully close both temperature control valves to the DHT Unit. (14) Set the output from the lean solvent flow controller to the LPG Treating Unit to 0% to fully close the lean solvent flow control valve to the LPG Treating Unit. B.
Issued 30 August 2011
Place the other Stripper pressure controller in "automatic" with a setpoint of 0.85 kg/cm2(g). This will open the pressure control
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SULFUR BLOCK valve to the flare if pressure builds in the Stripper during this procedure. C.
D.
Issued 30 August 2011
Verify that the following control valves are fully open. Open both of the isolation block valves and the bypass valve (where applicable) at each control station. (1)
The lean amine flow control.
(2)
The lean amine filter bypass.
(3)
The Amine Absorber level control, (the rich solvent from the Amine Absorber).
(4)
The rich solvent flow control (the rich solvent from the Rich Amine Flash tank)
(5)
The lean solvent to the Flash Gas Contactor
Verify that the following control valves are fully closed. Close both of the isolation block valves and the bypass valve at each control station. (1)
The steam flow control valve to the Stripper Reboiler.
(2)
The Stripper Reflux Accumulator level control valve.
(3)
The bleed water flow control valve from the Stripper reflux.
(4)
The spill-back flow controller to the Lean Amine Cooler.
(5)
The makeup water flow control valve.
(6)
The acid gas pressure control to the SRU.
E.
Verify that the bypass valve on the pressure control valve to the flare is closed. Open both of the isolation block valves at this control station.
F.
The solvent filters will not be used to filter solids during this time, but the filter vessels and their piping are to be flushed and cleaned. Remove the filter elements, then bolt-up the individual filters. Open the inlet and outlet block valves on each filter, and open the bypass valves for the filters.
G.
Verify that the valves in the amine makeup line are closed.
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SULFUR BLOCK H.
Add water (cold condensate) to the Amine Absorber by opening the flow control valve in the make-up water line.
I.
Once there is an adequate level in the Rich Amine Flash Tank, all the way to the top of its level gauge open the suction valve on a Rich Amine Pump and use its drain valve to be sure the pump is flooded with water. Start the pump, then open its discharge valve. Watch the level in the Amine Absorber and the Rich Amine Flash Tank as the pump fills the downstream piping and begins to fill the Stripper. When the level drops to the low-low level shutdown it should shut down the pump. If it does not, stop the pump manually before it loses suction and correct the problem with the low level shutdown before proceeding.
Issued 30 August 2011
J.
Continue filling the Amine Absorber with condensate and pumping the water to the Stripper periodically, until the level in the Stripper is all the way to the top of its level gauge.
K.
Once there is an adequate level in the Stripper, open the suction valve on a Lean Amine Booster Pump and use its drain valve to be sure the pump is flooded with water. Start the pump, then open its discharge valve.
L.
Once the downstream piping and equipment has been filled with water, open the suction valve on a Lean Amine Pump and use its drain valve to be sure the pump is flooded with water. Start the pump, then open its discharge valve
M.
As the pump fills the downstream piping and begins to return water to the Amine Absorber, watch the level in the Stripper to be sure the Lean Amine Booster Pump does not lose suction. If the level disappears in the column, shut both pumps down, add more condensate to the Amine Absorber and pump it to the Stripper to reestablish the level, then restart the Lean Amine Booster Pump and the Lean Amine Pump.
N.
As the level begins to rise in the Amine Absorber, restart the Rich Amine Pump. Watch the levels in both columns, and shut a pump down if necessary to keep from emptying either column.
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SULFUR BLOCK O.
Once the levels in both columns are adequate, discontinue the addition of condensate.
P.
At this point, neither the flow into or the level of the Amine Absorber is being controlled. Both control stations are in "manual" with the valves fully open to flush the piping as much as possible. Depending on the hydraulics of the system, it may be necessary to place either or both of these controls in "automatic" to prevent losing the level in one of the columns. If so, leave the bypass valve on the control station "cracked" so that the bypass piping gets flushed.
Q.
Use the low point drain valves to flush out each section of the system. Leave the drain valves open until the water is clear.
R.
Circulate the water and blow down the low point drains until all of the drain water is clear. Add more condensate as necessary to maintain the levels in the columns. At some point during the washing procedure, the standby Rich Amine Pump, standby Lean Amine Pump, and standby Lean Amine Booster Pump should be placed in service while the other pumps are shut down. This will ensure cleaning out both pumps and their associated piping in each service. At some point in the washing procedure, open the flow control valve in the spill-back line to the Lean Amine Cooler to clean out this section of piping. Then close the control valve again.
Issued 30 August 2011
S.
Once the drain water is clear, shut down the Rich Amine Pump and completely drain the system. Drain the system as quickly as possible, so that the water velocity will help flush the solids from all parts of the system.
T.
Allow the Lean Amine Pump and the Lean Amine Booster Pump to continue running while the system drains, but watch the pumps closely to verify that the Stripper low-low level shutdown shuts the pumps down when the level falls to the shutdown setpoint. If the level drops completely out of the gauge glass before the pumps shut down, stop the pumps manually and correct the problem with the low level shutdown before proceeding further.
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SULFUR BLOCK U.
7.7.5.2
Confirm that the solvent transfer line (for MDEA makeup) has been flushed and is ready for service.
Acid Wash A weak (0.1 wt %) citric acid solution is used next to remove grease, rust, and scale from the equipment and piping. The citric acid will chelate with the iron in the rust and scale so that it dissolves in the solution.
Issued 30 August 2011
A.
Use the make-up water line to re-establish the levels in the Amine Absorber, Rich Amine Flash Tank, and the Stripper as before, and establish circulation of water in the system.
B.
Add concentrated citric acid to the circulating water to make a 0.1 wt % citric acid solution.
C.
Begin steam flow to the Stripper Reboiler and gradually raise the temperature of the circulating solution. For maximum effectiveness, the solution should be 65-95°C throughout the system, so adjust the steam flow accordingly. The fans on the Lean Amine Cooler should not be operating at this time.
D.
It is unlikely that any steam will leave the top of the Stripper during this operation, so the Stripper Reflux Accumulator should remain dry. If a level should develop in this vessel, drain the water from the vessel using a drain valve on one of the Stripper Reflux Pumps.
E.
After circulating for about 3 hours, start the other Rich Amine Pump and shut down the first one. Do the same with the Lean Amine Pumps and the Lean Amine Booster Pumps.
F.
Open the flow control valve in the spill-back line to the Lean Amine Cooler and circulate through this section of piping. Then close the control valve.
G.
Circulate the hot solution for a total of about 6 hours, blowing down the low point drains occasionally. Add more condensate if necessary to maintain the levels in the columns.
H.
After 6 hours, shut off the steam to the Stripper Reboiler, shut down the pumps, and completely drain the system. Drain the system as quickly as possible, so that the liquid velocity will help flush any remaining solids from the system. Amine Treating & Regeneration
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SULFUR BLOCK
Issued 30 August 2011
I.
Use the condensate makeup line to reestablish the levels in the Amine Absorber and the Stripper as before, and establish circulation of water to flush the system.
J.
Switch to the other pumps for a few minutes, then shut down the pumps and completely drain the system.
K.
Once again, use the condensate makeup line to reestablish the levels in the Amine Absorber and the Stripper as before, and establish circulation of water in the system.
L.
Reestablish steam flow to the Stripper Reboiler and gradually raise the temperature in the column.
M.
When the temperature begins to rise in the Stripper overhead line, start a fan on the Stripper Reflux Condenser and place the reflux temperature controller in service with a setpoint of 49°C.
N.
When a level builds in the Stripper Reflux Accumulator, drain it to the closed drain from the drain on one of the pump cases.
O.
Open the downstream block valve at the Stripper Reflux Accumulator level control valve, then use the drain valve to blow steam from the column backwards down the reflux line to remove any debris. Continue until the steam blows clear, then close the drain valve and the block valve.
P.
Continue to circulate water and apply heat in the Stripper Reboiler, until the water drained from the Stripper Reflux Accumulator is clear. During this time, blow down the low point drains occasionally and add more condensate if necessary to maintain the levels in the columns, and switch to the other Rich Amine Pump, Lean Amine Booster Pump, and Lean Amine Pump.
Q.
Once the reflux loop has cleared up (the drain water is clear), shut off the steam to the Stripper Reboiler, shut down the pumps, and completely drain the system. Drain the system as quickly as possible, so that the liquid velocity will help flush any remaining solids from the system.
R.
Check the pH of the water draining from the system. If necessary, repeat Steps K through Q until the pH of the drain water is about the same as the pH of the condensate makeup.
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SULFUR BLOCK 7.7.5.3
Weak Amine Wash The washing operation is completed by circulating a weak amine solution through the system. This will neutralize any citric acid left in the system, and acclimate the system to alkaline pH operation so that no further scale is removed from the equipment and piping when the normal solvent is circulated. A.
Use the condensate makeup line to reestablish the levels in the Amine Absorber and the Stripper as before, and establish circulation of water in the system.
B.
Add enough MDEA to the circulating water to reach a concentration of about 1 wt%.
C.
Begin steam flow to the Stripper Reboiler and gradually raise the temperature in the column.
D.
When the temperature begins to rise in the Stripper overhead line, check that at least one of the fans is running on the Stripper Reflux Condenser.
E.
When a level builds in the Stripper Reflux Accumulator, open the suction valve on one of the Stripper Reflux Pumps and use its drain valve to be sure the pump is flooded with water. Start the pump, open its discharge valve, then open the bypass valve on the Stripper Reflux Accumulator level control valve to pump the water back into the Stripper. Watch the level in the Stripper Reflux Accumulator while pumping it out. Shut the pump down when the vessel is empty, then close the suction and discharge valves on the pump and close the bypass valve on the Stripper Reflux Accumulator level control valve.
F.
Issued 30 August 2011
Continue to circulate the solution and apply heat to the Stripper Reboiler, pumping out the Stripper Reflux Accumulator as required by alternating which pump is used. During this time, blow down the low point drains occasionally and add more condensate if necessary to maintain the levels in the columns, and switch to the other Rich Amine Pump, Lean Amine Booster Pump and Lean Amine Pump.
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SULFUR BLOCK
7.7.5.4
G.
During one of the pumping cycles for the Stripper Reflux Accumulator, flush out the minimum flow spill-back line by opening the manual block valve to allow circulation through this line. Then close the manual block valve.
H.
During another pumping cycle, flush out the bleed water piping by setting the output of the bleed water flow controller to 100% to fully open the bleed water flow control valve, opening its upstream and downstream block valves, and opening its bypass valve. Then close the valves and set the output of the bleed water flow control valve back to 0%.
I.
Take a sample of the circulating solution and run a foam test on it using the procedure in Section 7.10.
J.
Once the solution drained from all the low point drain valves is clear, shut off the steam to the Stripper Reboiler, shut down the pumps, and completely drain the system. Drain the system as quickly as possible, so that the liquid velocity will help flush any remaining solids from the system.
K.
Use the condensate makeup line to reestablish the levels in the Amine Absorber and the Stripper as before, and establish circulation of water to flush the system.
L.
Open the control valve in the spill-back line to the Lean Amine Cooler for a few minutes, then close the control valve.
M.
Switch to the other pumps for a few minutes, then shut down the pumps and completely drain the system.
N.
If the solvent sample taken in Step I was foamy, repeat Steps A through M until the solvent is not foamy.
Initial Solvent Fill The solvent system should now be clean, ready to place in service. All that remains is to fill the system with the proper solvent charge and establish the proper operating conditions. NOTE:
Issued 30 August 2011
This procedure prepares the solvent system for operation in the shortest possible time. However, it does allow the MDEA to come in contact with oxygen that is in the Amine Absorber. If a slightly longer startup schedule can be tolerated, this deficiency can be minimized or eliminated
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SULFUR BLOCK by deferring the procedure in this section until nitrogen has been used to purge the Wash Water Column and Amine Absorber as described in the following section.
Issued 30 August 2011
A.
Close the inlet and outlet block valves (but leave the bypass valves open) on the solvent filters, then install the proper elements and/or carbon in the filters. Leave the block valves closed on each filter for now.
B.
Use the condensate makeup line to reestablish the levels in the Amine Absorber and the Stripper as before, and establish circulation of water in the system.
C.
Add enough MDEA to the circulating water to reach a concentration of about 45 wt%.
D.
Place in service and adjust the level controller on the Amine Absorber to maintain its normal setpoint. Stop the condensate and/or amine makeup when the Stripper level is about 50-60%.
E.
Begin steam flow to the Stripper Reboiler and gradually raise the temperature in the column. Place the steam flow controller in the DCS on "automatic" with its setpoint set to its normal value.
F.
Open the high point vent valve on the Stripper overhead line and allow the steam to purge any air from the vessel. As the pressure builds, the vent valve can be closed.
G.
Monitor the stripper pressure, and adjust the overhead pressure controller if necessary to maintain the stripper pressure at about 0.85 kg/cm2(g) as the system is heated to operating temperatures.
H.
Ensure that the fans are running on the Lean Amine Cooler and the Stripper Condenser.
I.
Place the lean solvent temperature controllers in "automatic" and set their setpoints to their normal values.
J.
When a level builds in the Stripper Reflux Accumulator, open the suction valve on one of the Stripper Reflux Pumps and use its drain valve to be sure the pump is flooded with water. Open the block valves upstream and downstream of the reflux flow
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SULFUR BLOCK control valve, place the reflux flow controller in "automatic" with its setpoint set to its normal value, then start the pump and open its discharge valve. K.
Open the block valves on the Stripper Reflux Accumulator level control valve and place the level controller in the DCS in "automatic" with its setpoint set to its normal value. The Stripper Reflux Accumulator level control valve will now open as needed to pump water back into the Stripper and maintain the desired level in the Stripper Reflux Accumulator.
L.
If the control loops on the solvent have not already been placed in service, do so at this time. Switch the Amine Absorber level controller, and the lean solvent flow controller in the DCS to "automatic" with their setpoints set to their normal values.
M.
Place the Amine flow controller to the Flash Gas Contactor in “automatic” and set its setpoint to its normal value.
N.
Place the level controller for the Rich Amine Flash Tank in service as follows:
O.
Issued 30 August 2011
(1)
Confirm that the level controller in the DCS is in "automatic".
(2)
Confirm that the remote setpoint the level controller is supplying to the rich amine flow controller matches the current local setpoint on the flow controller.
(3)
Switch the rich amine flow controller to "cascade" mode so that the setpoint for the rich amine flow will now be adjusted automatically by the level controller.
(4)
The setpoint of the level controller will be set at the last reading. Adjust the setpoint to its normal value.
Place each of the solvent filters in service as follows: (1)
Open the vent valve on the top of the filter.
(2)
"Crack" the filter inlet block valve open slightly and allow the filter to fill with solvent. When the filter is full, close its vent valve.
(3)
Open the inlet and outlet block valves on the filter.
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SULFUR BLOCK (4)
Slowly close the valve in the bypass line around the filter.
P.
Analyze a sample of the circulating solvent using the procedure in these guidelines to determine the amine concentration. Add more fresh MDEA using the solvent transfer line if needed to bring the concentration up to the design value, 45 wt %.
Q.
Confirm that the bleed water flow controller is in "manual' with its output set at 0% and that the bleed water flow control valve is closed, then open its upstream and downstream block valves.
The solvent system is now ready for service. It can remain in this operating mode indefinitely while the rest of the Sulfur Block is prepared for startup. Check the system periodically for indications of plugging, etc. (low flow, erratic pump discharge pressure, high filter pressure drop), as solid materials may accumulate at various points in the system over time.
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SULFUR BLOCK 7.7.6
Purging the Low Pressure Columns Prior to starting up the using the procedures in Section 7.8 of these guidelines, nitrogen should be used to purge the Wash Water Column and the Amine Absorber. This will displace the air introduced into the columns while washing and filling them earlier. At this point, the following conditions should exist in the ATU: The Wash Water system and perhaps the amine system have been cleaned and loaded with their respective initial fills of water and amine. (The amine system may be waiting on purging of the Amine Absorber before the system is loaded with amine.)
7.7.6.1
Purging the Columns To establish nitrogen flow into the ATU, proceed as follows: A.
Reduce the output from the Sour Fuel Gas hand control in the DCS to 0% to close the Sour Fuel Gas inlet valve.
B.
Confirm that the Wash Water Column is isolated from the wash water circulation loop by confirming that the following valves are all closed:
C.
Issued 30 August 2011
(1)
The bypass valve and downstream block valve at the wash water flow control valve.
(2)
The suction valves at the Wash Water Pumps.
(3)
The drain valve on the suction line to the pumps.
(4)
The bypass valve and downstream block valve at the make-up water flow control valve.
Confirm that the Amine Absorber is isolated from the solvent circulation loop by confirming that the following valves are all closed: (1)
The bypass valve and downstream block valve at the lean solvent flow control valve.
(2)
The bypass valve and upstream block valve at the Absorber level control valve.
(3)
The drain valve upstream of the level control valve.
(4)
The block valves in the water makeup line.
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SULFUR BLOCK (5)
D.
Open all of the vent valves on the PI and PDT taps on the Wash Water Column and the Amine Absorber, and the vent valves at the tops of the columns.
E.
Use a temporary "jumper" to connect a nitrogen supply to one of the level bridles on the Wash Water Feed Knock-out Drum and establish a flow of nitrogen into the unit.
F.
Allow the nitrogen to continue flowing long enough to reduce the oxygen concentration in the equipment and piping to less than 1%. Use a portable oxygen analyzer to determine the oxygen concentration.
G.
Disconnect the nitrogen jumper.
H.
Re-open valves as necessary to restore the wash water and solvent circulation loops that were isolated from the columns in the previous steps.
NOTE:
Issued 30 August 2011
The bypass valve and upstream block valve at the Absorber overhead pressure control valve.
If the initial solvent fill was not loaded into the solvent system earlier to avoid exposing the MDEA to oxygen, this can be accomplished now. Follow the procedure given in the previous section to fill the solvent system with its initial solvent charge.
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SULFUR BLOCK
7.8
Startup Procedures The ATU is now ready to accept sour fuel gas from the complex.
7.8.1
Wash Water and Amine Systems Before routing sour fuel gas into the Wash Water Column and the Amine Absorber, the wash water and amine systems should be operating and ready to accept sour gas. The operating conditions described below should have been established previously at the conclusion of the washing operations but are repeated below to serve as a "checklist" before introducing sour fuel gas to the columns as described in the sections that follow.
Issued 30 August 2011
A.
The H2S analyzer has been calibrated.
B.
The Wash Water system should be charged with its initial fill of water, so that the level in the Wash Water Column is at the normal setpoint for the Wash Water Column level controller.
C.
Wash Water should be circulating to the Wash Water Column at the normal setpoint for the Wash Water flow controller.
D.
The Wash Water Filter should be in service.
E.
The amine system should be charged with its initial fill of amine, with the level control in the DCS controlling the level in the Amine Absorber at its normal setpoint and the level control in the DCS controlling the level in the Rich Amine Flash Tank at its normal setpoint.
F.
The MDEA concentration in the amine should be close to its design value (45 wt %). Add more fresh MDEA if necessary to bring the amine to this strength.
G.
Amine should be circulating through the Stripper, the Lean/Rich Exchanger, and the Lean Amine Cooler to the distributor tray at the top of the Amine Absorber at the normal setpoint for the flow controller.
H.
The fans should be operating on the Lean Amine Cooler, with the temperature controllers on the lean amine controlling at their normal setpoints.
I.
The Rich Amine Filters should be in service.
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SULFUR BLOCK J.
The lean amine filters should be in service, with the bypass flow controller controlling at its normal setpoint.
K.
Steam should be flowing to the Stripper Reboiler at the normal setpoint for the flow control.
L.
The overhead temperature from the Stripper should be above the low temperature alarm point for the temperature indicator.
M.
The fans should be operating on the Stripper Reflux Condenser with the temperature controller on the outlet from the Stripper Reflux Condenser controlling at its normal setpoint or lower.
N.
The Stripper pressure controller to the SRU, should be in "manual" with its output set to 0% so that the pressure control valve is fully closed.
O.
The Stripper pressure controller to the flare should be in "automatic" with a setpoint of 0.85 kg/cm2(g).
P.
The level in the Stripper Reflux Accumulator should be at the normal setpoint for the level control.
Q.
A Stripper Reflux Pump should be operating with the minimum flow lined up to allow reflux to spill back into the Stripper Reflux Accumulator whenever the level valve back to the Stripper is closed.
With these operating conditions established, the ATU is ready to accept the sour fuel gas and begin treating it.
7.8.2
Sour Fuel Gas Flow to the Columns The last step in the startup of the ATU is to bring the sour gas from the rest of the complex into the Wash Water Column and the Amine Absorber. They will then remove the H2S from the gas before sending it to the treated fuel gas system. The H2S removed will be stripped from the amine and sent to the flare initially. Once operation of the amine system stabilizes, this acid gas will be routed to the SRUs. Before introducing sour fuel gas into the columns, confirm that the proper operating conditions have been established for the Wash Water and amine systems.
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SULFUR BLOCK If any of the proper conditions have not been established, do not proceed until correcting the problem(s). Once all of the conditions are satisfied, complete the startup of the as follows: A.
Confirm that the sour fuel gas inlet hand control in the DCS is set to 0% output with the Sour Fuel Gas Inlet Valve closed.
B.
Slowly increase the output from the sour fuel gas inlet hand control to 100%, which will open the Sour Fuel Gas Inlet Valve and admit sour fuel gas to the Wash Water Column.
C.
When the output of the sour fuel gas inlet hand control reaches 100%, the Sour Fuel Gas Inlet Valve should be fully open and the pressure control valve to the flare should be closed to send all of the sour fuel gas into the Wash Water Column. Visually confirm that these valves are properly positioned.
D.
Once the operation of the Stripper has stabilized, route its acid gas, which is presently going to the flare through a pressure valve, to the SRUs as follows: (1)
Confirm that the Stripper pressure controller to the SRUs in the DCS is in "manual" with its output set to 0%.
(2)
Confirm that the setpoint of the Stripper pressure controller to the SRU is tracking its current reading, then place it in "automatic".
(3)
Slowly raise the setpoint of the Stripper pressure controller to the flare to 1.0 kg/cm2(g).
(4)
If, necessary, adjust the setpoint of the Stripper pressure controller to the SRU to its normal setpoint.
The Stripper pressure controller will now take over control of the Stripper pressure by opening the pressure valve to send the acid gas to the Acid Gas Knock-Out Drum in the SRUs. The Stripper pressure controller to the flare will close the acid gas pressure valve and stop the flow of acid gas to the flare. If the SRUs shut down (or some other upset causes the Stripper pressure to rise), the Stripper pressure controller to the flare will act as an over-ride and divert the acid gas to the flare.
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SULFUR BLOCK E.
Issued 30 August 2011
The ATU is now fully on-stream. away from the ATU, be sure that:
Before directing your attention
(1)
All controllers are functioning properly.
(2)
The steam heating systems are in service and the level control on the Reboiler condensate pot is functioning properly.
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SULFUR BLOCK
7.9
Shutdown Procedures The procedures to be used in performing a planned shutdown of the ATU, or the ATU and ARU, will vary depending on the extent and type of work to be performed in and around the units during the downtime period. If maintenance is to be performed on the ATU, there is no need to also shut down the ARU. This greatly simplifies and shortens the shutdown procedure. Section 7.9.1 that follows is an example of such a procedure. If the ARU must also be shut down, then more extensive procedures must be followed to accomplish a satisfactory shutdown and minimize the time required for performance of the desired maintenance work. Section 7.9.2 that follows is an example of a procedure for this circumstance. Section 7.9.3 is a discussion of emergency shutdown situations. A guide to troubleshooting the causes of unplanned shutdowns is presented to assist in quickly identifying and correcting the problem so that the ATU/ARU can be put back on-line in a minimum amount of time. The ATU/ARU is affected directly and indirectly by shutdowns and outages that occur in other systems within the complex. The more important aspects of the effects these other systems can have on the ATU/ARU are discussed in Section 7.9.4. Typical shutdown procedures are outlined and discussed in the sections that follow for the more common cases. Your existing company procedures and common sense operational judgment should be used to modify these procedures as needed to serve the purpose of any given planned shutdown situation.
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SULFUR BLOCK 7.9.1
Planned Shutdown - ATU Any equipment to be opened should be properly blinded and purged with inert gas before admission of air, to avoid exposure to potentially toxic gases or the formation of flammable vapor mixtures. Any equipment containing amine solution that is to be opened or entered should be drained completely, then flushed with condensate or steamed out to avoid the possibility of skin or eye irritation. It is generally preferable to shut down the ATU in a controlled fashion to minimize the impact on the other process units. If time does not allow performing a controlled shutdown, however, the unit can be shut down by simply activating the ESD system (using the manual shutdown switch). This will automatically block the feed into the ATU (sour fuel gas) and divert the feed gas to the flare system. To shut the ATU down in a controlled fashion proceed as follows: A.
Slowly reduce the output from the Sour Fuel Gas hand control in the DCS. As the pressure in the sour fuel gas inlet line begins to increase, the override pressure controller will open the pressure control valve and begin diverting the sour fuel gas to the flare system.
B.
When the output of the Sour Fuel Gas hand control reaches 0%, the pressure control valve should be open and the Sour Fuel Gas inlet valve should be fully closed to send all of the sour fuel gas to the flare system. Visually confirm that these valves are properly positioned. Confirm that the DCS indicates that the Sour Fuel Gas Inlet Valve is closed.
C.
Allow the amine to continue to circulate until the all of the H2S and CO2 have been stripped from the amine. Once the H2S/CO2 content of the "rich" amine leaving the Absorber is essentially the same as the "lean" amine, the ATU can be shut down and isolated from the ARU.
D.
Depending upon the type and extent of the maintenance work to be done, the wash water can continue to circulate while maintenance is being performed on the Amine Absorber. However, if desired, the wash water system can be shut down as follows: (1)
Issued 30 August 2011
Shut down the Wash Water Pump
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SULFUR BLOCK
E.
Issued 30 August 2011
(2)
Place the Wash Water flow controller in the DCS in "manual" and set its output to 0% to fully close the wash water flow control valve.
(3)
Place the Wash Water Column level controller in the DCS in "manual" and set its output to 0% to fully close the level control valve.
(4)
Place the make-up water flow controller in the DCS in "manual" and set its output to 0% to fully close the make-up water flow control valve.
(5)
Verify that the wash water flow control valve is fully closed. Close both of its isolation block valves and its bypass valve.
(6)
Verify that the Wash Water Column level control valve is fully closed. Close both of its isolation block valves and its bypass valve.
(7)
Verify that the make-up water flow control valve is fully closed. Close both of its isolation block valves and its bypass valve.
Once the H2S/CO2 content of the "rich" amine leaving the Absorber is essentially the same as the "lean" amine, the ATU can be shut down as follows: (1)
Shut down the Lean Amine Pump
(2)
Place the lean amine flow controller in the DCS in "manual" and set its output to 0% to fully close the lean amine control valve.
(3)
Place the amine make-up water flow controller in the DCS in "manual" and set its output to 0% to fully close the amine make-up water flow control valve.
(4)
Place the Amine Absorber level controller in the DCS in "manual" and set its output to 100% to fully open the level control valve.
(5)
Allow the amine to drain from the Amine Absorber until the low-low level shutdown is activated. This should close the level control valve. Monitor the level in the Amine Absorber
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SULFUR BLOCK and be prepared to close the level control valve if the low-low level shutdown fails to activate. (6)
Monitor the level in the Rich Amine Flash Tank to ensure that rich amine does not spill over into the hydrocarbon section of the vessel. Be prepared to take action and close the Amine Absorber level control valve if the amine level gets too high in the Rich Amine Flash Tank.
(7)
Drain the remaining amine from the Amine Absorber by opening the manual block valve in the drain line upstream of the level control valve to send the remaining amine to the Solvent Drain System.
(8)
Verify that the Amine Absorber level control valve is fully closed. Close both of its isolation block valves and its bypass valve.
(9)
Verify that the lean amine flow control valve is fully closed. Close both of its isolation block valves and its bypass valve.
(10) Verify that the make-up water flow control valve is fully closed. Close both of its isolation block valves and its bypass valve. (11) Verify that the spill-back flow control valve is fully closed. Close both of its isolation block valves and its bypass valve. F.
Issued 30 August 2011
The ATU is now ready to be isolated and made safe for entry.
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SULFUR BLOCK 7.9.2
Planned Shutdown - ATU and ARU Any equipment to be opened should be properly blinded and purged with inert gas before admission of air, to avoid exposure to potentially toxic gases or the formation of flammable vapor mixtures. Any equipment containing amine solution that is to be opened or entered should be drained completely, then flushed with condensate or steamed out to avoid the possibility of skin or eye irritation. To shut the ATU and ARU down in a controlled fashion proceed as follows: A.
Shutdown and isolate the DHT Unit and the LPG Treating Unit using the operating procedures for those units.
B.
Slowly reduce the output from the Sour Fuel Gas hand control in the DCS. As the pressure in the sour fuel gas inlet line begins to increase, the pressure controller will open the pressure control valve and begin diverting the sour fuel gas to the flare system.
C.
When the output of the Sour Fuel Gas hand control reaches 0%, the pressure control valve should be open and the Sour Fuel Gas inlet valve should be fully closed to send all of the sour fuel gas to the flare system. Visually confirm that these valves are properly positioned. Confirm that the DCS indicates that the Sour Fuel Gas Inlet Valve is closed.
D.
Allow the amine to continue to circulate with steam flowing to the Stripper Reboiler, until the all of the H2S and CO2 have been stripped from the amine. Once the H2S/CO2 content of the "rich" amine is essentially the same as the "lean" amine, the steam can be shut off to the Stripper Reboiler.
E.
Continue to circulate the amine and operate the Lean Amine Cooler and the Stripper Reflux Condenser until the amine is cool.
F.
Depending upon the type and extent of the maintenance work to be done, the wash water can continue to circulate while maintenance is being performed on the Amine Absorber or on the equipment in the ARU. However, if desired, the wash water system can be shut down as follows: (1)
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Shut down the Wash Water Pump
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SULFUR BLOCK
G.
(2)
Place the Wash Water flow controller in the DCS in "manual" and set its output to 0% to fully close the wash water flow control valve.
(3)
Place the Wash Water Column level controller in the DCS in "manual" and set its output to 0% to fully close the level control valve.
(4)
Place the make-up water flow controller in the DCS in "manual" and set its output to 0% to fully close the make-up water flow control valve.
(5)
Verify that the wash water flow control valve is fully closed. Close both of its isolation block valves and its bypass valve.
(6)
Verify that the Wash Water Column level control valve is fully closed. Close both of its isolation block valves and its bypass valve.
(7)
Verify that the make-up water flow control valve is fully closed. Close both of its isolation block valves and its bypass valve.
Once the amine is cool (60°C or less throughout the system), shut down the equipment in the following order: (1) The Rich Amine Pump. (2) The Lean Amine Booster Pump (3) The Lean Amine Pump. (4) The Stripper Reflux Pump. (5)
H.
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The fans on the Lean Amine Cooler and Stripper Reflux Condenser.
The ATU and ARU are now ready to be isolated and made safe for entry.
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SULFUR BLOCK 7.9.3
Emergency Shutdown The ATU ESD system can be initiated by any of the actuating devices outlined in Section 7.5.2.1 of these guidelines. The operator must determine and correct the condition causing the shutdown before the can be restarted. The problems outlined below should be investigated first by the operator in his troubleshooting procedure. S/D Actuation Device Wash Water Feed Knock-Out Drum High-High Level
Amine Absorber Feed Knock-Out Drum High-High Level
Amine Absorber Low-Low Level
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Possible Causes 1. Excessive liquids being received by the Knock-Out Drum. 2. Malfunction of level control system. 3. Level warning transmitters on the Knock-Out Drum are plugged or inoperable. 1. Excessive liquids being received by the Knock-Out Drum. 2. Malfunction of level control system. 3. Level warning transmitters on the Knock-Out Drum are plugged or inoperable. 1. Malfunction of the Lean Amine Pump 2. Malfunction of the Lean Amine Booster Pump 3. Malfunction of the lean amine flow control system 4. Malfunction of the level control system. 5. Manual drain valve left open.
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SULFUR BLOCK 7.9.4
Effects of Shutdowns and Outages in Other Systems The ATU/ARU system is directly affected by a shutdown and/or outage in the LP steam system for the complex. These effects are described below.
7.9.4.1
Steam System Outage The most immediate impact on the ATU/ARU will be the loss of LP steam to the Stripper Reboiler if the steam outage lasts long enough. As the heat input to the reboiler declines, stripping of the acid gas from the amine will decline and the H2S in the treated fuel gas leaving the Amine Absorber will begin to increase. This will cause the Treated Fuel Gas analyzer to close the pressure control valve to the treated fuel gas system to avoid sending off-spec fuel gas into the complex’s fuel gas system. The override pressure control valve will then open and begin routing the sour fuel gas to the flare system.
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SULFUR BLOCK
7.10 Analytical Procedures This Section contains analytical procedures for determining:
7.10.1
1.
The concentrations of total amine in the ATU/ARU solvent (Section 7.10.2).
2.
The concentrations of H2S and CO2 in the ATU/ARU solvent (Sections 7.10.3 and 7.10.4).
3.
The foaming tendency of ATU/ARU solvent (Section 7.10.5).
4.
The H2S content of the ATU/ARU Amine Absorber overhead gas (Sections 7.10.6 and 7.10.7).
General Procedures for Analyzing ATU/ARU Solvent1,2 An amine solution which is to be analyzed should first be inspected visually. If conducted by an experienced person, such an inspection will often yield important clues to the identity of a number of contaminants. For example, a green color in an amine solution usually indicates finely divided iron sulfide in sub-colloidal particle size (<1 micron), whereas a finely divided black suspension indicates the presence of larger (>3 micron) iron sulfide particles. A green or blue solution can indicate the possibility of either copper or nickel, while an amber colored solution may contain suspended or dissolved iron oxide. Iron may complex with the amine an give the solution an amber or dark red color. Thermal degradation of the amine may give the solution a dark red to brown color. Amines sometimes display a red or dark brown color resulting from oxidation, particularly when combined with thermal degradation. An oil slick on the solution or an oil-like odor is indicative of hydrocarbon contamination. The presence of these contaminants, however, must be proven by analysis. The next step in analyzing an amine solution is the determination of the percent amine and the acid gas content (H2S and CO2). Both rich and lean solutions may be analyzed for these constituents, and from the analyses the extent of acid gas loading and efficiency of stripping can be ascertained. Procedures for these analyses are given in Sections 7.10.2 through 7.10.4 that follow.
1 2
The Dow Chemical Company, Gas Conditioning Fact Book, 1962, pp. 310-311. Dow Chemical U.S.A., Gas Treating from Dow, 1987, pp. 8-1-1 – 8-1-2.
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SULFUR BLOCK In addition to the procedure in Section 7.10.2, the amine concentration of the solvent can be determined by performing Kjeldahl and Van Slyke nitrogen analyses. The Kjeldahl determination indicates the total nitrogen content of the solution, including nitrogen from the amine and from amine degradation products. The Van Slyke method, on the other hand, shows amine content, but does not reveal the extent to which the original amine has been degraded or tied up as heat stable salts. The difference between the results obtained through Kjeldahl and Van Slyke analyses usually indicates the degree of amine degradation. As would be expected, little difference is obtained with initial or unused solution. These analyses are not commonly performed in plant laboratories, but are generally left to the chemical solvent supplier. Heat stable salts can also be determined by a total anion assay. The amine solution is passed through an ion exchange column containing ion exchange resin in the hydrogen form. Acid salts are thus broken down and the acids recovered in the column effluent, while the amine is absorbed in the column. The acid in the effluent is determined by potentiometric titration, and from these results plus the original amine concentration the amount of amine in the form of heat stable salts is calculated. Again, this type of analysis is commonly left for the chemical solvent supplier to perform. The foaming characteristics of an amine solution are determined empirically in a simple apparatus consisting of an air (or gas) supply, pressure regulator or gas manometer, graduated glass cylinder, and a gas dispersion tube. The amine solution is poured into the graduated cylinder and air passed through at a constant rate. After five minutes, the height of the foam is recorded, the air flow is interrupted, and the time for the foam to break is determined. The results thus obtained will indicate whether or not evaluation of anti-foam agents is desirable. Section 7.10.5 describes this procedure more completely. A water analysis can be conducted on the amine solution to obtain a material balance and serve as an approximate check on the amine concentration. This is typically determined using the Karl Fischer method of analysis, but most plant laboratories leave this procedure to the chemical solvent supplier. Ordinarily, the above analyses will provide an accurate picture of the condition of the amine plant solution. At times, however, unusual operational difficulties may be encountered in amine sweetening units
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SULFUR BLOCK because of contaminants which are not revealed by the usual analytical methods. When this occurs, infrared spectroscopic analysis may often be utilized to good advantage. Infrared spectroscopy is based on the principle that each molecule or functional group exhibits its own particular absorption characteristics when exposed to infrared light of a definite wavelength. A wide variety of functional groups can be readily detected and identified by infrared techniques. For example, it has been found that degraded or oxidized amine solutions may contain ammonia, formic acid, a di-functional acid, a carbonyl compound yielding a glyoxal dinitrophenylhydrazone derivative, and a high molecular weight material that exhibits the characteristics of a Jones polymer. Also, both mono- and di-substituted amines have been identified. Each component exhibits its own particular effects on corrosion, foaming, and acid gas absorption, effects which can be determined only by the separate evaluation of each contaminant. Once these effects are determined, a knowledge of functional groups present and their relative concentration makes it possible to anticipate which types of contaminants may be causing difficulties. The chemical solvent supplier can usually perform this type of analysis more easily than the plant laboratory. Steps should be taken to ensure that the amine solution samples taken are representative of the circulating solvent. Samples should be taken in glass or plastic containers. Metal containers will cause low results for H2S because sulfides will react with the metal walls of the container. Do not use copper tubing to withdraw the samples; the copper will contaminate the amine solution, and H2S will react with the copper and give low results. Special care should be exercised when taking samples of the rich amine solution to avoid personnel exposure to H2S. Hot, fully loaded amine solution can flash acid gas when released to atmospheric pressure, causing low acid gas loading results in addition to the dispersion of H2S to the surroundings. Take samples of the rich solution from the coolest point in the process (the Amine Absorber outlet, usually), and cool the samples in a stainless steel coil immersed in an ice bath or cold water to prevent flashing. The solution should be allowed to flow to a drain in this fashion for several minutes before taking the sample to be sure that circulating amine is being taken.
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SULFUR BLOCK In the laboratory procedures that follow, several different reagents are used that can be harmful if proper care is not exercised. Acids, bases, and flammable substances are utilized in these procedures, so adherence to proper laboratory safety practices is necessary to ensure the safety of all personnel.
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SULFUR BLOCK 7.10.2
Determination of Amine Concentration in ATU/ARU Solvent The amine concentration in the ATU/ARU solvent can be determined by acid titration of the lean solution. This technique is not specific for free amine, however, as amine present in the solution as an amine-acid salt will also react during the titration. This technique will also give erroneous results if there are other basic materials in the solution, such as caustic or soda ash (sometimes used to "neutralize" heat stable salts). 1.
Reagents:
2.
Procedure:
3.
Distilled or Deionized Water 0.5 N Hydrochloric Acid (HCl) Bromophenol Blue Indicator (3',3'',5',5''-tetrabromophenolsulfonephthalein)
a.
Place about 95 ml of distilled or deionized water in a 250 ml beaker or Erlenmeyer flask.
b.
Add about 5 ml of lean amine solution to the water in the beaker via pipette, recording the actual quantity.
c.
Add 5 drops of Bromophenol Blue indicator to the solution in the beaker and stir well.
d.
Titrate the solution in the beaker with 0.5 N HCl to a faint yellow color. Alternatively, if a pH meter is available, titrate to a pH of 4.5. Record the amount of HCl used in the titration.
Chemical reaction involved: R2HN + HCl
+
R2HNH + Cl
–
where R2HN = CH3-N-(CH2-CH2-OH)2 = MDEA (methyldiethanolamine) As the hydrochloric acid is added to the solution, it reacts with the amine to form a chloride salt. Once all the amine has reacted, the continued addition of acid causes the pH of the solution to drop, until the Bromophenol Blue indicator changes from blue to yellow. Note that HCl reacts with the amine on a 1:1 molar basis.
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SULFUR BLOCK 4.
Calculation of Weight Percent Amine:
ml HCl Normality of Amine 100% Used HCl Solution Weight % Mole Amine Weight 1000 ml / l ml of Sp. Gravity of Sample Amine Sample The molecular weight of MDEA is 119.17, and the specific gravity of the solution at room temperature (20°C) is about 1.059, assuming the solution is about 45 wt% MDEA. The equation can then be simplified to:
ml HCl Normality of Used HCl Solution Weight % Amine 11.253 ml of Sample
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SULFUR BLOCK 7.10.3
Determination of Total Acid Gas Loading in ATU/ARU Solvent The total acid gas (H2S + CO2) loading, relative to the amine concentration, in either the lean or rich ATU/ARU solvent can be determined by base titration of the solution. This procedure does not distinguish between H2S and CO2. However, together with the procedure in Section 7.10.4, the individual concentrations of H2S and CO2 can be determined. 1.
Reagents:
2.
Procedure:
3.
Methanol (CH3OH), Anhydrous 0.5 N Potassium Hydroxide (KOH) Solution in Methanol Thymolphthalein Indicator in Methanol
a.
Place about 125 ml of methanol in a 250 ml beaker or Erlenmeyer flask.
b.
If a pH meter is available, insert the pH meter probe into the methanol in the beaker and adjust the pH of the methanol to 11.2 by titrating the methanol in the beaker with the 0.5 N KOH.
c.
If a pH meter is not available, add 5 drops of Thymolphthalein indicator to the methanol in the beaker. Titrate the solution in the beaker with 0.5 N KOH until the solution turns a faint blue color, indicating a pH of 11.2. The change to faint blue will be sudden, so add the KOH slowly (one drop at a time).
d.
Add about 20 ml of lean amine solution to the methanol in the beaker via pipette, recording the actual quantity. If rich amine solution is being tested, use about 10 ml of solution instead.
e.
Titrate the solution in the beaker with 0.5 N KOH back to a pH of 11.2 (or until the solution again turns a faint blue color when using Thymolphthalein indicator). Record the amount of KOH used in this titration.
Chemical reactions involved: +
–
H2S + KOH
K + HS + H2O
CO2 + KOH
K + HCO3
+
–
As the potassium hydroxide is added to the solution, it reacts with the H2S and CO2 to form potassium hydrosulfide and potassium
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SULFUR BLOCK hydrogen carbonate salts. Once all of the acid gas has reacted, the continued addition of base causes the pH of the solution to rise, until the Thymolphthalein indicator changes from colorless to blue. Note that KOH reacts with H2S and CO2 on a 1:1 molar basis. 4.
Calculation of Acid Gas Loading (molar basis): ml KOH Normality of Used KOH Solution Moles Acid Gas Amine 100% Mole Mole Amine Weight 1000 ml / l ml of S.G. of Wt % Amine Sample Sample in Solvent
Note that "ml KOH used" refers to the amount used in the second titration, step 2.e. The "wt % amine in solvent" can be determined using the procedure in Section 7.10.2. The molecular weight of MDEA is 119.17, and the specific gravity of the solution at room temperature (20°C) is about 1.059, assuming the solution is about 45 wt% MDEA. The equation can then be simplified to:
ml KOH Normality of Used KOH Solution Moles Acid Gas 11.253 ml of Wt % Amine Mole Amine Sample in Solvent 5.
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Special Considerations: a.
Excess moisture in the equipment will give false readings. Water may be used to clean the equipment if the equipment is thoroughly dried prior to use with the anhydrous methanol.
b.
The faint blue titration endpoint using Thymolphthalein indicator is not definite. It may best be determined by comparing the color of the solution against a reference prepared by titrating a second sample of methanol-Thymolphthalein to the same color.
c.
The KOH solution and Thymolphthalein indicator solution should be kept tightly closed to prevent loss of methanol by vaporization. Any vaporization of methanol from the KOH solution will change the normality of the solution.
d.
The Thymolphthalein indicator solution can be prepared by dissolving 5 grams of thymolphthalein in 100 ml of anhydrous methanol.
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SULFUR BLOCK 7.10.4
Determination of H2S and CO2 Loading in ATU/ARU Solvent The H2S loading, relative to the amine concentration, in either the lean or rich ATU/ARU solvent can be determined by titration of the solution with iodine. Since CO2 does not react with iodine, this procedure is specific for H2S. Together with the total acid gas loading determined using the procedure in Section 7.10.3, the individual concentrations of H2S and CO2 can be determined. 1.
Reagents:
Distilled or Deionized Water Concentrated Hydrochloric Acid (HCl) or Sulfuric Acid (H2SO4) Standard Starch Solution - 1% 0.1 N Iodine Solution (I2) 0.1 N Sodium Thiosulfate Solution (Na2S2O3)
2.
Issued 30 August 2011
Procedure: a.
Measure about 25 ml of chilled iodine solution and place it in a 250 ml beaker or Erlenmeyer flask. Record the amount of iodine solution used.
b.
Carefully add about 25 ml of concentrated acid to the beaker.
c.
Add about 5 ml of standard starch solution to the beaker, then re-chill the beaker in an ice batch for 2-3 minutes.
d.
Slowly add 10-20 ml of lean amine solution to the solution in the beaker via pipette, recording the actual quantity. If rich amine solution is being tested, use 1-2 ml of solution instead.
e.
Use about 25 ml of distilled or deionized water to rinse the inside of the beaker, then swirl the contents gently to mix the solution without splashing it.
f.
Titrate the excess iodine in the sample with the sodium thiosulfate solution until the blue color disappears. The end point is a pale yellow or clear color. The approach of the endpoint is usually indicated by a milky brown tint at the top of the liquid surface. As the endpoint nears, slow the rate of titration and use a small amount of distilled or deionized water to wash the flask. Record the amount of sodium thiosulfate solution used in this titration.
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SULFUR BLOCK g.
3.
Check the pH of the titrated solution with pH paper to be sure the solution is acidic. If the solution is not acidic, repeat the procedure but use more acid in step 2.b.
Chemical reactions involved: H2S + I2
S + 2 HI
I2 + Na2S2O3
2 S + NaI + NaIO3
When the solvent is added to the iodine solution, the H2S in the solvent reacts with the iodine to form hydrogen iodide and elemental sulfur. The solution contains an excess of iodine to ensure that all of the H2S reacts. The iodine solution is chilled prior to adding the solvent to eliminate or minimize the evolution of H2S gas. Note that H2S reacts with iodine on a 1:1 molar basis. When the sodium thiosulfate solution is added to the solution, it reacts with the remaining iodine to form sodium iodide and sodium iodate, along with more elemental sulfur. (It is this elemental sulfur that may cause the titrated solution to appear pale yellow.) Once the last bit of iodine is consumed, the starch solution loses its characteristic blue color. The amount of H2S in the solvent sample is then calculated from the difference between the total iodine and the iodine that reacts with the sodium thiosulfate. Note that sodium thiosulfate reacts with iodine on a 1:1 molar basis. The purpose of the concentrated acid is to neutralize the amine so that it will release the H2S (a weaker acid) so it can react with the iodine. If the titrated solution is not acidic in step 2.g, then the amine was not fully neutralized and the H2S determination will not be correct. 4.
Calculation of H2S Loading (Molar Basis): g - moles ml I2 Normality of 1 liter 1 g - mole I2 Used used I2 Solution 1000 ml 2 g - equivalent
g - moles ml Normality of 1 liter 1 g - mole Na2S2O3 Na2S2O3 Na2S2O3 used Solution 1000 ml 2 g - equivalent Used
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SULFUR BLOCK g - moles g - moles Amine I2 Used Na2S2O3 Used Moles H2S Mole 100 % Mole Amine Weight ml of S.G. of Wt % Amine Sample Sample in Solvent
The "wt % amine in solvent" can be determined using the procedure in Section 7.10.2. The molecular weight of MDEA is 119.17, and the specific gravity of the solution at room temperature (20°C) is about 1.059, assuming the solution is about 45 wt% MDEA. Using these values and substituting the first and second equations into the third, these equations can be simplified to: Normality Normality of ml I2 of I ml Na2S2O3 Na S O 2 2 3 2 Used Used Solution Solution Moles H2S 5.626 Mole Amine ml of Wt % Amine Sample in Solvent
5.
Calculation of CO2 Loading (Molar Basis): Using the total acid gas loading determined with the procedure in Section 7.10.3, the CO2 loading of the solvent is determined by difference:
Moles CO2 Moles Acid Gas Moles H2S Mole Amine Mole Amine Mole Amine 6.
Other Common Units: The loadings calculated above can be easily converted to other units commonly used within the industry:
Grains H2S Moles H2S Wt % Amine S.G. of 166.7 Gallon Solvent Mole Amine in Sample Sample Moles H2S Wt % Amine Wt % H2S 0.2858 in Sample Mole Amine
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SULFUR BLOCK SCF CO2 Moles CO2 Wt % Amine S.G. of 0.2653 Gallon Solvent Mole Amine in Sample Sample
Moles CO2 Wt % Amine Wt % CO2 0.3693 in Sample Mole Amine Note that these conversions are specifically for MDEA. amines require different conversion factors.
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SULFUR BLOCK 7.10.5
Determination of Foaming Tendency of ATU/ARU Solvent The procedure described in this section is an empirical method for measuring the foaming tendency of aqueous amine solvents, universally accepted within the industry. 1.
Principle: Air is bubbled through a solvent sample at a fixed rate for five minutes, at which time the foam height is measured. The air flow is stopped and the time for the foam to disappear is measured. The foam height and "break" time are indicative of how high the foaming tendency of the solvent is.
2.
Equipment:
3.
Procedure:
4.
1000 ml Graduated Cylinder Aquarium Air Pump (or laboratory air supply) with Bubble Stone Stop Watch (or regular watch with a second hand)
a.
Pour about 200 ml of the sample solution into the graduated cylinder and insert the bubble stone into the bottom of the cylinder.
b.
Record the level of sample in the cylinder (in ml).
c.
Start the air pump or air supply to agitate the sample with oil-free air at 4 liters per minute (0.2 Nm3/H).
d.
After five minutes, record the height of the foam in the cylinder (in ml). Then turn off the air supply and measure the time in seconds for the foam to "break". For consistency, foam "break" is defined as the first clear "fish eye" in the surface of the liquid in the cylinder.
Calculation: Foam Height = Height of Foam - Initial Height of Sample (in ml)
5.
Interpretation: Considerable experience with this test has shown that if the foam height exceeds 200 ml or the "break" time exceeds 5 seconds, the plant may be experiencing a foaming problem. The higher the foam
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SULFUR BLOCK height and/or the longer it takes to "break", the more severe the problem. 6.
Issued 30 August 2011
Other Considerations: a.
A nitrogen cylinder with the pressure regulated to about 0.35 kg/cm2(g), equipped with a flow rotameter, may be used instead of air. Be sure to keep the tubing and fittings oil-free.
b.
This procedure can be used to evaluate the effects of anti-foam agents on the solvent. However, care must be exercised in cleaning the equipment between tests since a very small quantity of residual anti-foam agent will affect the test.
c.
Foaming is sometimes caused by contaminants in the solvent that can be removed by activated carbon treatment. The effect of activated carbon filtration can be evaluated by running foam tests on treated and untreated samples. The sample is treated by mixing it with a quantity of carbon (12-20 mesh) to remove the contaminant, then filtering the mixture through Whatman No. 41 filter paper.
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SULFUR BLOCK 7.10.6
H2S Conc. in Amine Absorber Ovhd by the Tutweiler Method The overhead gas from the Amine Absorber Overhead Knock-out Drum can be sampled from the sample connection near the sample line for the H2S analyzer. 1.
Using a 500 ml Tutweiler apparatus, sample and titrate the treated gas leaving the Amine Absorber Overhead Knock-out Drum as outlined in Section 7.10.1 of these guidelines.
2.
Chemical reaction involved: H2S + I2
2 HI + S
The hydrogen sulfide (H2S) is converted to small particles of elemental sulfur by the iodine during the shaking. Good shaking is required to get good contact between the hydrogen sulfide in the gas and the iodine in the liquid. When all of the hydrogen sulfide is converted, the excess iodine causes the characteristic blue color in the presence of starch. This is a universal test for starch. (Iodine causes a blue color when it contacts starchy foods, such as potato for example.) 5.
Calculation of Mole (or Volume) percent H2S (dry basis): ml Iodine Normality of 273 T 760 Mole % H2S Iodine Solution (11.85) Solution Used 289 P - V.P.
Where
T P
= =
sample temperature, °C atmospheric pressure at particular location, mm Hg
V.P
=
vapor pressure of water at sample temperature, mm Hg
The Normality of the standard iodine solution will be 0.1 N. The last three factors (which correct the actual H2S content to compensate for expansion due to temperature, pressure, and water content) can be combined and calculated as a function of temperature only. This has been done for the 500-ml gas sample and is included as the Tutweiler Factor Chart in Section 7.10.3 of these guidelines (Chart 2). Therefore, the equation above can be simplified to:
ml Iodine Normality Factor from PPM H2S 10,000 Solution of Iodine Tutweiler Used Solution Factor Chart
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SULFUR BLOCK 7.10.7
H2S Conc. in Amine Absorber Ovhd Using Gas Detector Tubes As an alternative to the traditional wet-chemistry method described in the preceding Section 7.10.6 for determining the concentration of H2S in the Amine Absorber overhead gas, gas detector tubes can be used to quickly and easily make this determination. Although the discussion that follows specifically addresses using gas detector tubes manufactured by Drägerwerk AG of West Germany, there may be suitable detector tubes available from other manufacturers. Dräger tubes can be purchased from most safety equipment supply companies. The following Dräger tubes can be used with this procedure:
7.10.7.1
H2S 5/b
Dräger Cat. No. CH 298 01
H2S 100/a
Dräger Cat. No. CH 291 01
Operating Principles
Dräger tubes and other gas detector tubes measure gas concentrations by using a sample pump to draw a specific volume of the gas to be sampled into a glass tube containing a suitable reagent. The gaseous compound of interest chemically reacts with the reagent to produce a color change. The length of the "stain" line is a direct function of the concentration of the compound in the sample gas. Some detector tubes are calibrated with measured lines to allow reading the concentration directly on the tube. Others, such as the two listed above, have reference marks on the tube that can be multiplied by a factor to compute the concentration. Dräger tubes are designed to be used with a Dräger Model 31 gas detector pump. This is a hand-operated bellows pump that will draw a 100 cc sample volume for each pump stroke. Some tubes are designed for a single sample stroke, while others may use 5, 10, or even 20 strokes. In some cases, a tube may be used for measuring different concentration ranges by using a different number of strokes. a.
Dräger Cat. No. CH 298 01, H2S 5/b This tube will measure H2S concentrations in the range of 50 PPM to 600 PPM when one sample stroke is used. If desired, the range can be reduced to 5 PPM to 60 PPM by using 10 sample strokes. Each tube contains a substrate of a white lead compound. When exposed to H2S, the lead
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SULFUR BLOCK compound is converted to brown lead sulfide. The H2S concentration in PPM can be read directly from the marks on the tube according to the length of the brown stain when using 10 sample strokes. If only one sample stroke is used, the tube reading is multiplied by 10 to give the PPM of H2S. This lead sulfide reaction is not affected by any of the other compounds normally found in the overhead gas from the ATU/ARU Amine Absorber. b.
Dräger Cat. No. CH 291 01, H2S 100/a This tube will measure H2S concentrations in the range of 100 PPM to 2,000 PPM when one sample stroke is used. Each tube contains a substrate of a white lead compound. When exposed to H2S, the lead compound is converted to brown lead sulfide. The H2S concentration in PPM can be read directly from the marks on the tube according to the length of the brown stain. This lead sulfide reaction is not affected by any of the other compounds normally found in the overhead gas from the ATU/ARU Amine Absorber.
7.10.7.2
Sampling the Amine Absorber Overhead Gas
The overhead gas from the Amine Absorber Overhead Knock-out Drum can be sampled from the sample connection near the sample line for the H2/H2S analyzer.
Issued 30 August 2011
a.
Before beginning, check the Dräger pump for leaks by inserting an unopened tube into the pump and stroking the pump. Confirm that the bellows does not re-expand. If it does, either the pump or its seal around the tube is leaking, and the test results will not be accurate.
b.
Attach a short piece of rubber tubing to the process sample valve.
c.
Break off the tips at each end of a Dräger tube and insert it into the sample pump (with the arrow on the side of the tube pointing toward the pump).
d.
Purge the rubber tubing by venting gas to the atmosphere for a few seconds. Pinch the rubber tubing closed at the end, close the gas sample valve, slip the end of the rubber tubing onto the end of the Dräger tube, and reopen the sample valve. Amine Treating & Regeneration
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7.10.7.3
e.
Stroke the sample pump one time (be sure to compress the bellows until reaching the stops) and allow the pump to draw the gas sample into the detector tube. The sample stroke is complete when the metal chain on the bellows is taut.
f.
Close the sample valve and remove the rubber tubing from the end of the Dräger tube and from the sample valve.
g.
Read the length of the brown stain using the marks on the tube and record the reading.
Calculations
Mole (or Volume) PPM H2S (wet basis):
1013 Stain Tube PPM H2S Length Factor Baro. Pres., mbar The last factor corrects the measurement for pressure effects when samples are taken at elevations above sea level. Note that the average barometric pressure at the compex is 14.7 PSIA = 1013 mbar. The "Tube Factor" depends on the type of Dräger tube used and the number of sample strokes:
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Dräger Tube
Catalog No.
Sample Strokes
Tube Factor
H2S 5/b H2S 5/b H2S 100/a
CH 298 01 CH 298 01 CH 291 01
1 10 1
10 1 1
Amine Treating & Regeneration
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Table of Contents 8. SOUR WATER STRIPPING ......................................................................................... 8-1 8.1 PURPOSE OF SYSTEM ....................................................................................... 8-1 8.2 SAFETY ................................................................................................................. 8-1 8.3 PROCESS DESCRIPTION.................................................................................... 8-2 8.3.1 General ........................................................................................................... 8-2 8.3.2 Sour Water Collection..................................................................................... 8-2 8.3.3 Sour Water Stripping ...................................................................................... 8-3 8.4 EQUIPMENT DESCRIPTION ................................................................................ 8-5 8.4.1 Sour Water Stripper, A2-DA1520 ................................................................... 8-5 8.4.2 Sour Water Stripper Packing and Internals, A2-DB1520 ................................ 8-5 8.4.3 Stripper Trays, A2-DB1521 ............................................................................ 8-5 8.4.4 SWS Cross Exchanger, A2-EA1520 .............................................................. 8-5 8.4.5 Sour Water Stripper Reboiler, A2-EA1521 ..................................................... 8-6 8.4.6 SWS Quench Water Cooler, A2-EC1520 ....................................................... 8-6 8.4.7 SWS Bottoms Cooler, A2-EC1521 ................................................................. 8-6 8.4.8 Sour Water Flash Drum, A2-FA1520.............................................................. 8-6 8.4.9 SWS Skim Oil Sump, A2-FA1522 .................................................................. 8-7 8.4.10 SWS Skim Oil Pump Sump, A2-FA1523A/B .................................................. 8-7 8.4.11 Sour Water Tank, A2-FB1520 ........................................................................ 8-7 8.4.12 Sour Water Filter, A2-FD1520A/B .................................................................. 8-7 8.4.13 Sour Water Transfer Pump, A2-GA1520A/B .................................................. 8-7 8.4.14 SWS Feed Pump, A2-GA1521A/B ................................................................. 8-8 8.4.15 SWS Quench Water Pump, A2-GA1522A/B .................................................. 8-8 8.4.16 SWS Bottoms Pump, A2-GA1523A/B ............................................................ 8-8 8.4.17 SWS Skim Oil Pump, A2-GA1524A/B ............................................................ 8-8 8.5 INSTRUMENTATION AND CONTROL SYSTEMS ............................................... 8-9 8.5.1 SWS Shutdowns and Alarms ......................................................................... 8-9 8.6 PROCESS PRINCIPLES AND OPERATING TECHNIQUES ............................. 8-11 8.6.1 SWS Stripper Operation ............................................................................... 8-11 8.6.2 Quench Water Circulation ............................................................................ 8-12 8.6.3 pH Control .................................................................................................... 8-13 8.7 PRECOMMISSIONING PROCEDURES ............................................................. 8-14 8.7.1 Preliminary Check-out .................................................................................. 8-14 8.7.2 Washing the Sour Water System ................................................................. 8-15 8.8 STARTUP PROCEDURES.................................................................................. 8-19 8.8.1 Initial Startup of the SWS ............................................................................. 8-19 8.8.1.1 Initial Water Fill ...................................................................................... 8-19
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SULFUR BLOCK 8.8.1.2 Exporting Treated Water ....................................................................... 8-21 8.8.2 Normal Startup of the SWS .......................................................................... 8-23 8.8.2.1 Initial Water Fill ...................................................................................... 8-23 8.8.2.2 Exporting Treated Water ....................................................................... 8-26 8.9 SHUTDOWN PROCEDURES ............................................................................. 8-29 8.9.1 Planned Shutdown ....................................................................................... 8-29 8.9.2 Effects of Shutdowns and Outages in Other Systems.................................. 8-31 8.9.2.1 Steam System Outage .......................................................................... 8-31
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8. SOUR WATER STRIPPING 8.1
Purpose of System The purpose of the Sour Water Stripping (SWS) system is to remove H2S and ammonia (NH3) from various sour water streams produced in the Sulfur Block and elsewhere in the aromatics complex. The resulting treated water (containing less than 20 PPMW of H2S and less than 20 PPMW of NH3) is returned to the aromatics complex for reuse elsewhere, while the SWS off-gas (NH3, H2S, and water vapor) is routed to the Sulfur Recovery Units (SRUs).
8.2
Safety
WARNING
ALL PIPING AND VESSELS INCLUDED IN THIS UNIT EITHER CONTAIN OR HAVE THE POTENTIAL FOR CONTAINING HAZARDOUS GASES THAT MAY CAUSE SERIOUS INJURY OR DEATH. THE TWO GASES THAT ARE MOST COMMON AND HAZARDOUS IN A TOXIC WAY ARE HYDROGEN SULFIDE AND AMMONIA. CLOSE ATTENTION SHOULD BE PAID TO THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES AS TO THE NATURE AND ABILITY OF THESE GASES TO CONTAMINATE OTHER ELEMENTS IN THIS UNIT. AN EMPLOYEE'S KNOWLEDGE OF THE HAZARDOUS CHEMICALS AND COMPOUNDS WITH WHICH HE WILL BE WORKING IS ONE OF THE MOST BASIC PREREQUISITES FOR HIS OWN SAFETY, THE SAFETY OF OTHERS, AND THE PROTECTION OF EQUIPMENT. ALL EMPLOYEES SHOULD REVIEW THE "GENERAL SAFETY" SECTION OCCASIONALLY TO REFRESH THEIR MEMORIES. NEW EMPLOYEES SHOULD STUDY IT UNTIL THE INFORMATION IS THOROUGHLY UNDERSTOOD. PEOPLE WHO HAVE NOT BEEN PROPERLY TRAINED SHOULD NOT BE ALLOWED TO OPERATE OR WORK IN AND AROUND THIS PLANT.
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8.3
Process Description
8.3.1
General The Systems Diagram, Material Balance and Process Flow Diagram, Dwg. Nos. 507000-7000-01, and 507000-7000-05 through -06, are contained in the "Process Flow Diagrams" Section of the Basic Engineering Package. Please refer to these drawings to follow this description of the process. The Sour Water Stripping Unit (SWS) receives sour water streams containing ammonia (NH3) and hydrogen sulfide (H2S) from other units in the No. 2 Aromatics Complex. These sour water streams are combined with sour water produced in the Sulfur Block (predominately Sour Water from the ATU and excess quench water from the SWS) and steam stripped to remove essentially all of the NH3 and H2S from the water. The resulting treated water (containing less than 20 PPMW of H2S and less than 20 PPMW of NH3) is returned to the complex for reuse elsewhere, while the SWS off-gas (NH3, H2S, and water vapor) is routed to the SRUs.
8.3.2
Sour Water Collection Sour water from other units within the complex is combined with the sour water streams generated within the Sulfur Block and flows to the Sour Water Flash Drum, A2-FA1520, at 54°C [129°F]. This vessel is operated at low pressure (1.05 kg/cm2(g) [15 PSIG]) to maximize the vaporization and removal of any light hydrocarbons that may be entrained or dissolved in the sour water. Any flash gases are directed to the flare header for disposal. The flash drum is large enough to provide 30 minutes or more of residence time for the sour water. This allows time for any heavy hydrocarbons entrained in the water to separate as a second liquid phase that spills over the internal weir at the inlet end of the drum, collecting in the SWS Skim Oil Sump, A2-FA1522. The SWS Skim Oil, A2-GA1524A/B, sends the collected hydrocarbon to the Condensate Feed Tank on start/stop level control. After removal of any liquid hydrocarbon, the heavier water phase passes under the internal weir at the outlet end of the drum to be pumped to the Sour Water Tank, A2-FB1520, by the Sour Water Transfer Pump, A2-GA1520A/B, on level control. This tank is large enough to provide 3-4 days of residence time to allow "working off " an accumulation of sour
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SULFUR BLOCK water after an outage. The tank also provides time for mixing which minimizes Sour Water Stripper feed composition fluctuations due to the many sources of sour water in the complex.
8.3.3
Sour Water Stripping After residing in the Sour Water Tank for several days, the sour water is pumped by the SWS Feed Pump, A2-GA1521A/B, on flow control through the tube side of the SWS Cross Exchanger, A2-EA1520. The sour water is preheated to 100°C [211°F] by cooling the treated water before flowing to the Sour Water Stripper, A2-DA1520, to enter the column above the first valve tray, tray #2. Traditional reflux systems do not work well for strippers in this service because of the highly corrosion nature of concentrated NH3-H2S aqueous systems. For this reason, these systems often employ a direct-contact condenser instead, using a circulating stream of quench water to provide cooling for the upper section of the column. The Sour Water Stripper contains an upper section of packing to provide contact between the quench water and the stripped gases, and a lower section of valve trays to provide contact between the sour water and the stripping steam. The stripping section of the column contains 30 valve trays and one chimney draw tray. As the sour water flows down the column, the NH3 and H2S are stripped from the water by countercurrent contact with stripping steam rising upward. This stripping steam is generated in the Sour Water Stripper Reboiler, A2-EA1521, using LP (3.5 kg/cm2(g) [50 PSIG]) steam on flow control as the heat input. The stripping steam strips the NH3 and H2S from the water and carries it upward to the quench section of the column. The SWS Bottoms Pump, A2-GA1523A/B, pumps the treated water from the bottom of the column through the shell side of the SWS Cross Exchanger, cooling the treated water from 123°C [254°F] to 54°C [130°F] by countercurrent heat exchange with the cool sour water. The SWS Bottoms Cooler, A2-EC1521, provides final cooling to 49°C [120°F] before the treated water is returned to the complex for reuse elsewhere. The quench section of the column contains a packed bed and a chimney draw tray. As the stripping steam rises upward in this section, it is countercurrently contacted by the circulating quench water, cooling the off-gas to 85°C [185°F] as it condenses most of the steam. The chimney tray below the packed bed that collects the quench water leaving the
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SULFUR BLOCK bottom of the bed has overflow pipes to direct the condensed water onto the valve tray (tray #2) below. The quench water collecting on the chimney tray is pumped by the SWS Quench Water Pump, A2-GA1522A/B, to the SWS Quench Water Cooler, A2-EC1520, to cool the water from 99°C [210°F] to 66°C [150°F] to reject the heat removed from the stripping steam in the quench section of the column. The cooling rate is adjusted as necessary to control the column overhead temperature at 85°C [185°F]. This allows the NH3 and H2S stripped from the water to leave the column at 0.85 kg/cm2(g) [12 PSIG]and flow to the SRUs.
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8.4
Equipment Description
8.4.1
Sour Water Stripper, A2-DA1520 The upper section of the Sour Water Stripper contains a chimney draw tray and a single bed of random packing to provide good contact between the circulating quench water and the stripped gases. The stripping section of the column contains 30 valve trays and one chimney draw tray. The valve trays provide good contact between the sour water and the reboiler vapors to strip H2S and NH3 from the water. A chimney tray is located below the bottom valve tray to gather all of the column liquids to feed the Sour Water Stripper Reboiler. The column section located below this chimney tray serves to separate the outlet steam and treated water from the reboiler.
8.4.2
Sour Water Stripper Packing and Internals, A2-DB1520 This bed of random packing provides good contact between the stripped gases entering below it and the quench fed above it inside the Sour Water Stripper. The packing has a bed limiter above it and rests on a bed support. The quench water is distributed over the packing by a distributor tray. The packing is aluminum; the other internals are 316L S.S.
8.4.3
Stripper Trays, A2-DB1521 These 1-pass valve trays provide good contact between the sour water fed above them and the reboiler vapors fed below them inside the Sour Water Stripper. The tray decks for Trays #1 and #2 are 316L S.S. with 316 S.S. valves and bolting. For the remaining trays, the tray decks are carbon steel and the valves are fabricated from 316 S.S. to resist corrosion and to prevent "sticking" to the tray decks. The bottom valve tray has a seal pan for its downcomer to maintain a liquid seal and prevent gas from blowing up the downcomer. The chimney tray gathers the tower liquids to feed the reboiler. The outlet from the reboiler reenters the column below the chimney tray, with the vapor produced by the reboiler flowing upward through the chimneys in order to reach the valve trays above.
8.4.4
SWS Cross Exchanger, A2-EA1520 This shell and tube exchanger conserves energy by providing heat exchange between the stripped sour water and the sour water feed
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SULFUR BLOCK stream, so that the hot water leaving the Sour Water Stripper can preheat the sour water before it feeds the Sour Water Stripper. This cross exchange saves reboiler duty by preheating the sour water, and reduces the load on the SWS Bottoms Cooler by partially cooling the hot stripped water.
8.4.5
Sour Water Stripper Reboiler, A2-EA1521 The Sour Water Stripper Reboiler is a fixed tubesheet shell and tube heat exchanger. The exchanger is arranged as once-through vertical thermosiphon reboiler, mounted on the side of the Sour Water Stripper. The static head of the water above the inlet nozzle on the lower channel provides the driving force to circulate the water through the tubes. LP steam on the shell of the exchanger heats the water inside the tubes, partially vaporizing it to create stripping steam to remove the H2S and the NH3 from the sour water flowing down the Sour Water Stripper.
8.4.6
SWS Quench Water Cooler, A2-EC1520 This forced-draft aerial exchanger is used to cool a circulating stream of quench water which enters above the packed section of the Sour Water Stripper and provides cooling for the upper section of the column. Fans are used to circulate air across the finned tubes to remove heat from the circulating quench water.
8.4.7
SWS Bottoms Cooler, A2-EC1521 This forced-draft aerial exchanger provides the final cooling of the stripped sour water stream leaving the bottom of the Sour Water Stripper. Fans are used to circulate air across the finned tubes to remove heat from the water.
8.4.8
Sour Water Flash Drum, A2-FA1520 This horizontal vessel allows for the removal of hydrocarbons that may be carried out of the various upstream processes with the sour water. The sour water enters the vessel through a slotted, vertical distributor. Any hydrocarbon that may be carried with the sour water from the upstream processes will accumulate in the center section of this vessel. When a sufficient amount of hydrocarbon has accumulated, the hydrocarbon will overflow the partition and flow into the hydrocarbon section. Lighter hydrocarbons are disengaged from the sour water and routed to the battery limits on pressure control. Hydrocarbon-free sour water then passes under another partition, at the opposite end of the vessel, and into
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SULFUR BLOCK the sour water outlet section, where the sour water is pumped to the Sour Water Tank.
8.4.9
SWS Skim Oil Sump, A2-FA1522 This horizontal vessel is located in a below-ground concrete vault. It collects the heavy hydrocarbons from the Sour Water Flash Tank. The collected hydrocarbon liquid is pumped back to the Condensate Feed Tank on stop/start level control.
8.4.10
SWS Skim Oil Pump Sump, A2-FA1523A/B These vertical vessels house the SWS Skim Oil pumps. Hydrocarbon liquids from the SWS Skim Oil Sump flow into this vessel and are pumped out by the SWS Skim Oil Pump.
8.4.11
Sour Water Tank, A2-FB1520 The Sour Water Tank is an above-ground vertical cylindrical tank with a floating roof. This tank is large enough to provide 2-3 days of residence time to allow "working off " an accumulation of sour water after an outage. It has two level transmitters to indicate the sour water level, with a low level alarm to alert the operators of a low level, and a low level shutdown which will shut down the SWS Feed Pump if the level in the tank drops too low. The tank also has multiple connections to the closed drain system which can be used to route hydrocarbons to the closed drain if a layer of hydrocarbon should form in the tank.
8.4.12
Sour Water Filter, A2-FD1520A/B These full-flow filters are designed to remove solid particles 5 microns and larger from the sour water, which will help prevent fouling of the downstream heat exchangers.
8.4.13
Sour Water Transfer Pump, A2-GA1520A/B These centrifugal pumps are used to transfer the sour water from the Sour Water Flash Drum to the Sour Water Tank. Each pump is designed for the total duty; the other pump is a 100% spare. These pumps are equipped with tandem seals to reduce the likelihood of releasing H2S to the surroundings.
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SULFUR BLOCK 8.4.14
SWS Feed Pump, A2-GA1521A/B These centrifugal pumps are used to send the sour water from the Sour Water Tank to the Sour Water Stripper. Each pump is designed for the total duty; the other pump is a 100% spare. These pumps are equipped with tandem seals to reduce the likelihood of releasing H2S to the surroundings.
8.4.15
SWS Quench Water Pump, A2-GA1522A/B These centrifugal pumps are used to circulate quench water to cool the stripped gases in the upper section of the Sour Water Stripper. Each pump is designed for the total duty; the other pump is a 100% spare. These pumps are equipped with tandem seals to reduce the likelihood of releasing H2S to the surroundings.
8.4.16
SWS Bottoms Pump, A2-GA1523A/B These centrifugal pumps are used to send the stripped water from the Sour Water Stripping Unit to the battery limits for use elsewhere in the complex. Each pump is designed for the total duty; the other pump is a 100% spare.
8.4.17
SWS Skim Oil Pump, A2-GA1524A/B These vertical sump-type pump is mounted in the SWS Skim Oil Pump Sump to transfer the recovered hydrocarbons back to the Condensate Feed Tank.
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8.5
Instrumentation and Control Systems
8.5.1
SWS Shutdowns and Alarms There are several interlocks of significance in the SWS Unit that either generate an alarm or shut down an individual piece of equipment. These devices/interlocks and their effects are described in this section. a.
Sour Water Flash Drum Low-Low Level, A2-LT15209A/B/C The Sour Water Transfer Pump (A2-GA1520A/B) could be damaged if the pump loses suction because the level in the Sour Water Flash Drum drops too low. This device will protect the pump by stopping it before this can occur. The setpoint is 530 mm above the bottom of the vessel. Note that there are three independent transmitters and 2oo3 voting logic is used for the shutdown.
b.
Sour Water Tank Low-Low Level, A2-LT15218A/B/C The SWS Feed Pump (A2-GA1521A/B) could be damaged if the pump loses suction because the level in the Sour Water Tank drops too low. This device will protect the pump by stopping it before this can occur. The setpoint is 300 mm above the bottom of the vessel. Note that there are three independent transmitters and 2oo3 voting logic is used for the shutdown.
c.
SWS Bottoms Cooler Fan High Vibration, A2-WSH15234 Each fan on the SWS Bottoms Cooler (A2-EC1521) is provided with its own vibration switch. If the vibration sensed by the switch exceeds the preset level, the switch will trip to stop the associated fan and activate an alarm in the DCS.
d.
Sour Water Stripper Low-Low Level, A2-LT15247A/B/C The SWS Bottoms Pump (A2-GA1523A/B) could be damaged if the pump loses suction because the level in the Sour Water Stripper drops too low. This device will protect the pump by stopping it before this can occur. The setpoint is 300 mm above the bottom seam of the column. Note that there are three independent transmitters and 2oo3 voting logic is used for the shutdown.
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SULFUR BLOCK e.
SWS Quench Water Cooler Fan High Vibration, A2-WSH15263 Each fan on the SWS Quench Water Cooler (A2-EC1520) is provided with its own vibration switch. If the vibration sensed by the switch exceeds the preset level, the switch will trip to stop the associated fan and activate an alarm in the DCS.
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8.6
Process Principles and Operating Techniques
8.6.1
SWS Stripper Operation The stripped water must be comparatively free of H2S and NH3 to assure attainment of the treated water specification. These contaminates are removed from the sour water in the Sour Water Stripper by stripping them out with steam. The stripping steam is produced by vaporizing some of the water in the in the Sour Water Stripper Reboiler, using LP (3.5-4.2 kg/cm2(g)) steam for the heat input. The steam rate to the reboiler (and, hence, the stripping rate) is controlled by the steam flow controller. Adjust this steam rate as needed to keep the H2S and NH3 in the treated water low, i.e., less than 20 PPMW of H2S and less than 20 PPMW of NH3.
CAUTION THE DESIGN STRIPPING STEAM RATE SHOWN ON THE PROCESS FLOW DIAGRAM SHOULD BE CLOSE TO OPTIMUM. ALTHOUGH IT MAY BE POSSIBLE TO REDUCE THIS SOMEWHAT WITHOUT GOING OUT OF COMPLIANCE, REDUCING THE STRIPPING STEAM RATE SIGNIFICANTLY CAN CAUSE THE CONCENTRATION OF H2S AND AMMONIA IN THE TREATED WATER TO EXCEED THE ALLOWABLE CONCENTRATION IN THE TREATED WATER SPECIFICATION. IF IT IS NECESSARY TO OPTIMIZE THE STEAM TO THE SOUR WATER STRIPPER REBOILER, REDUCE THE STEAM BY SMALL INCREMENTS AND CHECK THE CONCENTRATION OF AMMONIA AND H2S AFTER EACH CHANGE. DO NOT REDUCE THE STEAM FURTHER IF EITHER CONCENTRATION BEGINS TO RISE SIGNIFICANTLY.
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SULFUR BLOCK 8.6.2
Quench Water Circulation The operating conditions shown on the Process Flow Diagram for this system (in terms of the quench water circulation rate and water temperature) should generally be maintained. The quench water circulation rate is controlled by the quench water flow controller in the DCS, while the temperature is controlled by a temperature controller on the Sour Water Stripper overhead gas line adjusting the speed of one of the fans on the SWS Quench Water Cooler, A2-EC1520. In general, decreasing the quench water circulation rate will increase the quench water temperature upstream of the cooler (which increases the corrosion rate) and may increase the Sour Water Stripper Overhead temperature if the cooler cannot cool the quench water sufficiently. Care should be taken when reducing the quench water circulation rate to ensure that the corrosion rate in the quench water circulation loop does not become excessive. As the feed rate to the SWS Stripper decreases, the quench water circulation rate can decrease in proportion with the feed flow rate down to about 50% of design flow rate. Below this point, the quench water rate cannot be allowed to drop any further without risking poor performance in the packed section of the SWS Stripper due to uneven liquid distribution and wetting of the packing. At lower feed rates (below 50%) simply setting the quench water flow rate to the column at about 50% of design should maintain adequate performance. (It should be noted, however, that there is really no detrimental effect if the quench water circulation is simply left at the design value at all times. The only drawback is slightly higher power consumption by the pump and aerial cooler.) Increasing the quench water temperature will increase the overhead gas temperature and water content which increases the load on the downstream SRUs (since water is a product of the Claus reaction, higher water content in the SWS feed gas can negatively impact the recovery of in the SRUs). However, decreasing the quench water temperature (and correspondingly the overhead gas temperature) may lead operating issues including salt deposition and plugging in the downstream piping and equipment. Ammonium salts can form in the gas stream leaving the top of the Sour Water Stripper if the gas temperature falls below about 70°C. These salts can plug the mist eliminator in the top of the Sour Water Stripper as well as the downstream piping and equipment. In addition, decreasing the overhead gas temperature below about 82°C may prevent
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SULFUR BLOCK the ammonia from leaving the top of the column. Instead it may become “trapped” in the column where it will concentrate, or it may leave in the stripped water causing the treated water to exceed the specification for ammonia. The flow rate and temperatures shown on the Process Flow Diagram are usually a good compromise between minimizing corrosion, minimizing the load on the downstream SRUs, and minimizing operating issues within the SWS unit.
8.6.3
pH Control High pH water tends to hold H2S in solution and aids in releasing ammonia from sour water. Conversely, low pH water tends to hold ammonia in solution and improves the stripping of H2S. By injecting a small amount of caustic near the tower bottom, ammonia stripping in the bottom of the Sour Water Stripper can be improved while the H2S is still stripped in the upper part of the tower. Injection points for caustic addition have been supplied in the lower section of the Sour Water Stripper. In the event that the stripped water cannot meet the low ammonia specification, caustic can be added to the tower to increase the pH and improve the ammonia stripping in the tower. If caustic is added, injection control is critical to limit the pH of the stripped water to about 8.0.
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8.7
Precommissioning Procedures Prior to the initial startup, there are a number of precommissioning activities that are necessary to ensure that the newly constructed plant is ready to be placed in service. The activities outlined below should serve as a guide, but there may be others required as a part of your normal plant procedures.
8.7.1
Preliminary Check-out Check all equipment to ensure that it is properly installed. This will probably require consulting Manufacturer's literature as well as construction drawings.
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A.
Check and lubricate all equipment, in accordance with the Manufacturer's recommendations.
B.
Check the rotation of the following pumps by "bumping" them: (1) (2)
Sour Water Transfer Pump. SWS Feed Pump
(3) (4) (5)
SWS Quench Water Pump SWS Bottoms Pump
SWS Skim Oil Pump
C.
Check the rotation of the fans on the SWS Quench Water Cooler and the SWS Bottoms Cooler, by operating each fan for a short period.
D.
Check all piping and equipment to be sure that all blinds have been removed and that no valves are vented to atmosphere.
E.
Place the Instrument Air System in service to all instruments and check the action of controllers and control valves.
F.
Check all relief valves to ensure that they are installed in the proper locations, the inlet and outlet block valves (if provided) are open, the bypass valves (if provided) are closed, and the relief valves are set for the correct relieving pressure.
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SULFUR BLOCK 8.7.2
Washing the Sour Water System The following procedure is intended to remove grease, rust, scale, dirt, and trash from the equipment and piping in the Sour Water Stripping system before it is placed in operation. Failure to clean the system properly prior to startup can lead to operating problems (heat exchanger fouling, rapid filter plugging, etc.). A.
Issued 30 August 2011
Place the following controllers in the DCS in "manual" with their outputs set as indicated: (1)
Set the output from the Sour Water Flash Drum level controller to 0% to fully close the Sour Water Flash Drum level control valve.
(2)
Set the output from the SWS Inlet flow controller to 100% to fully open the SWS Inlet flow control valve.
(3)
Set the output from the SWS level controller to 100% to fully open the level control valve.
(4)
Set the output from the Quench Water flow controller to 100% to fully open the Quench Water flow control valve.
(5)
Set the output from the SWS Stripper Reboiler steam flow controller to 0% to fully close the steam flow control valve.
(6)
Set the output from the SWS pressure controller to 0% to fully close the overhead pressure control valve to the SRUs.
B.
Place the other SWS pressure controller in "automatic" with a setpoint of 0.85 kg/cm2(g). This will open the pressure control valve to the flare if pressure builds in the Sour Water Stripper during this procedure.
C.
Verify that the bypass valve on the pressure control valve to the flare is closed. Open both of the isolation block valves at this control station.
D.
Place the H.P. Nitrogen supply to the Stripper overhead line in service and open the manual block valve. This will prevent a vacuum from forming in the Sour Water Stripper during this procedure.
E.
Set the Treated Water hand control in the DCS is to 0% output to fully open the automated valve in the Startup/Re-run line to the Sour
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SULFUR BLOCK Water Tank, and fully close the automated valve in the Treated Water line downstream of the SWS Bottoms Cooler. Visually confirm that these valves are properly positioned. F.
Verify that the manual block valve at the inlet to the Sour Water Tank is open.
G.
Verify that the manual block valve in the fill line for the Quench Water Loop is closed.
H.
Verify that the SWS Inlet flow control valve is fully open. Open both of its isolation block valves and its bypass valve.
I.
Verify that the SWS level control valve is fully open. Open both of its isolation block valves and its bypass valve.
J.
Verify that the Quench Water flow control valve is fully open. Open both of its isolation block valves and its bypass valve.
K.
Verify that the Sour Water Flash Drum level control valve is fully closed. (This will prevent water from entering the upstream equipment if the Sour Water Tank is accidentally over-filled.)
L.
The Sour Water Filters will not be used to filter solids during this time, but the filter vessels and their piping are to be flushed and cleaned. Remove the filter elements, then bolt-up the filters. Open the inlet and outlet block valves on the filters, and open the bypass valve around the filters.
M.
Use a temporary “jumper” to add cold condensate to the Sour Water Tank.
N.
Once there is an adequate level in the tank, open the suction valve on a SWS Feed Pump and use its drain valve to be sure the pump is flooded with water. Start the pump, then open its discharge valve. Watch the level in the Sour Water Tank as the pump fills the downstream piping and begins to fill the Sour Water Stripper. When the level drops to the low-low level shutdown it should shut down the pump. If it does not, stop the pump manually before it loses suction and correct the problem with the low level shutdown before proceeding.
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SULFUR BLOCK O.
Continue filling the Sour Water Tank with condensate and pumping the water to the Sour Water Stripper periodically, until the level in the Stripper is all the way to the top of its level gauge.
P.
Once there is an adequate level in the Stripper, open the suction valve on a SWS Bottoms Pump and use its drain valve to be sure the pump is flooded with water. Start the pump, then open its discharge valve. Watch the level in the Sour Water Stripper as the pump fills the downstream piping and begins to circulate back to the Sour Water Tank. When the level drops to the low-low level shutdown it should shut down the pump. If it does not, stop the pump manually before it loses suction and correct the problem with the low level shutdown before proceeding.
Q.
Once circulation is achieved and the level in the Sour Water Stripper is adequate (about halfway up in the level gauge), discontinue the addition of condensate.
R.
Circulate the water and blow down the low point drains until all of the drain water is clear. Add more condensate as necessary to maintain the level in the Sour Water Stripper. At some point during the washing procedure, the standby SWS Feed Pump and the standby SWS Bottoms pump should be placed in service while the other pumps are shut down. This will ensure cleaning out all pumps and their associated piping.
S.
When the drain water begins to clear, open the manual block valve in the Quench Water fill line, open the suction valve on a SWS Quench Water Pump and use its drain valve to be sure the pump is flooded with water. Start the pump, then open its discharge valve. Watch the level in the Sour Water Stripper as the pump fills the quench water circulation loop. Add additional condensate to the Sour Water Tank if necessary and pump the water to the Sour Water Stripper.
T.
Issued 30 August 2011
Once circulation is achieved in the Quench Water loop and the level in the Sour Water Stripper is adequate (about halfway up in the level gauge), discontinue the addition of condensate and close the manual block valve in the Quench Water fill line.
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SULFUR BLOCK U.
Circulate the water in the Quench Water loop and blow down the low point drains until all of the drain water is clear. At some point during the washing procedure, the standby SWS Quench Water Pump should be placed in service while the other pump is shut down. This will ensure cleaning out both pumps and their associated piping.
V.
Issued 30 August 2011
Once the drain water is clear in the main circulation loop and Quench Water loop, shutdown the pumps and completely drain the system. Drain the system as quickly as possible, so that the water velocity helps to flush the solids from all parts of the system.
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SULFUR BLOCK
8.8
Startup Procedures
8.8.1
Initial Startup of the SWS The SWS system should now be clean, ready to place in service. All that remains is to fill the system with water and establish the proper operating conditions.
8.8.1.1
Initial Water Fill A.
Issued 30 August 2011
Close the bypass valves around the following control stations: (1)
SWS Inlet flow control
(2)
SWS level control
(3)
Quench water flow control
B.
Close the inlet and outlet block valves (but leave the bypass valves open) on the Sour Water Filters, then install the proper elements in the filters. Leave the block valves closed on each filter for now.
C.
Use a temporary “jumper” to add cold condensate to the Sour Water Tank and reestablish the level in the Sour Water Stripper as before.
D.
Establish circulation of water in the system (including the Quench Water loop) using the procedures in Section 8.7.2.
E.
Start a fan on the SWS Bottoms Cooler and place the bottoms temperature controller in service with a setpoint of 60°C.
F.
Begin steam flow to the Sour Water Stripper Reboiler and gradually raise the temperature in the column. Place the steam flow controller in the DCS on "automatic" with its setpoint set to its normal value.
G.
Open the high point vent valve on the Stripper overhead line and allow the steam to purge any air from the vessel. As the pressure builds, the vent valve can be closed.
H.
When the temperature begins to rise in the SWS overhead line, start a fan on the SWS Quench Water Cooler and place the overhead temperature controller in service with a setpoint of 85°C.
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SULFUR BLOCK I.
Monitor the stripper pressure, and adjust the overhead pressure controller if necessary to maintain the stripper pressure at about 0.85 kg/cm2(g) as the system is heated to operating temperatures.
J.
Ensure that the fans are running on the SWS Bottoms Cooler and the SWS Quench Water Cooler.
K.
If the control loops for the Sour Water Stripper have not already been placed in service, do so at this time. Switch the SWS level controller, and the SWS Inlet flow controller in the DCS to "automatic" with their setpoints set to their normal values.
L.
Place the Quench Water flow controller in “automatic” and set its setpoint to its normal value.
M.
Place each of the sour water filters in service as follows: (1)
Open the vent valve on the top of the filter.
(2)
"Crack" the filter inlet block valve open slightly and allow the filter to fill with sour water. When the filter is full, close its vent valve.
(3)
Open the inlet and outlet block valves on the filter.
(4)
Slowly close the valve in the bypass line around the filter.
Note:
N.
At this point the sour water system is ready for service. It can remain in this operating mode indefinitely while the rest of the Complex is prepared for startup. Check the system periodically for indications of plugging, etc. (low flow, erratic pump discharge pressure, high filter pressure drop), as solid materials may accumulate at various points in the system over time.
Once there is an adequate level of Sour Water in the Sour Water Flash Drum, open the suction valve on a Sour Water Transfer Pump and use its drain valve to be sure the pump is flooded with water. Start the pump, then open its discharge valve. Watch the level in the Sour Flash Drum as the pump fills the downstream piping and begins to flow to the Sour Water Tank. When the level drops to the low-low level shutdown it should
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SULFUR BLOCK shut down the pump. If it does not, stop the pump manually before it loses suction and correct the problem with the low level shutdown before proceeding. O.
Place the Sour Water Flash Tank level controller in the DCS in “automatic” and set its setpoint to its normal value.
P.
Once a level of hydrocarbons has built up in the hydrocarbon side of the Sour Water Flash Tank, the oil level controller can also be placed “automatic” and its setpoint set to its normal value.
The sour water will continue to circulate from the Sour Water Tank to the Sour Water Stripper and back to the tank. The Sour Water Tank is large enough to provide 3-4 days of residence time for the produced sour water in the event the Sour Water System is not ready to export treated water at this time. 8.8.1.2
Exporting Treated Water Stripped sour water may not be routed to the complex’s treated water system until the temperature in the bottom of the Sour Water Stripper is high enough to satisfy the Stripped Water Low Temperature Interlock. This interlock disables the hand control in the DCS to prevent the operator from routing the stripped water to the complex’s treated water system until the temperature in the bottom of the Sour Water Stripper is sufficiently high. Once the temperature in the bottom of the Sour Water Stripper is high enough to satisfy the low-temperature interlock, and the complex is producing a sufficient quantity of sour water for processing:
Issued 30 August 2011
A.
Slowly increase the output from the Treated Water hand control to 100%, which will open the automated valve in the Treated Water line downstream of the SWS Bottoms Cooler and close the automated valve in the Startup/Re-run line to the Sour Water Tank.
B.
When the output of the Treated Water hand control reaches 100%, the automated valve in the Treated Water line downstream of the SWS Bottoms Cooler should be fully open and the automated valve in the Startup/Re-run line fully closed to send all of the treated water to the complex’s treated water Tailgas Cleanup
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SULFUR BLOCK system. Visually confirm that these valves are properly positioned. C.
Once the operation of the Sour Water Stripper has stabilized, route its acid gas, which is presently going to the flare through a pressure valve to the SRUs as follows: (1)
Confirm that the Sour Water Stripper pressure controller to the SRUs in the DCS is in "manual" with its output set to 0%.
(2)
Confirm that the setpoint of the Sour Water Stripper pressure controller to the SRUs is tracking its current reading, then place it in "automatic".
(3)
Slowly raise the setpoint of the Sour Water Stripper pressure controller to the flare to 1.0 kg/cm2(g).
(4)
If, necessary, adjust the setpoint of the Sour Water Stripper pressure controller to the SRU to its normal setpoint.
The Sour Water Stripper pressure controller will now take over control of the Sour Water Stripper pressure by opening the pressure valve to send the acid gas to the SWS Gas Knock-Out Drums in the SRUs. The Sour Water Stripper pressure controller to the flare will close the acid gas pressure valve and stop the flow of acid gas to the flare. If the SRUs shut down (or some other upset causes the Sour Water Stripper pressure to rise), the Sour Water Stripper pressure controller to the flare will act as an over-ride and divert the acid gas to the flare. D.
Issued 30 August 2011
The SWS is now fully on-stream. Before directing your attention away from the SWS, be sure that: (1)
All controllers are functioning properly.
(2)
The steam heating systems are in service and the level control on the Reboiler condensate pot is functioning properly.
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SULFUR BLOCK 8.8.2
Normal Startup of the SWS The procedure for startup of the SWS after it has been shut down will be very similar to the procedure for the initial startup, except that condensate will not be used to fill the system. For ease of reference, the steps to be performed are written in this Section to serve as a "check list" that can be easily followed on subsequent startups. Refer to the previous Sections for the reasons and details pertaining to the different steps performed. Prior to commencing SWS startup, check for the completion of all maintenance work (connecting lines, removing blinds, etc.) if such work was performed.
8.8.2.1
Issued 30 August 2011
Initial Water Fill A.
Confirm that the Treated Water hand control in the DCS is to 0% output to fully open the automated valve in the Startup/Rerun line to the Sour Water Tank, and fully close the automated valve in the Treated Water line downstream of the SWS Bottoms Cooler. Visually confirm that these valves are properly positioned.
B.
Place the following controllers in the DCS in "manual" with their outputs set as indicated: (1)
Set the output from the SWS Inlet flow controller to 100% to fully open the SWS Inlet flow control valve.
(2)
Set the output from the SWS level controller to 100% to fully open the level control valve.
(3)
Set the output from the Quench Water flow controller to 100% to fully open the Quench Water flow control valve.
C.
Confirm that the output from the SWS Stripper Reboiler steam flow controller is set to 0% and the steam flow control valve is fully closed.
D.
Confirm that the output from the SWS pressure controller is set to 0% and the overhead pressure control valve to the SRUs is fully closed.
E.
Place the other SWS pressure controller in "automatic" with a setpoint of 0.85 kg/cm2(g). This will open the pressure control
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SULFUR BLOCK valve to the flare if pressure builds in the Sour Water Stripper during this procedure. F.
Verify that the bypass valve on the pressure control valve to the flare is closed and that both of the isolation block valves are open.
G.
If not already in service, place the H.P. Nitrogen supply to the Stripper overhead line in service and open the manual block valve.
H.
Verify that the manual block valve at the inlet to the Sour Water Tank is open.
I.
Verify that the manual block valve in the fill line for the Quench Water loop is closed.
J.
If the Sour Water Flash Drum is already in service and sending sour water to the Sour Water Tank, proceed to Step L. Otherwise, if the Sour Water Flash Drum is not in service, open the isolation valves upstream of the flash drum to allow sour water to enter the flash drum from the upstream Units.
K.
Once there is an adequate level of sour water in the Sour Water Flash Drum, open the suction valve on a Sour Water Transfer Pump and use its drain valve to be sure the pump is flooded with water. Start the pump, then open its discharge valve. Watch the level in the Sour Flash Drum as the pump fills the downstream piping and begins to send sour water to the Sour Water Tank. When the level drops to the low-low level shutdown it should shut down the pump. If it does not, stop the pump manually before it loses suction and correct the problem with the low level shutdown before proceeding.
L.
Confirm that there is an adequate level of sour water in the Sour Water Tank, then open the suction valve on a SWS Feed Pump and use its drain valve to be sure the pump is flooded with water. Start the pump, then open its discharge valve. Watch the level in the Sour Water Tank as the pump fills the downstream piping and begins to fill the Sour Water Stripper.
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SULFUR BLOCK M.
Continue pumping sour water to the Sour Water Stripper until the level in the Stripper is all the way to the top of its level gauge.
N.
When there is an adequate level in the Stripper, open the suction valve on a SWS Bottoms Pump and use its drain valve to be sure the pump is flooded with water. Start the pump, then open its discharge valve to begin circulating sour water back to the Sour Water Tank.
O.
Once circulation is achieved and the level in the Sour Water Stripper is adequate, open the manual block valve in the Quench Water fill line, open the suction valve on a SWS Quench Water Pump and use its drain valve to be sure the pump is flooded with water. Start the pump, then open its discharge valve. Watch the level in the Sour Water Stripper as the pump fills the quench water circulation loop. If the level in the stripper falls below the low level alarm point, stop the SWS Quench Water Pump and pump additional sour water to the Stripper from the Sour Water Tank to bring the level in the level back up before restarting the SWS Quench Water Pump.
Issued 30 August 2011
P.
Once circulation is achieved in the Quench Water loop and the level in the Sour Water Stripper is adequate (about halfway up in the level gauge), close the manual block valve in the Quench Water fill line.
Q.
Start a fan on the SWS Bottoms Cooler and place the bottoms temperature controller in service with a setpoint of 60°C.
R.
Begin steam flow to the Sour Water Stripper Reboiler and gradually raise the temperature in the column. Place the steam flow controller in the DCS on "automatic" with its setpoint set to its normal value.
S.
When the temperature begins to rise in the SWS overhead line, start a fan on the SWS Quench Water Cooler and place the overhead temperature controller in service with a setpoint of 85°C.
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SULFUR BLOCK T.
Monitor the stripper pressure, and adjust the overhead pressure controller if necessary to maintain the stripper pressure at about 0.85 kg/cm2(g) as the system is heated to operating temperatures.
U.
Ensure that the fans are running on the SWS Bottoms Cooler and the SWS Quench Water Cooler.
V.
If the control loops for the Sour Water Stripper have not already been placed in service, do so at this time. Switch the Sour Water Flash Tank level controllers, the SWS level controller, and the SWS Inlet flow controller in the DCS to "automatic" with their setpoints set to their normal values.
W.
Place the Quench Water flow controller in “automatic” and set its setpoint to its normal value.
The sour water will continue to circulate from the Sour Water Tank to the Sour Water Stripper and back to the tank. The Sour Water Tank is large enough to provide 3-4 days of residence time for the produced sour water in the event the Sour Water System is not ready to export treated water at this time. 8.8.2.2
Exporting Treated Water Stripped sour water may not be routed to the complex’s treated water system until the temperature in the bottom of the Sour Water Stripper is high enough to satisfy the Stripped Water Low Temperature Interlock. This interlock disables the hand control in the DCS to prevent the operator from routing the stripped water to the complex’s treated water system until the temperature in the bottom of the Sour Water Stripper is sufficiently high. Once the temperature in the bottom of the Sour Water Stripper is high enough to satisfy the low-temperature interlock, and the complex is producing a sufficient quantity of sour water for processing: A.
Issued 30 August 2011
Slowly increase the output from the Treated Water hand control to 100%, which will open the automated valve in the Treated Water line downstream of the SWS Bottoms Cooler and close the automated valve in the Startup/Re-run line to the Sour Water Tank.
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SULFUR BLOCK B.
When the output of the Treated Water hand control reaches 100%, the automated valve in the Treated Water line downstream of the SWS Bottoms Cooler should be fully open and the automated valve in the Startup/Re-run line fully closed to send all of the treated water to the complex’s treated water system. Visually confirm that these valves are properly positioned.
C.
Once the operation of the Sour Water Stripper has stabilized, route its acid gas, which is presently going to the flare through a pressure valve to the SRUs as follows: (1)
Confirm that the Sour Water Stripper pressure controller to the SRUs in the DCS is in "manual" with its output set to 0%.
(2)
Confirm that the setpoint of the Sour Water Stripper pressure controller to the SRUs is tracking its current reading, then place it in "automatic".
(3)
Slowly raise the setpoint of the Sour Water Stripper pressure controller to the flare to 1.0 kg/cm2(g).
(4)
If, necessary, adjust the setpoint of the Sour Water Stripper pressure controller to the SRU to its normal setpoint.
The Sour Water Stripper pressure controller will now take over control of the Sour Water Stripper pressure by opening the pressure valve to send the acid gas to the SWS Gas Knock-Out Drums in the SRUs. The Sour Water Stripper pressure controller to the flare will close the acid gas pressure valve and stop the flow of acid gas to the flare. If the SRUs shut down (or some other upset causes the Sour Water Stripper pressure to rise), the Sour Water Stripper pressure controller to the flare will act as an over-ride and divert the acid gas to the flare. D.
The SWS is now fully on-stream. Before directing your attention away from the SWS, be sure that: (1)
Issued 30 August 2011
All controllers are functioning properly.
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SULFUR BLOCK (2)
Issued 30 August 2011
The steam heating systems are in service and the level control on the Reboiler condensate pot is functioning properly.
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SULFUR BLOCK
8.9
Shutdown Procedures Typical shutdown procedures for the Sour Water Stripping Unit are outlined and discussed in the sections that follow for the more common cases. Your existing company procedures and common sense operational judgment should be used to modify these procedures as needed to serve the purpose of any given planned shutdown situation.
8.9.1
Planned Shutdown Any equipment to be opened should be properly blinded and purged with inert gas before admission of air, to avoid exposure to potentially toxic gases or the formation of flammable vapor mixtures. To shut the SWS down in a controlled fashion proceed as follows:
Issued 30 August 2011
A.
Slowly reduce the output from the Treated Water hand control in the DCS is to 0% output to fully open the automated valve in the Startup/Re-run line to the Sour Water Tank, and fully close the automated valve in the Treated Water line downstream of the SWS Bottoms Cooler. Visually confirm that these valves are properly positioned.
B.
Place the stream flow controller in manual and set its output to 0% to close the stream flow control valve and stop the steam flow to the Sour Water Stripper Reboiler.
C.
Continue to circulate the sour water and operate the SWS Bottoms Cooler and the SWS Quench Water Cooler until the sour water is cool.
D.
Once the sour water is cool, shut down the SWS Feed Pump to stop the flow of sour water to the Sour Water Stripper and close the block valves in the pump suction lines.
E.
Place the SWS flow controller in the DCS in "manual" and set its output to 0% to fully close the sour water inlet flow control valve.
F.
Shutdown the SWS Quench Water Pumps and shut down the fans on the SWS Quench Water Cooler.
G.
Place the quench water flow controller in the DCS in "manual" and set its output to 0% to fully close the quench water flow control valve.
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SULFUR BLOCK
Issued 30 August 2011
H.
Use the SWS Bottoms pump to pump the sour water from the Sour Water Stripper to the Sour Water Tank until the low-low level shutdown is activated. This should shut down the SWS Bottoms Pump. Monitor the level in the Sour Water Stripper and be prepared to shut down the pump if the low-low level shutdown fails to activate.
I.
Place the SWS level controller in the DCS in "manual" and set its output to 0% to fully close the SWS level control valve.
J.
Shut down the fans on the SWS Bottoms Cooler
K.
Drain the remaining sour water in the SWS equipment to the Closed Drain System.
L.
Verify that the SWS level control valve is fully closed. Close both of its isolation block valves and its bypass valve.
M.
Verify that the SWS flow control valve is fully closed. Close both of its isolation block valves and its bypass valve.
N.
Verify that the quench water flow control valve is fully closed. Close both of its isolation block valves and its bypass valve.
O.
The SWS is now ready to be isolated and made safe for entry.
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SULFUR BLOCK 8.9.2
Effects of Shutdowns and Outages in Other Systems The SWS system is directly affected by a shutdown and/or outage in the LP steam system for the complex. These effects are described below.
8.9.2.1
Steam System Outage The most immediate impact on the SWS will be the loss of LP steam to the Stripper Reboiler if the steam outage lasts long enough. As the heat input to the reboiler declines, stripping of the acid gas from the sour water will decline and the H2S and NH3 in the treated water leaving the Sour Water Stripper will begin to increase. If this happens, use the Treated Water hand control in the DCS to route the treated water back to the Sour Water Tank until the LP steam system can be brought back on-line.
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SULFUR BLOCK
Table of Contents 9. SULFUR RECOVERY .................................................................................................. 9-4 9.1 PURPOSE OF SYSTEM ....................................................................................... 9-4 9.2 SAFETY ................................................................................................................. 9-4 9.3 PROCESS DESCRIPTION.................................................................................... 9-5 9.3.1 Overview......................................................................................................... 9-5 9.3.2 General ........................................................................................................... 9-6 9.3.3 Feed Gas Processing ..................................................................................... 9-6 9.3.4 Thermal Processing........................................................................................ 9-7 9.3.5 Catalytic Processing ....................................................................................... 9-8 9.3.6 Air Control System.......................................................................................... 9-9 9.3.7 Molten Sulfur Handling ................................................................................. 9-10 9.3.8 Steam Production ......................................................................................... 9-10 9.4 EQUIPMENT DESCRIPTION .............................................................................. 9-11 9.4.1 Reactor Furnace, A2-BA1530 (A2-BA1540) ................................................. 9-11 9.4.2 Acid Gas Burner Assembly, A2-BA1531 (A2-BA1541) ................................ 9-12 9.4.3 Acid Gas Knock-Out Drum, A2-FA1530 (A2-FA1540) ................................. 9-12 9.4.4 SWS Gas Knock-Out Drum, A2-FA1531 (A2-FA1541) ................................ 9-12 9.4.5 Reactor, A2-DC1530 (A2-DC1540) .............................................................. 9-13 9.4.6 Catalyst for Sulfur Plant Reactors, A2-MC1530 (A2-MC1540) ..................... 9-13 9.4.7 Acid Gas Preheater, A2-EA1530 (A2-EA1540) ............................................ 9-13 9.4.8 Sulfur Condenser, A2-EA1531 (A2-EA1541) ............................................... 9-13 9.4.9 Reactor No. 1 Feed Heater, A2-EA1532 (A2-EA1542) ................................ 9-14 9.4.10 Reactor No. 2 Feed Heater, A2-EA1533 (A2-EA1543) ................................ 9-14 9.4.11 Reactor No. 3 Feed Heater, A2-EA1534 (A2-EA1544) ................................ 9-15 9.4.12 Sulfur Surge Tank, A2-FB1530 (A2-FB1540) ............................................... 9-15 9.4.13 Acid Gas Knock-Out Drum Pump, A2-GA1530A/B (A2-GA1540A/B) .......... 9-16 9.4.14 SWS Gas Knock-Out Drum Pump, A2-GA1531A/B (A2-GA1541A/B) ......... 9-17 9.4.15 Sulfur Storage Tank Vent Ejector, A2-EE1530 (A2-EE1540) ....................... 9-17 9.4.16 Process Air Blower, A2-GB1530A/B (A2-GB1540A/B)................................. 9-18 9.4.17 Air Blower Suction Screen/Silencer, A2-FD1530A/B (A2-FD1540A/B) ........ 9-19 9.4.18 Process Air Vent Silencer, A2-FG1530A/B (A2-FG1540A/B) ....................... 9-19 9.4.19 Sulfur Drain Seal Assembly, A2-ME1530A-D (A2-ME1540A-D) .................. 9-19 9.4.20 Refractory for Reactor Furnace and Waste Heat Boiler, A2-MR1530 (A2-MR1540) .............................................................................................................. 9-20 9.4.21 Ceramic Ferrules for Waste Heat Boiler, A2-MR1532 (A2-MR1542) ........... 9-20 9.4.22 Refractory for Waste Heat Boiler, A2-MR1533 (A2-MR1543) ...................... 9-20 9.4.23 Refractory for Sulfur Condenser, A2-MR1534 (A2-MR1544) ....................... 9-20
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SULFUR BLOCK 9.4.24 Refractory for Reactor, A2-MR1535 (A2-MR1545) ...................................... 9-21 9.4.25 Rainshield for Reactor Furnace, A2-ME1531 (A2-ME1541) ........................ 9-21 9.4.26 Ceramic Ferrule for Reactor Furnace, A2-MR1531 (A2-MR1541) ............... 9-21 9.4.27 Waste Heat Boiler, A2-BF1530 (A2-BF1540) ............................................... 9-22 9.5 INSTRUMENTATION AND CONTROL SYSTEMS ............................................. 9-24 9.5.1 SRU Air:Acid Gas Ratio Control Loop .......................................................... 9-24 9.5.2 Acid Gas Burner Management System ........................................................ 9-30 9.5.3 Process Air Blower Controls ......................................................................... 9-34 9.5.4 Reactor Furnace Temperature Control......................................................... 9-39 9.5.5 Knock-Out Drum Pump Control .................................................................... 9-41 9.5.6 "Ride-Through" System Considerations ....................................................... 9-41 9.5.7 Boiler Low-Low Level S/D Transmitter Testing ............................................ 9-44 9.5.8 SRU Emergency Shutdown Systems ........................................................... 9-46 9.6 PROCESS PRINCIPLES AND OPERATING TECHNIQUES ............................. 9-56 9.6.1 Equipment Damage ...................................................................................... 9-56 9.6.2 Cold Catalyst Bed Startup ............................................................................ 9-58 9.6.3 Sulfur Solidification ....................................................................................... 9-60 9.6.4 Ammonia Salt Formation .............................................................................. 9-61 9.6.5 Catalyst Fouling ............................................................................................ 9-62 9.6.6 Operation of SRUs in Parallel....................................................................... 9-62 9.6.7 Process air Blower Operation ....................................................................... 9-65 9.6.8 Reactor Furnace Temperature ..................................................................... 9-70 9.6.9 Ammonia Destruction Considerations .......................................................... 9-73 9.6.10 Sulfur Recovery Efficiency............................................................................ 9-76 9.6.11 Operation at Low Flow Rates ....................................................................... 9-78 9.6.12 Pressure Drop Surveys ................................................................................ 9-82 9.6.13 Boiler Water Treatment ................................................................................ 9-84 9.7 PRECOMMISSIONING PROCEDURES ............................................................. 9-86 9.7.1 Preliminary Check-out .................................................................................. 9-86 9.7.2 Shutdown System Check-out ....................................................................... 9-87 9.7.3 Leak Testing the Process Piping and Equipment ......................................... 9-88 9.7.4 Purging the Inlet Knock-Out Drums .............................................................. 9-93 9.7.5 Commissioning Fuel Gas and Instrument Air to the Process ....................... 9-95 9.7.6 Commissioning Nitrogen to the Process ...................................................... 9-99 9.7.7 Commissioning the Sulfur Surge Tank Heating and Ventilation ................. 9-102 9.7.8 Pre-filling the Sulfur Drain Seal Assemblies ............................................... 9-104 9.8 STARTUP PROCEDURES................................................................................ 9-105 9.8.1 Initial Firing / Refractory Cure-out............................................................... 9-105 9.8.2 Amine Acid Gas Flow ................................................................................. 9-117 9.8.3 SWS Gas Flow ........................................................................................... 9-124 Issued 30 August 2011
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SULFUR BLOCK 9.8.4 Routing SRU Tailgas to the TGCU ............................................................. 9-127 9.8.5 Normal Startup - Cold System .................................................................... 9-129 9.8.6 Normal Startup - Hot System...................................................................... 9-146 9.8.7 Firing Supplemental Fuel Gas .................................................................... 9-158 9.9 SHUTDOWN PROCEDURES ........................................................................... 9-164 9.9.1 Planned Shutdown - No Reactor Entry....................................................... 9-165 9.9.2 Planned Shutdown for Reactor Entry ......................................................... 9-170 9.9.3 Shutting Down When Boiler Tubes Are Leaking ........................................ 9-180 9.9.4 Emergency Shutdown ................................................................................ 9-181 9.9.5 Effects of Shutdowns and Outages in Other Systems................................ 9-183 9.10 ANALYTICAL PROCEDURES .......................................................................... 9-187 9.10.1 Procedure for Sampling and Titrating with a Tutweiler Apparatus ............. 9-187 9.10.2 H2S Concentration in Acid Gas by the Tutweiler Method ........................... 9-189 9.10.3 H2S and SO2 Concentration in Tailgas by the Tutweiler Method ................ 9-192 9.10.4 Tailgas Analysis Table................................................................................ 9-196 9.10.5 Tailgas Analysis Operating Chart ............................................................... 9-197 9.10.6 Essential Apparatus for Tutweiler Analysis ................................................ 9-199 9.10.7 Materials for Tutweiler Analysis .................................................................. 9-200 9.10.8 H2S and SO2 Conc. in Tailgas Using Gas Detector Tubes ......................... 9-200 9.11 ADJUSTING STACKMATCH® IGNITOR/PILOTS ............................................. 9-205
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SULFUR BLOCK
9. SULFUR RECOVERY 9.1
Purpose of System The purpose of the Sulfur Recovery Units (SRUs) is to dispose of H2S-laden acid gas. This gas is produced by the new Amine Regeneration Unit and Sour Water Stripping Unit. Acid gases of this type are not allowed into the atmosphere, as they are highly toxic. If burned in a flare system, the pollutants would exceed emission standards. Each Sulfur Recovery Unit can take enough H2S out of the acid gas so that the remaining tailgas can be processed in a Tailgas Cleanup Unit to meet the emission standards after incineration. Also, the byproduct of pure sulfur is a marketable product.
9.2
Safety WARNING ALL PIPING AND VESSELS INCLUDED IN THIS UNIT EITHER CONTAIN OR HAVE THE POTENTIAL FOR CONTAINING HAZARDOUS GASES THAT MAY CAUSE SERIOUS INJURY OR DEATH. THE TWO GASES THAT ARE MOST COMMON AND HAZARDOUS IN A TOXIC WAY ARE HYDROGEN SULFIDE AND WARNING SULFUR DIOXIDE. CLOSE ATTENTION SHOULD BE PAID TO THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES AS TO THE NATURE AND ABILITY OF THESE GASES TO CONTAMINATE OTHER ELEMENTS IN THIS UNIT. AN EMPLOYEE'S KNOWLEDGE OF THE HAZARDOUS CHEMICALS AND COMPOUNDS WITH WHICH HE WILL BE WORKING IS ONE OF THE MOST BASIC PREREQUISITES FOR HIS OWN SAFETY, THE SAFETY WARNING OF OTHERS, AND THE PROTECTION OF EQUIPMENT. ALL EMPLOYEES SHOULD REVIEW THE "GENERAL SAFETY" SECTION OCCASIONALLY TO REFRESH THEIR MEMORIES. NEW EMPLOYEES SHOULD STUDY IT UNTIL THE INFORMATION IS THOROUGHLY UNDERSTOOD. PEOPLE WHO HAVE NOT BEEN PROPERLY TRAINED SHOULD NOT BE ALLOWED TO OPERATE OR WORK IN AND AROUND THIS PLANT.
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SULFUR BLOCK
9.3
Process Description
9.3.1
Overview The Systems Diagram, Material Balance and Process Flow Diagrams, Dwg. Nos. 507000-7000-01, and 507000-7000-07 through -09, are contained in the "Process Flow Diagrams" Section of the Basic Engineering Package. Please refer to these drawings to follow this description of the process. The new Sulfur Recovery Units, consisting of SRU Train 1 and SRU Train 2, are designed to operate in parallel and recover elemental sulfur from the off-gases produced by the new Amine Regeneration and Sour Water Stripper Units. It is intended that the Sulfur Recovery Facility convert and recover 99.9% or more of the hydrogen sulfide (H2S) contained in the feed streams as elemental sulfur in compliance with environmental requirements. The acid gases produced by the new Amine Regeneration Unit (ARU) and the new Sour Water Stripping Unit (SWS) are routed to two parallel Claus Sulfur Recovery Units (SRUs) using technology licensed from BP Amoco Corporation. The H2S is converted into molten elemental sulfur and routed to the common Sulfur Degassing Unit (SDU) that uses technology licensed from BP Amoco Corporation to reduce the H2S content of the sulfur to less than 10 PPMW. The combined tailgas from the sulfur plants is processed in a Tailgas Cleanup Unit (TGCU) using the Shell Claus Off-gas Treating (TGCU) process licensed by Shell Global Solutions (US) Inc. to produce an acid gas stream that is recycled back to the Claus plant so that the overall sulfur recovery is 99.9 wt. % or better. The effluent gas from the TGCU is thermally incinerated in a Tailgas Thermal Oxidation Unit (TTO) to convert all of the remaining sulfur compounds into sulfur dioxide (SO2) before dispersion of the gas to the atmosphere. Due to the sulfur removal by the TGCU process, the incinerated effluent gas will contain less than 200 PPMV of SO2 on a dry, 0% oxygen basis. The two process trains are identical, so all of the information that follows applies to both trains. Where references to equipment or instrument tag numbers are given, the SRU Train 1 tag number is given first followed by the SRU Train 1 tag number in parentheses.
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SULFUR BLOCK 9.3.2
General Each sulfur plant processes 1,181 Nm3/H of acid gas from the Amine Regeneration Unit and 33 Nm3/H of off-gas from Sour Water Stripping (SWS) Unit, plus 50% of the recycle acid gas from the Tailgas Cleanup Unit. Each sulfur plant will recover 94-96% of the sulfur contained in the total acid gas feed as elemental sulfur, producing about 34.6 MT/D of molten sulfur product. The tailgas leaving each sulfur plant is routed to the common TGCU. Each sulfur plant uses the modified straight-through Claus process licensed from BP Amoco Corporation, with a number of special design features to accomplish the required recovery performance while providing exceptionally good on-stream reliability and ease of operation. The Claus process utilizes the following chemical reactions to convert hydrogen sulfide to elemental sulfur: (1)
H2S + 3/2 O2
SO2 + H2O
(2)
2 H2S + SO2
3/n Sn + 2 H2O
The overall reaction for the process is: (3)
3 H2S + 3/2 O2
3/n Sn + 3 H2O
The sulfur plant contains one non-catalytic conversion stage and three catalytic conversion stages in series. The Claus reaction is highly exothermic, releasing a great deal of heat energy that is recovered as HP and LP steam in heat exchangers following the conversion stages.
9.3.3
Feed Gas Processing Acid gas from the Amine Regeneration Unit is combined with the recycle acid gas from the Tailgas Cleanup Unit and is routed to the Acid Gas Knock-Out Drum, A2-FA1530 (A2-FA1540), at 49°C [120°F] and Entrained liquids are separated and 0.74 kg/cm2(g) [10.5 PSIG]. automatically routed back to the Rich Amine Flash Drum by Acid Gas Knock-Out Drum Pump, A2-GA1530A/B (A2-GA1540A/B), on start/stop level control. The scrubbed acid gas stream flows through the Acid Gas Preheater, A2-EA1530 (A2-EA1540), where a portion of the LP (4.2 kg/cm2(g) [60 PSIG]) steam generated elsewhere in the SRU heats the acid gas to 126°C [259°F]. Preheating the amine acid gas allows it to be mixed with the SWS gas without causing ammonium salt precipitation. The preheater is also an energy conservation device, as preheating with
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SULFUR BLOCK LP steam allows more HP (48.5 kg/cm2(g) [690 PSIG]) steam to be produced in the sulfur plant. SWS gas from the Sour Water Stripping Unit is routed to the SWS Gas knock-Out Drum, A2-FA1531 (A2-FA1541), at 85°C [185°F] and 0.70 kg/cm2(g) [10.0 PSIG]. Entrained liquids are separated and automatically routed back to the Sour Water Flash Drum by the SWS Gas Knock-Out Drum Pump, A2-GA1531A/B (A2-GA1541A/B), on start/stop level control. The scrubbed SWS gas mixes with the majority of the preheated amine acid gas and flows to the Acid Gas Burner, A2-BA1531 (A2-BA1541). The remainder of the amine acid gas is routed into the sides of the Reactor Furnace, A2-BA1530 (A2-BA1540), on flow ratio control to ensure proper destruction of the ammonia in the first zone of the furnace as described below.
9.3.4
Thermal Processing One-third of the hydrogen sulfide in the feed stream must be converted to sulfur dioxide before the Claus reaction (2) can be utilized to produce elemental sulfur. Accordingly, the acid gas feed stream flows to the Acid Gas Burner to be combusted with air provided by the Process Air Blower, A2-GB1530A/B (A2-GB1540A/B). The amount of air is controlled to combust one-third of the hydrogen sulfide to sulfur dioxide via reaction (1). Sufficient air is also provided to combust the ammonia and hydrocarbons entering with the acid gas. The combustion products pass into the first combustion zone of the Reactor Furnace, which provides the necessary residence time to allow these reactions to reach equilibrium. At 1370°C [2500°F] or above (with the proper residence time), ammonia is almost completely destructed to nitrogen and water. The first combustion zone is controlled at or above this temperature by adjusting the amount of amine acid gas bypassing the burner. Combustion of the SWS gas at or above this temperature in a reducing atmosphere is essential for destruction of the ammonia, and avoids formation of undesirable and troublesome compounds such as sulfur trioxide. The first combustion zone of the Reactor Furnace is separated from the second zone by a refractory checker wall. The amine acid gas bypassing the burner is injected into the Reactor Furnace immediately downstream of the checker wall, where it mixes with the burner effluent. The second zone is large enough to provide sufficient residence time for the
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SULFUR BLOCK sulfur-forming and hydrocarbon-oxidizing reactions to reach equilibrium. The Reactor Furnace functions as a non-catalytic conversion stage, as 67% of the hydrogen sulfide is converted to elemental sulfur. The effluent from the Reactor Furnace enters the tubes in the Waste Heat Boiler, A2-BF1530 (A2-BF1540), where the gas is cooled to 328°C [622°F] by producing HP steam. The gas is then routed through the first condensing pass of the Sulfur Condenser, A2-EA1531 (A2-EA1541), and further cooled to 165°C [329°F] by producing LP steam. The outlet channel of the Sulfur Condenser is extended and contains a compartment that serves as a separator for the condensed sulfur that is formed as the gases are cooled. About 65% of the sulfur entering the sulfur plant is recovered as condensed liquid sulfur here.
9.3.5
Catalytic Processing The vapor from the first condensing pass of the Sulfur Condenser flows to the Reactor No. 1 Feed Heater, A2-EA1532 (A2-EA1542), and is heated by a portion of the HP steam generated in the Waste Heat Boiler, which circulates in a thermosiphon loop. The reheated stream then enters the first catalyst chamber in the Reactor, A2-DC1530 (A2-DC1540), at 232°C [450°F]. In this first catalytic conversion stage, the majority of the remaining sulfur compounds are converted to elemental sulfur vapor by reaction (2). In addition, much of the organic sulfur compounds formed by side reactions in the Reactor Furnace, carbonyl sulfide (COS) and carbon disulfide (CS2), are hydrolyzed back to H2S in this catalyst bed. Hydrolysis of the organic sulfur compounds helps achieve high sulfur recovery by converting the organic sulfur compounds into sulfur species that will react via the Claus reaction to produce sulfur. Special promoted catalysts are often employed for higher COS/CS2 conversion, and this catalytic stage is often operated at higher temperatures since this also increases conversion. The sulfur vapor produced the first catalyst bed is then condensed at about 161°C [322°F] in the second condensing pass of the Sulfur Condenser by generating additional LP steam. About 20% of the inlet sulfur is condensed and recovered as liquid sulfur in the separator chamber at the outlet of this condenser pass. The vapor from the second condensing pass is reheated to 210°C [410°F] using HP steam in the Reactor No. 2 Feed Heater, A2-EA1533 (A2-EA1543), and is routed to the
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SULFUR BLOCK second catalyst chamber in the Reactor where further conversion of H2S and SO2 occurs. The reactor effluent is then cooled to 157°C [314°F] in the third condensing pass of the Sulfur Condenser by generating additional LP steam. About 7% of the inlet sulfur is recovered as condensed liquid sulfur in the separator chamber at the outlet of this condensing pass. The vapor leaving the third condensing pass is reheated to 204°C [400°F] using HP steam in the Reactor No. 3 Feed Heater, A2-EA1534 (A2-EA1544), and flows to the third catalyst chamber in the Reactor, the final conversion stage. More conversion occurs in this third catalytic stage before the gas is cooled in the fourth pass of the Sulfur Condenser by generating additional LP steam. An additional 2% of the total sulfur is recovered in the separator chamber at the outlet of this fourth and final condensing pass, bringing the total sulfur recovery to approximately 94% in the Claus sulfur plant. The remaining vapor leaves the fourth pass of the Sulfur Condenser at about 156°C [313°F] and flows to the TGCU.
9.3.6
Air Control System For optimum sulfur recovery, the hydrogen sulfide:sulfur dioxide ratio of the process gas at all points downstream of the Reactor Furnace should be exactly 2:1. This ratio depends on the amount of air sent to the Acid Gas Burner by the Process Air Blower. A combination of feed-forward/feed-back control is used in the sulfur plant to control the proper quantity of air. The amine acid gas flow rate and SWS gas flow rate (and fuel gas flow rate, if any) are measured, summed together, and sent to the ratio controller which adjusts the air flow, yielding feed-forward control that allows the sulfur plant to compensate for changes in the amine acid gas and SWS gas flow rates (and the fuel gas flow rate, also). The H2S:SO2 ratio of the gas from the fourth condensing pass of the Sulfur Condenser is continuously analyzed by the air demand analyzer. This analyzer signal is then used to change the setpoint of the flow ratio controller, thus providing feed-back control to allow the sulfur plant to adjust to variations in amine acid gas and/or SWS gas composition, temperature, and pressure.
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 9.3.7
Molten Sulfur Handling Liquid sulfur from each of the four condensing passes is routed to an individual Sulfur Drain Seal Assembly, A2-ME1530A-D (A2-ME1540A-D), in the below-ground Sulfur Surge Tank, A2-FB1530 (A2-FB1540). Each drain seal has a "U"-tube that uses static head from a column of liquid sulfur to serve as a seal and prevent the process gases from escaping. The drain seals are steam-jacketed to prevent sulfur from freezing and have view hatches to allow verifying that each rundown line is flowing. The Sulfur Surge Tank provides storage for about 160 metric tons of raw sulfur production from the sulfur plant. The Sulfur Surge Tank is a horizontal cylindrical tank resting in a concrete vault. The tank is constructed of carbon steel and is equipped with internal steam coils. The Sulfur Surge Tank Vent Ejector, A2-EE1530 (A2-EE1540), uses HP motive steam to route the tank vapors to the Tailgas Thermal Oxidation system.
9.3.8
Steam Production The Sulfur Recovery Unit produces steam at two pressure levels. High pressure steam is generated at 48.5 kg/cm2(g) [690 PSIG] in the Waste Heat Boiler. A portion of this steam is used to reheat the reactor feed streams and in the TGCU Reactor Feed Heater, A2-EA1560. The remaining HP steam from the SRU is routed to the Tailgas Thermal Oxidation system to be superheated in the Thermal Oxidizer Waste Heat Boiler, A2-BF1570. Low pressure steam at 4.2 kg/cm2(g) [60 PSIG] is produced in the Sulfur Condenser. Part of this steam is used to preheat the amine acid gas, heat the Sulfur Storage Tank, heat the steam-jacketed lines, and for steam tracing services. The remainder is routed to the complex's LP steam header.
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SULFUR BLOCK
9.4
Equipment Description
9.4.1
Reactor Furnace, A2-BA1530 (A2-BA1540) The Reactor Furnace is a combustion and non-catalytic reaction chamber. The furnace shell is internally lined with refractory insulation to protect it against the extreme process temperatures inside. The maximum operating temperature is about 1600°C. Although the furnace can withstand short excursions above this temperature, prolonged operation above this temperature will damage the refractory. The refractory is designed to keep the furnace shell at 200-340°C to protect it from acid corrosion on its interior. Periodic surveys of the temperature all along the shell of the furnace should be conducted (using a hand-held infrared pyrometer) to ensure that the shell is always in the desired temperature range. The furnace is divided into two combustion/reaction zones by a refractory checker wall. In the first zone, the SWS gas and most of the amine acid gas are combusted with process air to destroy the ammonia, oxidize the hydrocarbons, produce sulfur dioxide, and form sulfur. The remaining amine acid gas enters the furnace through side injection nozzles and mixes with the combustion products flowing through the checker wall into the second zone of the furnace. This second zone provides additional residence time for the sulfur-forming and hydrocarbon-oxidizing reactions to reach equilibrium. The furnace is covered by a protective metal shroud to prevent thermal shock to the hot metal shell by severe weather, such as heavy rains.
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SULFUR BLOCK 9.4.2
Acid Gas Burner Assembly, A2-BA1531 (A2-BA1541) The burner assembly is specifically designed to burn the acid gas stream for this facility. The unit consists of an acid gas burner tip, a fuel gas burner ring with multiple tips for combusting fuel gas during plant warmup, a pilot gas burner with an integral ignitor, two flame scanners, two viewports, and specially designed air distribution baffles for proper combustion. This complete unit is installed in the front of the Reactor Furnace The StackMatch® ignitor/pilot assembly is designed to be retracted or extracted after the main fuel gas burner ring or the acid gas burner tip has been lit. If the assembly is extracted, the block valve can be closed to isolate it from the furnace atmosphere. The assembly includes filters for the incoming fuel gas and air, which should be checked (and cleaned, if necessary) after each use so that there is no chance of a plugged filter causing delays during the next startup.
9.4.3
Acid Gas Knock-Out Drum, A2-FA1530 (A2-FA1540) This vertical vessel is installed in the inlet amine acid gas line to remove liquids from the gas stream before it is routed to the Acid Gas Burner and Reactor Furnace. The liquid produced in this vessel is pumped on automatic start/stop control to the Rich Amine Flash Drum. The vessel is equipped with high level alarms to warn of a rising level in the drum, and a high-high level shutdown to activate the SRU ESD system before liquids can reach the hot furnace. The shutdown requires that 2 out of 3 transmitters have a high-high level indicated.
9.4.4
SWS Gas Knock-Out Drum, A2-FA1531 (A2-FA1541) This vertical vessel is installed in the inlet SWS gas line to remove liquids from the gas stream before it is routed to the Acid Gas Burner. The liquid removed in this vessel is pumped on automatic start/stop control to the Sour Water Flash Drum. The vessel is equipped with high level alarms to warn of a rising level in the drum, and a high-high level shutdown to block-in the SWS gas before liquids can reach the hot furnace.
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SULFUR BLOCK 9.4.5
Reactor, A2-DC1530 (A2-DC1540) The Reactor is a single horizontal vessel divided by two vertical partitions into three separate catalyst chambers. This reactor is of the axial down-flow type, with the feed gas entering the top of each chamber (via a standpipe from the bottom of the vessel) and proceeding vertically downward through its catalyst bed. These standpipes discharge the feed gases against the top of the vessel shell to distribute the gases over the length of each chamber and prevent the inlet gas streams from impinging directly on the catalyst beds. A catalyst support grating is installed in each chamber to support its catalyst bed in the center of the vessel. The support grating is covered with a stainless steel screen to prevent the catalyst from sifting through the grating. A small bead of castable refractory is used to seal the edges of the support grating to prevent catalyst leaks between the grating and the vessel shell.
9.4.6
Catalyst for Sulfur Plant Reactors, A2-MC1530 (A2-MC1540) Refer to the Basic Engineering Package for the type of catalyst used in the Reactor.
9.4.7
Acid Gas Preheater, A2-EA1530 (A2-EA1540) This shell and tube exchanger uses LP steam to heat the inlet amine acid gas stream before it mixes with the SWS gas and is combusted in the Acid Gas Burner and the Reactor Furnace. This minimizes the possibility of having ammonia salts precipitate when the amine acid gas mixes with the high ammonia content SWS gas. The preheating also increases the production of HP steam in the Waste Heat Boiler.
9.4.8
Sulfur Condenser, A2-EA1531 (A2-EA1541) The Sulfur Condenser contains four different sets of tubes. Divider plates in the inlet and outlet channels segregate the four different gas streams flowing through this exchanger. The four sets of condensing pass tubes are immersed in the water-filled section of the shell, allowing them to cool the hot gases leaving the Waste Heat Boiler and the three catalyst beds in the Reactor. The boiling water in the shell of the exchanger cools the gases and condenses sulfur from the process streams. The steam produced will be controlled at about
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SULFUR BLOCK 4.2 kg/cm2(g). The outlet channel of the exchanger is extended to serve as gas/liquid separators to remove entrained sulfur droplets from the gas streams by gravity separation. The separator chambers also contain woven wire mist eliminators to assist in removing sulfur from the gas streams. Steam-jacketed sulfur drains are located in the bottom of each separator chamber to remove the liquid sulfur produced. The boiler is equipped with level transmitters that will shut down the SRU should the water level fall to within 75 mm of the top row of condensing tubes. The shutdown requires that 2 out of 3 transmitters have a low-low level indicated. Operation of the boiler without a sufficient water level could possibly damage the tubes.
9.4.9
Reactor No. 1 Feed Heater, A2-EA1532 (A2-EA1542) This shell and tube exchanger uses HP steam to heat the process gas stream leaving the first condensing pass of the Sulfur Condenser before it enters the first catalyst bed in the Claus Reactor. This exchanger operates in a thermosiphon loop with the Waste Heat Boiler using a portion of the steam produced by the Waste Heat Boiler to provide the heat input. The temperature of the gas leaving the exchanger is controlled at the desired value by adjusting a control valve in the condensate outlet line. This control valve can raise the level of condensate in the exchanger shell to submerge some of the tubes in condensate to reduce the heat input.
9.4.10
Reactor No. 2 Feed Heater, A2-EA1533 (A2-EA1543) This shell and tube exchanger uses HP steam to heat the process gas stream leaving the second condensing pass of the Sulfur Condenser before it enters the second catalyst bed in the Claus Reactor. This exchanger operates in a thermosiphon loop with the Waste Heat Boiler using a portion of the steam produced by the Waste Heat Boiler to provide the heat input. The temperature of the gas leaving the exchanger is controlled at the desired value by adjusting a control valve in the condensate outlet line. This control valve can raise the level of condensate in the exchanger shell to submerge some of the tubes in condensate to reduce the heat input.
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 9.4.11
Reactor No. 3 Feed Heater, A2-EA1534 (A2-EA1544) This shell and tube exchanger uses HP steam to heat the process gas stream leaving the third condensing pass of the Sulfur Condenser before it enters the third catalyst bed in the Claus Reactor. This exchanger operates in a thermosiphon loop with the Waste Heat Boiler using a portion of the steam produced by the Waste Heat Boiler to provide the heat input. The temperature of the gas leaving the exchanger is controlled at the desired value by adjusting a control valve in the condensate outlet line. This control valve can raise the level of condensate in the exchanger shell to submerge some of the tubes in condensate to reduce the heat input.
9.4.12
Sulfur Surge Tank, A2-FB1530 (A2-FB1540) This horizontal vessel is installed in a below-ground concrete vault. It receives the produced liquid sulfur from the SRU and holds it in a molten state for pumping to the Sulfur Degassing Unit. There are steam coils installed in the bottom of the tank to keep the sulfur molten, each with its own steam supply and trap. Should a steam coil develop a leak, it can be shut off while the others keep the sulfur hot. The tank is installed below ground to accept the sulfur production by gravity flow. Liquid-sealed Sulfur Drain Seal Assemblies are provided to allow draining of the produced liquid sulfur while preventing passage of the process gases. Liquid sulfur flows through these drain seals and then into the tank. The primary ventilation system for the Sulfur Storage Tank is the Sulfur Surge Tank Vent Ejector, A2-EE1530 (A2-EE1540). It uses HP steam as the motive force to circulate air through the tank. Ambient air enters through the breather vents at each end of the tank and is educted to the ejector suction. The discharge from the ejector is routed to the TTO for disposal. This air circulation dilutes the H2S that "weathers off" from the liquid sulfur so that the concentration remains below the lower explosive limit. The circulation also prevents accumulation of water in the tank that could cause rapid corrosion. In addition to the steam-powered ejector, there is a backup natural-draft ventilation system provided for the Sulfur Storage Tank when the ejector is out of service. The tank vapors are vented from the tank through a heated vent stack mounted on the top of the tank. Air to displace these vapors enters through the breather vents at each end of the tank and
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SULFUR BLOCK sweeps through the tank before entering the vent stack. The steam-jacketing on the vent stack heats the air in the stack, providing the natural-draft driving force that makes the system work.
WARNING
IT IS VERY IMPORTANT TO KEEP HEAT (STEAM) ON THE VENT STACK TO MAINTAIN THE NATURAL DRAFT. IN ADDITION, THE STEAM JACKET ON THE VENT STACK MUST VENTED PERIODICALLY TO PREVENT NON-CONDENSIBLES FROM ACCUMULATING AND "BLANKING OFF" THE STEAM HEATING SURFACES. A VENT LINE IS PROVIDED EXPRESSLY FOR THIS PURPOSE.
9.4.13
Acid Gas Knock-Out Drum Pump, A2-GA1530A/B (A2-GA1540A/B) These pumps send liquids that accumulate in the Acid Gas Knock-Out Drum to the Rich Amine Flash Drum. The pumps are designed to start and stop automatically when the level rises in the vessel. Level transmitters mounted on the vessel alert the operator if the level in the vessel exceeds the automatic start point. These pumps are equipped with tandem seals to reduce the likelihood of releasing H2S to the surroundings.
WARNING THE LIQUID IN THESE PUMPS CONTAINS DISSOLVED H2S. THIS H2S CAN BE RELEASED TO THE SURROUNDINGS WHEN LIQUID IS DRAINED FROM THESE PUMPS OR FROM THE PIPING CONNECTED TO THE PUMPS. ALWAYS OBSERVE PROPER PROCEDURES AND PRECAUTIONS WHEN DRAINING LIQUID FROM THESE PUMPS OR PERFORMING MAINTENANCE ON THEM. THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES SHOULD BE CONSULTED IF THERE IS ANY DOUBT ABOUT HOW TO WORK SAFELY WHEN H2S MAY BE PRESENT.
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SULFUR BLOCK 9.4.14
SWS Gas Knock-Out Drum Pump, A2-GA1531A/B (A2-GA1541A/B) These pumps send liquids that accumulate in the SWS Gas Knock-Out Drum to the Sour Water Flash Drum. The pumps are designed to start and stop automatically when the level rises in the vessel. Level transmitters mounted on the vessel alert the operator if the level in the vessel exceeds the automatic start point. These pumps are equipped with tandem seals to reduce the likelihood of releasing H2S to the surroundings. WARNING THE LIQUID IN THESE PUMPS CONTAINS DISSOLVED H2S AND NH3. THIS H2S AND/OR NH3 CAN BE RELEASED TO THE SURROUNDINGS WHEN LIQUID IS DRAINED FROM THESE PUMPS OR FROM THE PIPING CONNECTED TO THE PUMPS. ALWAYS OBSERVE PROPER PROCEDURES AND PRECAUTIONS WHEN DRAINING LIQUID FROM THESE PUMPS OR PERFORMING MAINTENANCE ON THEM. THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES SHOULD BE CONSULTED IF THERE IS ANY DOUBT ABOUT HOW TO WORK SAFELY WHEN H2S AND/OR NH3 MAY BE PRESENT.
9.4.15
Sulfur Storage Tank Vent Ejector, A2-EE1530 (A2-EE1540) This jet ejector uses HP motive steam to circulate air through the Sulfur Surge Tank and route it to the Thermal Oxidizer. This air dilutes the H2S that "weathers off " from the liquid sulfur product so that the H2S concentration in the Sulfur Surge Tank is well below the lower explosive limit (LEL). The ejector body is steam-jacketed to prevent sulfur contained in the circulating air from freezing and plugging the ejector. Whenever motive steam to the ejector is not available, the ejector discharge valve should be closed. This will prevent back-flow of Thermal Oxidizer gases into the Sulfur Surge Tank.
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SULFUR BLOCK
WARNING
NEVER BLOCK-IN THE EJECTOR COMPLETELY (CLOSING BOTH THE SUCTION AND DISCHARGE VALVES) WHILE THE HP MOTIVE STEAM IS CONNECTED TO THE EJECTOR. A LEAK IN THE MOTIVE STEAM BLOCK VALVE COULD ALLOW THE HP STEAM TO OVER-PRESSURE THE EJECTOR BODY.
9.4.16
Process Air Blower, A2-GB1530A/B (A2-GB1540A/B) These multi-stage centrifugal blowers provide the combustion air required to combust the amine acid gas and SWS gas in the Acid Gas Burner. The air flow rate is controlled by throttling a valve in each blower suction line. A vent valve on each blower discharge line is used to vent air to the atmosphere when the process air flow is low so that the blower does not go into "surge".
CAUTION
THE BOLT HOLES IN THE BLOWER/MOTOR BASEPLATES ARE PROVIDED FOR SHIPPING AND POSITIONING PURPOSES ONLY. DO NOT BOLT THE BASEPLATES DOWN TIGHTLY. EITHER LEAVE THE NUTS OFF, OR HAND-TIGHTEN THEM ONLY. EXCESSIVE TIGHTENING MAY DISTORT THE BASEPLATES AND CAUSE MISALIGNMENT AND/OR VIBRATION DAMAGE TO THE UNITS. THE BASEPLATES ARE TO REST ON RESILIENT FOUNDATION PADS. DO NOT GROUT UNDER THE BASEPLATES. RIGIDLY CONNECTING THE BASEPLATES TO THEIR FOUNDATIONS WILL INCREASE THE BLOWER VIBRATION LEVELS AND LEAD TO BLOWER DAMAGE.
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SULFUR BLOCK 9.4.17
Air Blower Suction Screen/Silencer, A2-FD1530A/B (A2-FD1540A/B) This filter/silencer is designed to keep rainwater and large solid particles from entering the Process Air Blower. It also helps reduce the noise produced by the Process Air Blowers.
9.4.18
Process Air Vent Silencer, A2-FG1530A/B (A2-FG1540A/B) These silencers help reduce the noise produced when the blow-off valves on the discharge of the Process Air Blowers are being used to prevent the blowers from "surging".
9.4.19
Sulfur Drain Seal Assembly, A2-ME1530A-D (A2-ME1540A-D) Ortloff's proprietary Sulfur Drain Seal Assemblies are designed to drain liquid sulfur from the four outlet channels of the Sulfur Condenser. The seals are built as "U-type" traps that use liquid sulfur to seal and prevent process gases from flowing to the Sulfur Surge Tank along with the liquid sulfur product. The drain seals are sized to provide a seal leg which should not blow out at the maximum discharge pressure of the Process Air Blower. The seals are fully steam-jacketed and designed to be installed in the top of the Sulfur Surge Tank. Each seal has a hinged inspection hatch to allow observation and sampling of the flow from each condenser pass. The liquid sulfur from the inspection basin flows down to the bottom of the Sulfur Surge Tank through a drain pipe to prevent free-fall of the liquid sulfur, which could cause static electricity to build up. The drain seals are mostly carbon steel, except for the inspection hatches which are aluminum. Each drain seal has removable blind flanges to allow "rodding" its rundown line and its dip leg. Before removing either flange, close the block valve in the rundown line to prevent the escape of process gas to the surroundings when the plugging is cleared. When the rodding operation is complete and the flange(s) are back in place, remember to reopen the block valve.
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SULFUR BLOCK 9.4.20
Refractory for Reactor Furnace and Waste Heat Boiler, A2-MR1530 (A2-MR1540) The firing chamber of the Reactor Furnace and the transition piece on the Waste Heat Boiler have a refractory lining consisting of alumina firebrick backed heavy duty firebrick. The checker wall in the Reactor Furnace is also constructed from alumina firebrick. Mortar used for installing the brick is alumina air-setting mortar. The inlet tubesheet on the Waste Heat Boiler is covered with a layer of alumina castable refractory.
9.4.21
Ceramic Ferrules for Waste Heat Boiler, A2-MR1532 (A2-MR1542) The ceramic ferrules are inserted into the inlet ends of the tubes in the Waste Heat Boiler, then a layer of castable refractory is installed over the tubesheet. The ceramic ferrules are flush with the outside of the refractory and extend into each tube. The ferrules and refractory protect the tube ends from being directly exposed to the hot combustion gas and give very long operating life to the Waste Heat Boiler.
9.4.22
Refractory for Waste Heat Boiler, A2-MR1533 (A2-MR1543) The outlet channel of the Waste Heat Boiler is covered with a lining of castable refractory. This refractory protects the steel surfaces of the channel from accelerated sulfide corrosion rates due to the high process gas temperature.
9.4.23
Refractory for Sulfur Condenser, A2-MR1534 (A2-MR1544) The inlet channel of the first pass of the Sulfur Condenser is covered with a lining of castable refractory. This refractory protects the steel surfaces of the channel from accelerated sulfide corrosion rates due to the high process gas temperature. The refractory is built up on the bottom of the channel so that it is flush with the bottom of the inlet nozzle and with the bottom of the tubes in the lowest row of tubes, so that the entire inlet channel free-drains from the inlet nozzle into the tubes and liquid sulfur cannot "puddle" in the inlet channel.
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SULFUR BLOCK 9.4.24
Refractory for Reactor, A2-MR1535 (A2-MR1545) A 50 mm bead of castable refractory is installed around the edges of the catalyst bed supports inside each chamber of the Reactor. This seals the edges of the bed supports so that the small catalyst pellets cannot escape from the beds.
9.4.25
Rainshield for Reactor Furnace, A2-ME1531 (A2-ME1541) The Reactor Furnace shell is internally lined with refractory insulation to protect it against the extreme process temperatures inside. The refractory is designed to keep the furnace shell at 200-340°C to protect it from corrosion on its interior. Shell temperatures higher than this can result in high temperature sulfidic corrosion of the steel shell, while temperatures lower than this can cause the steel to drop below the acid dewpoint of the process gas and suffer acid corrosion. The upper 240° of the Reactor Furnace is covered by a metal rainshield to prevent over-cooling of the furnace shell by rain and/or wind, which would cause shorter refractory life (due to thermal cycling) and corrosion of the furnace shell (due to acid condensation). The rainshield is mounted on stand-off rings to protect the furnace shell from direct exposure to the elements without restricting the free circulation of cooling air over the furnace shell. The rainshield is formed from corrugated galvanized steel.
9.4.26
Ceramic Ferrule for Reactor Furnace, A2-MR1531 (A2-MR1541) These ceramic ferrules are inserted into the side ports on the Reactor Furnace where the bypassed acid gas is to be injected into the second zone of the furnace. The ceramic ferrules extend to the outside of the refractory lining inside the furnace so that essentially no part of the nozzle is directly exposed to the hot furnace gases or to radiation from the hot furnace. This will help protect the nozzles from overheating whenever the bypass acid gas is not flowing.
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SULFUR BLOCK 9.4.27
Waste Heat Boiler, A2-BF1530 (A2-BF1540) The Waste Heat Boiler contains the cooling pass tubes which cool the hot gases leaving the Reactor Furnace. The cooling pass tubes are immersed in the water-filled section of the shell, allowing them to cool the hot gases leaving the Reactor Furnace from by boiling water in the shell of the exchanger. The steam produced will be controlled at about 2 48.5 kg/cm (g). Because of the high inlet temperature to these tubes, the inlet tubesheet is refractory-lined and the inlet of each tube contains a ceramic ferrule insert. Most of the steam produced by the Waste Heat Boiler is routed to the Thermal Oxidizer Waste Heat Boiler, A2-BF1570, to be superheated before it is exported to the HP Steam header. The remaining portion of this steam is withdrawn and directed to the three heaters for the Reactor feeds, the Reactor No. 1 Feed Heater, the Reactor No. 2 Feed Heater, and the Reactor No. 3 Feed Heater, which operate in a thermosiphon loop with the Waste Heat Boiler. The steam flows over and condenses on the outside of the tubes in these exchangers, heating the gas within the tubes to raise the temperatures of the gas streams to the desired feed temperatures for the catalyst beds. The condensate from these three exchangers returns to the Waste Heat Boiler by gravity flow. The boiler is equipped with level transmitters that will shut down the SRU should the water level fall to within 75 mm of the top row of tubes. The shutdown requires that 2 out of 3 transmitters have a low-low level indicated. Operation of the boiler without a sufficient water level will result in severe damage to the tubes and the shell.
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SULFUR BLOCK
WARNING
AS DISCUSSED ABOVE, THE BOILING WATER IN THE SHELL KEEPS THE COOLING PASS TUBES FROM OVERHEATING. IF THE WATER LEVEL IN THE BOILER DROPS BELOW THESE TUBES, THE HOT COMBUSTION GAS INSIDE WILL DESTROY THE TUBES. ALTHOUGH LOW LEVEL SHUTDOWN SHOULD ACTIVATE THE SRU ESD IF THE WATER LEVEL FALLS TO 75 MM ABOVE THE COOLING PASS TUBES, THE LOW LEVEL ALARMS IN THE DCS ARE EARLY WARNINGS OF BFW LOSS. THESE LOW LEVEL ALARMS SHOULD RECEIVE IMMEDIATE ATTENTION TO MINIMIZE THE POTENTIAL FOR DAMAGE TO THE BOILER. THE LEVEL GAUGES SHOULD ALSO BE MONITORED CLOSELY BY THE OUTSIDE OPERATOR.
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SULFUR BLOCK
9.5
Instrumentation and Control Systems
9.5.1
SRU Air:Acid Gas Ratio Control Loop The chemistry of the Claus reaction dictates that optimum sulfur recovery is achieved when the ratio of hydrogen sulfide (H2S) to sulfur dioxide (SO2) in the process gases is maintained at 2:1. This ratio is determined by the amount of H2S in the acid gas feed that is combusted to SO2 by the oxygen in the process air stream fed to the burner. Each sulfur plant uses a combination of feed-forward and feed-back control to adjust the ratio of the air flow rate to the acid gas and fuel gas flow rates and maintain the optimum 2:1 H2S:SO2 ratio. The loop diagram on page 9-29 illustrates the components of this control scheme when implemented in a distributed control system (DCS). (All of the instrument tag numbers used below refer to the instruments as they are numbered in the Train 1 SRU. The control algorithm and the relay settings for the Train 2 SRU will be identical.) The feed-forward portion of the control loop uses the acid gas and fuel gas flow rates to compute the setpoint for the air flow controller, A2-FIC15370. Since the amine acid gas, SWS gas, and fuel gas require different amounts of air, the three flow rates are metered separately and then summed by A2-FY15345 and A2-FY15349. The three signals are also biased (by A2-FY15320, A2-FY15331, and A2-FY15355) to allow for the differences in air requirements. In this manner, the setpoint for A2-FIC15370 will be properly adjusted as the individual gas flow rates vary. A special photometric analyzer samples the process gas in the sulfur plant tailgas to determine the relative amounts of H2S and SO2 in the gas. The analyzer provides an output signal that is proportional to the amount the air flow rate must change in order to bring the H2S:SO2 ratio to the optimum 2:1 value. This signal is the feed-back part of the control loop, and is used to make minor adjustments to the air:acid gas ratio and allow the control system to respond to compositional variations in one or more of the acid gas feeds. The control loop is discussed in detail in the sections that follow. The discussions are divided into five sections: air requirement computation for the acid gas streams, air:acid gas ratio adjustment, air requirement computation for fuel gas, air flow control, and local/remote control.
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SULFUR BLOCK 9.5.1.1
Air Requirement Computation for the Acid Gas Streams The purpose of the acid gas bias/summing circuit is to compute the theoretical process air required for the acid gas streams, properly adjusted to account for the differing amounts of oxygen that the two streams require. The amine acid gas and SWS gas flow rate signals are linearized and input to the DCS by A2-FT15320 and A2-FT15331, respectively. Flow indicators A2-FI15320 and A2-FI15331 in the DCS indicate these flow rates in engineering units. Each flow rate is multiplied by a scale factor (relays A2-FY15320 and A2-FY15331, respectively) to compute the process air required by each stream, then added together by summing relay A2-FY15345 to give the theoretical air flow requirement for the acid gas streams. The two bias calculation blocks multiply each gas flow rate by a gain factor equal to the process air required per unit of flow for that stream. The appropriate gain factors are 2.563 Nm3/Nm3 for the amine acid gas (A2-FY15320) and 2.186 Nm3/Nm3 for the SWS gas (A2-FY15331). A2-FY15345 then sums the two outputs from the bias relays, providing an output that (at design conditions) is equal to the required air flow rate for the acid gas streams. This output is then supplied to the ratio adjustment relay, A2-AY15348. These factors can be revised periodically if changes in feedstocks, etc. cause long-term changes in the compositions of one or both of the acid gas streams. Note that each bias relay has a "zero" switch (A2-HS15320 for A2-FY15320 and A2-HS15331 for A2-FY15331). These switches can be used to "turn off " their respective relays when there is no flow of the corresponding gas stream. This prevents an erroneous reading from a flow transmitter causing errors in the theoretical air flow computations. A similar switch (A2-HS15356) is included for the fuel gas bias relay (A2-FY15355) discussed in Section 9.5.1.3.
9.5.1.2
Air:Acid Gas Ratio Adjustment By choosing the appropriate gain factors for A2-FY15320 and A2-FY15331, the output from A2-FY15345 (the theoretical air flow rate) is equal to the required process air flow rate for the acid gas streams, assuming the composition and conditions of the amine acid gas and SWS gas streams remain constant. This will seldom be true, however, so there must be a means to adjust the air:acid gas ratio for temporary changes in composition, such as increased
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK hydrocarbon content. This is the reason for including the ratio adjustment relay, A2-AY15348. The "coarse" ratio adjustment is set manually by the DCS operator in the range of 0.0-2.0 via A2-HIC15347. This ratio setting is then "fine tuned" by the air demand controller, A2-AIC15347. The action of limit relay A2-AY15347 is to allow A2-AIC15347 to vary the "coarse" ratio setting up or down by about 10%, so that the controller acts as a "trim" on the control loop. This is accomplished with two calculation blocks: bias relay A2-AY15347 and summing relay A2-HY15347. The bias relay, A2-AY15347, reduces the magnitude of the A2-AIC15347 output signal and centers it around zero by multiplying the signal by a gain factor of 0.002 and adding a constant of -0.1. Thus, as the output from A2-AIC15347 varies from 0% to 100%, the output from A2-AY15347 will vary from -0.1 to +0.1. Summing relay A2-HY15347 then adds this output to the output from A2-HIC15347 to yield the ratio adjustment setting that is input to A2-AY15348 and indicated by A2-HI15347. The ratio adjustment relay, A2-AY15348, multiplies the ratio adjustment setting from A2-HY15347 by the theoretical air flow rate from A2-FY15345 to produce the corrected air flow rate for the acid gas streams. The effective ratio at A2-AY15348 will vary from 0.0 to 2.0 as the output from A2-HY15347 varies from 0.0 to 2.0. For example, if the output from A2-HY15347 is 1.1, the effective ratio applied to the theoretical air flow by A2-AY15348 will be 1.1, and the corresponding corrected air flow rate will be 1.1 times the theoretical air flow rate. The output from A2-AY15348 (the corrected air flow rate for the acid gas streams) is then supplied to the fuel gas summing relay, A2-FY15349. The design setting for A2-HIC15347 is 1.0 (i.e., a ratio adjustment multiplier of 1.0, which is no adjustment). 9.5.1.3
Air Requirement Computation for Fuel gas If an SRU is operating at very low load, it may be necessary to burn supplemental fuel gas in its Acid Gas Burner. When operating in this mode, the air flow control scheme must also add the air required to burn the fuel gas. Since most fuel gas has a nearly constant composition, it is not necessary to adjust the air:fuel gas ratio like it is with the acid gas streams. Instead, the fuel gas flow rate can simply
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SULFUR BLOCK be multiplied by a gain factor to compute its air requirement, then summed together with the corrected air flow described earlier that is computed by A2-AY15348. The fuel gas flow rate is linearized and input to the DCS by A2-FT15355. Flow controller A2-FIC15355 in the DCS converts this linear signal into a flow rate in engineering units. Bias relay A2-FY15355 then multiplies the fuel gas flow rate by the appropriate gain factor for this fuel gas, 32.509 Nm3/Nm3 (For the C4 LPG), to give the computed air flow for the fuel gas. This is added to the corrected air flow for the acid gas streams by summing relay A2-FY15349, giving the total air flow rate that is then supplied to the air flow controller, A2-FIC15370, as a remote setpoint. For reference, the total theoretical air flow requirement is also computed and displayed in the DCS. This is accomplished by summing relay A2-FY15346, which sums the theoretical air flow rate for the acid gas streams (the output from A2-FY15345) with the theoretical air flow rate for the fuel gas (the output from A2-FY15355). The output from A2-FY15346 is the total theoretical air flow requirement, which is displayed on A2-FI15346 in the DCS. 9.5.1.4
Air Flow Control All of the complicated parts of the control loop are contained in the calculation blocks discussed above. The resulting output from A2-FY15349 is the required air flow rate, so it is simply supplied to the air flow controller, A2-FIC15370, as its setpoint. A2-FIC15370 is a standard PID controller with remote setpoint adjustment. Its output controls the Process Air Blower suction valve, either A2-FV15333A on A2-GB1530A or A2-FV15333B on A2-GB1530B. Note that the signal from A2-FIC15370 actually controls A2-FV15333A or A2-FV15333B together with the control valves on the blower discharge lines using split ranges. This split-range action is discussed in later sections as its details are not important to this discussion.
9.5.1.5
Local/Remote Control The initial startup of an Acid Gas Burner is performed by an outside operator stationed at the local control panel near the burner. Since the operator must be able to control the air flow rate while purging
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SULFUR BLOCK the furnace and lighting the burner, a hand controller (A2-HIC15370) is mounted on the local Train 1 SRU control panel to allow manual control of the air flow valve, A2-FV15333A or A2-FV15333B, and the other blower control valves. After startup, control is then switched back to the DCS. A2-HS15370 in the DCS selects whether A2-FV15333A/B is controlled by the local operator or by the controller in the DCS, A2-FIC15370. During startup, when the outside operator has control, A2-HS15370 is positioned such that the signal from A2-HIC15370 is supplied to A2-FV15333A/B. When the DCS operator is ready to assume control, the output of A2-FIC15370 can be matched to that of A2-HIC15370 (as indicated by A2-HI15370 in the DCS) and A2-HS15370 repositioned to send the output of A2-FIC15370 to A2-FV15333A/B, resulting in a "bump-less" transfer.
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SULFUR BLOCK
Air:Acid Gas Ratio Control Loop (SRU Train 1)
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SULFUR BLOCK 9.5.2
Acid Gas Burner Management System The burner management system (BMS) for the Acid Gas Burner in each SRU is controlled by a sequential logic controller (most commonly a programmable logic controller or PLC). The ESD reset, BMS, and Startup/Run Logic Flowcharts for the Train 1 SRU, contained in the Instrumentation and Controls Diagrams section of the Basic Engineering Package, describe the sequence of steps required before permitting ignition to ensure a safe firing order. The function of the various system components is described below. (All of the instrument tag numbers used below refer to the instruments as they are numbered in the Train 1 SRU. The logic for the Train 2 SRU is identical.)
9.5.2.1
Startup/Run Interlocks The "startup" and "run" interlock logic for the Train 1 SRU is shown on the Startup/Run Logic Flowcharts. The purpose of this logic is to simplify lighting the Acid Gas Burner and switching to acid gas firing in the Train 1 SRU by automatically positioning the process gas switching valves in the proper sequence for safe operation:
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(1)
Before attempting ignition of the burner, the catalyst beds should be bypassed so that air cannot reach them and cause sulfur fires. Setting selector switch A2-HS15314 on the local Train 1 SRU control panel to "STARTUP" will open the two Warmup Bypass Valves, A2-HV15441 and A2-HV15454, close the Tailgas Valve to the TTO, A2-HV15457, and close the Tailgas Valve to the TGCU, A2-HV15462, so that air and/or combustion products from the Reactor Furnace are diverted upstream of the first catalyst bed in the Reactor to flow directly to the TTO.
(2)
Once the pilot burner in the Acid Gas Burner has been lit and the SRU is ready to accept acid gas (furnace up to temperature, etc.), the Warmup Bypass Valves must be closed before acid gas can be introduced into the SRU. However, in order to avoid activating the "complete flowpath interlock" alarm and possibly tripping the Reactor Furnace high-high pressure S/D, there must be an open flowpath through the SRU before the bypass valves are closed.
(3)
Setting selector switch A2-HS15314 to "RUN" will automatically open the Tailgas Valve to the TTO, prove the valve open, then
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SULFUR BLOCK close the two bypass valves and initiate the nitrogen purge, A2-HV15453, between the two valves. By automating the valve switching steps and including checks of the limits switches in the logic, the chance of accidentally causing an SRU1 ESD due to over-pressure during startup are greatly reduced. While the switching valves are moving, the corresponding status lights on the local Train 1 SRU control panel should blink to provide feedback to the operator. If a switching valve does not move to the proper position, its status light should continue to blink. This will alert the operators to investigate the problem and take any required corrective action so that the BMS then allows proceeding. 9.5.2.2
Flame Scanners The flame scanners, A2-BE15369A and A2-BE15369B, monitor the pilot, warmup, and acid gas burners. If a scanner detects a flame, the associated "flame proven" signal will indicate. If neither scanner detects a flame, the SRU1 ESD system is activated. Since a "flame proven" signal from either scanner satisfies the ESD system, maintenance may be performed on one flame scanner while the other remains in service. Note that a third flame scanner, A2-BE15368, is furnished with the pilot to detect its flame, but it is used only to activate its status light (A2-GL15368) on the local Train 1 SRU control panel and a status indicator (A2-BL15368) in the DCS.
9.5.2.3
Purge Cycle To ensure the unit is safe for firing, a purge cycle must be completed before the pilot can be ignited. To purge the Reactor Furnace, a Process Air Blower is used to send a high flow rate of air through the furnace for 25 seconds to satisfy the purge timer. The air flow must then be reduced to a low rate to allow ignition of the pilot.
9.5.2.4
Ignition Cycle After the purge cycle is complete, pressing the "IGNITION" push-button (A2-HPB15368) on the local Train 1 SRU control panel causes the BMS to initiate an attempt to ignite the pilot. The BMS closes the pilot burner purge gas valve (A2-HV15381), opens the pilot air block valve (A2-NV15367), closes the vent valve in the fuel gas to the pilot (A2-NV15364), opens the pilot fuel gas block valves,
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SULFUR BLOCK (A2-NV15363 and A2-NV15365), and energizes the ignition system, (A2-BX15368). After a 15 second ignition trial, the ignition system is de-energized. If a pilot flame is established, one or both flame scanners will indicate "flame proven" and the block valves in the air and fuel gas supplies to the pilot will remain open. Otherwise, the air and fuel gas supplies to the pilot are blocked-in and the purge cycle must be repeated. 9.5.2.5
Fuel gas Firing After the pilot burner is lit, the main fuel gas supply is enabled. Pressing push-button A2-HPB15391 on the local Train 1 SRU control panel will close the main burner purge gas valve, (A2-HV15382), close the vent valve in the fuel gas to the main burner (A2-NV15358), and open the main fuel gas block valves (A2-NV15357 and A2-NV15359). The fuel gas control valve (A2-FV15355) can then be adjusted using either A2-HIC15355 on the local SRU control panel or A2-FIC15355 in the DCS to manually fire fuel gas on the warmup burner ring in the Acid Gas Burner to heat the refractory in the Reactor Furnace and heat the water in the Waste Heat Reclaimer and Sulfur Condenser.
9.5.2.6
Acid Gas Firing After the pilot burner is lit, the acid gas controls can also be enabled. Turning startup/run selector switch A2-HS15314 on the local Train 1 SRU control panel to "RUN" will open the Tailgas Valve to the TTO, A2-HV15457, prove it open, then close the two Warmup Bypass Valves, A2-HV15441 and A2-HV15454, and establish a nitrogen purge between them. Turning acid gas firing selector switch A2-HS15315 on the local Train 1 SRU control panel to "ENABLED" will then allow using the manual acid gas controls, A2-HIC15320 and A2-HIC15331, on the local Train 1 SRU control panel to introduce amine acid gas and SWS gas, respectively, into the Train 1 SRU.
9.5.2.7
Pilot and Main Fuel gas On/Off Switches Push-buttons A2-HPB15390 and A2-HPB15391 on the local Train 1 SRU control panel are used to turn the pilot burner and main fuel gas burner, respectively, on and off. If the burner is already "on", pressing its push-button will extinguish the burner by closing the two block valves and opening the vent valve in its fuel gas supply, and
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SULFUR BLOCK then open the valve in its purge gas supply to begin purging the burner. For the pilot burner, the block valve in its air supply is also closed and the ignition system, A2-BX15368, is de-energized. If the burner is "off " (and the "flame proven" is already satisfied by one of the other burner tips), pressing its push-button will ignite the burner by closing the valve in its purge gas supply to cease purging the burner, and closing the vent valve and opening the two block valves in its fuel gas supply. For the pilot burner, the block valve in its air supply is also opened and its ignition system, A2-BX15368, is energized for 15 seconds.
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SULFUR BLOCK 9.5.3
Process Air Blower Controls The depiction of the controls for the Process Air Blower (A2-GB1530A/B) shown on P&ID 507000-7100-23 is fairly straightforward in how the control elements are to be arranged. What may not be clear, however, is why the controls are implemented in this manner. The discussion that follows will describe what purposes these controls serve. (The Train 1 SRU blower controls for A2-GB1530A are used as examples below. The concepts for the "B" blower and for the Train 2 SRU blower controls are the same.) In general, the process air flow to the Train 1 SRU is controlled at a specified ratio to the acid gas and fuel gas flows by A2-FIC15370. A2-FIC15370 is given a remote setpoint computed from the amine acid gas flow rate, the SWS gas flow rate, the fuel gas flow rate, and the air demand reading. A2-FIC15370 then adjusts the blower suction valve, A2-FV15333A, to control the desired air flow rate.
9.5.3.1
Blower Operation at Low Air Flow At low flow rates, the air flow can drop below the blower's surge line. If this is allowed to occur, the air flow will become erratic and the blower may be damaged. To prevent this from happening, the blower is equipped with a blow-off valve, A2-FV15335A, on its discharge line. When the air flow to the SRU is low, the blow-off valve will open and allow some of the air from the blower to vent to the atmosphere, increasing the air flow through the blower to keep it above the surge line. The discharge pressure from the air blower depends on the back-pressure from the SRU, the TGCU, and the TTO, which is a function of plant throughput. At low plant throughput, the pressure drop through these units is low and the resulting back-pressure on the air blower is low. If the back-pressure gets low enough, it can limit the air flow through the blow-off valve and cause the blower to drop below its surge line. To prevent this from happening, the air blower discharge valve, A2-FV15334A, is designed to begin throttling the blower discharge at very low flow rates, so that the discharge pressure from the blower will remain high enough to allow the blow-off valve to keep the blower from surging. The three valves on the A2-GB1530A blower operate together over the following controller ranges to give the response described above:
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SULFUR BLOCK A2-FV15333A:
Fully open at 100% output from A2-FIC15370 33.3% open at 0-66.7% output from A2-FIC15370 (software "min. stop" keeps valve from closing further)
A2-FV15334A:
Fully open at 100% output from A2-FIC15370 Fully closed at 0% output from A2-FIC15370
A2-FV15335A:
Fully closed A2-FIC15370
at
66.7-100%
output
from
Fully open at 0% output from A2-FIC15370 This results in the following actions by the blower control valves: 1.
At 100% output from A2-FIC15370, the suction valve and discharge valve will be fully open, the blow-off valve will be fully closed, and all of the air will be flowing to the SRU.
2.
As the output from A2-FIC15370 drops from 100% to 66.7%, the suction valve will begin throttling from 100% open to 33.3% open, the discharge valve will begin closing and going from fully open to throttling at 66.7% open, the blow-off valve will still be fully closed, and all of the air will still be flowing to the SRU.
3.
As the output drops below 66.7%, the suction valve will not close any further (to prevent starving the blower for air), the discharge valve will continue to throttle, and the blow-off valve will begin to open and vent part of the air to the atmosphere instead of flowing to the process.
4.
At 0% output, the suction valve will still be 33.3% open, the discharge valve will be fully closed, the blow-off valve will be 100% open, and all of the air will be venting rather than flowing to the SRU. These split-range control actions are accomplished by the function relays in the DCS shown on the P&ID. For the A2-GB1530A blower, the actions of the relays are as follows: A2-FY15333A:
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For an input of 66.7-100%, the output from this relay varies linearly from 33.3-100%. For an input below 66.7%, the output is constant at 33.3% (minimum output limit).
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SULFUR BLOCK A2-FY15334A:
For an input of 0-100%, the output from this relay is direct.
A2-FY15335A:
For an input of 0-66.7%, the output from this relay varies linearly from 100% to 0%, providing reverse action for the fail-closed control valve. For an input above 66.7%, the output is constant at 0%.
The output signals from the DCS to each of the control valves should be displayed on the DCS console. The I/P transducers mounted on the valves in the field are direct (i.e., 4-20 mA to the transducer gives an output of 0-100% from the valve positioner). The split-range values on the P&IDs are the suggested initial settings for the control schemes on these blowers. These values may need adjustment once the SRUs are placed in operation, depending on the operating characteristics of each particular air blower and its control valves. These adjustments can be made during plant startup. 9.5.3.2
Blower "Swapping" Controls While the SRUs are operating, it is sometimes necessary to "swap" air blowers for maintenance purposes, etc. This means switching from A2-GB1530A to A2-GB1530B or vice versa in the Train 1 SRU, for instance. The DCS provides controls for slowly reducing the air flow from the on-line blower while increasing the air flow from the off-line blower, so that switching from one blower to the other can be accomplished without disturbing SRU operations. (Although we have attempted to automate this concurrent ramping operation on a couple of past projects, we have not found this to be very satisfactory. The way that the blower controls need to be ramped will depend on the current plant throughput and whether or not the blower suction valve is still in control. This is classic "fuzzy logic", something that is easy for a human to do but very difficult for a computer.) Bias controller A2-HIC15339A and bias relay A2-HY15339A in the DCS adjust the controller output to the control valves on A2-GB1530A. A setting of 1.0 on A2-HIC15339A results in multiplying the output of A2-FIC15370 by 1.0 before sending the signal to the valves on A2-GB1530A (i.e., no change). A setting of 0.0 on A2-HIC15339A results in multiplying by 0.0, so zero signal is sent to the valves on A2-GB1530A (resulting in all its air venting to atmosphere with no air flow to the process). At settings between 0.0
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SULFUR BLOCK and 1.0 on A2-HIC15339A, the output to the valves on A2-GB1530A is the corresponding fraction of the output from A2-FIC15370. The bias controllers and relays (A2-HIC15339B and A2-HY15339B) for the other blower (A2-GB1530B) work in the same fashion. With these controls in the DCS, it is a relatively simple matter to swap air blowers by gradually shifting the air flow control from one blower to the other. After the off-line blower has been started, the DCS operator can begin to reduce the control signal to the on-line blower while increasing the control signal to the off-line blower, making changes as needed to maintain a stable air flow to the SRU. Once all of the control signal is going to the off-line blower and none is going to the on-line blower, the off-line blower has become the on-line blower. What was the on-line blower is now the off-line blower, and it can then be shut down without affecting the SRU. 9.5.3.3
Blower Start Interlocks and Controls The interlocks and control actions for starting a Process Air Blower are shown on the BMS Logic Flowchart contained in the Instrumentation and Controls Diagrams section of the Basic Engineering Package. These interlocks and actions ensure that these blowers are started in a safe manner while minimizing the starting load on the blowers and motors:
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a.
It is best to start a blower in an unloaded condition, with its suction valve partially open and its blow-off valve wide open. The "blower start permissive" relays, A2-HSL15338A/B, require that the control signal to the blower in question be set to 0% in order to start that blower. As described earlier in Section 9.5.3.1, this will place the suction valve and blow-off valve in the proper positions.
b.
There is always the potential to have acid gas in the process air piping, so having the blower suction and blow-off valves open while its blower is not running should be minimized to reduce the risk of releasing acid gas to the atmosphere. When the operator presses the "permit to start" push-button, A2-HPB15338A/B, for a blower, its suction and blow-off valves will open for 30 seconds to allow time for the operator to start the blower using the local start/stop control.
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SULFUR BLOCK If the blower is not started within this time, the suction and blow-off valves are closed and the "permit to start" is disabled. The operator will have to press A2-HPB15338A/B again before the blower can be started. c.
If the operator starts the blower and the motor starter contacts for the blower indicate that the blower is running within this time, the solenoid valve on the blower discharge valve is then energized so that the operator can increase the control signal to the blower to open the discharge valve and commence air flow to the process. The solenoid valve for the fail-closed discharge valve on each blower is not energized unless that blower is running. This minimizes the potential to have acid gas "back down" the process air line and be released to the atmosphere.
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SULFUR BLOCK 9.5.4
Reactor Furnace Temperature Control The temperature in the first combustion zone of each Reactor Furnace, A2-BA1530 and A2-BA1540, must be 1370°C [2500°F] or higher to insure maximum ammonia destruction. The temperature in each furnace can be controlled at this value by varying the amount of amine acid gas bypassing its Acid Gas Burner, A2-BA1531 or A2-BA1541, respectively. Increasing the portion of bypassed acid gas increases the flame temperature at an Acid Gas Burner, which is the opposite of what would be expected for typical burner systems. However, remember that an Acid Gas Burner operates at substoichiometric conditions - combustion is limited by the amount of process air provided, not by the amount of acid gas (i.e., the fuel) at the burner. The process air rate is determined by the total acid gas inlet flow rate to an SRU, not by the amount of acid gas routed to its burner. Claus plant operation is based on converting one-third of the H2S in the total feed gas to SO2 at the burner. Any hydrocarbons and ammonia present are also oxidized, but the rest of the H2S passes through un-oxidized. Bypassing some of the acid gas around the burner permits combustion of a larger fraction of the H2S in the feed to the burner, resulting in a higher flame temperature. For a simplified example, consider the case where there is no SWS acid gas flow. Without any amine acid gas bypassed, only 33% of the H2S at the burner would be burned. If one-third of the total amine acid gas bypasses the burner, then 50% of the H2S in the amine acid gas sent to the burner must be burned in order to convert one-third of the total H2S to SO2. Thus, a larger fraction of the H2S entering the burner is combusted when part of the acid gas bypasses the burner, which raises the flame temperature. The furnace temperature control loop for the Train 1 SRU consists of: the optical pyrometer, A2-TT15375; the Reactor Furnace temperature controller, A2-TIC15375; the acid gas bypass flow ratio controller, A2-FFIC15350; the acid gas valve to the burner, A2-FV15351, and the acid gas bypass valve, A2-FV15350. (Note that an optical pyrometer does not actually measure temperature. Instead, it infers the furnace temperature by measuring the infrared radiation inside the Reactor Furnace. Experience has shown that the temperature indicated by an
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SULFUR BLOCK optical pyrometer is usually 100-200°C lower than the calculated temperature for a given set of conditions.) The furnace temperature is not directly controlled. Instead, it is controlled indirectly via remote setpoint adjustment of A2-FFIC15350. (Past experience has shown that measurement of the front zone temperature using optical pyrometers is not always consistent and/or repeatable, and flow ratio control of the bypass amine acid gas has proven to be more stable for control purposes.) By placing A2-FFIC15350 in "cascade", A2-TIC15375 can adjust its ratio setpoint within the range of 0.00:1 to 0.65:1. Thus, if the temperature in the first zone of the Reactor Furnace is too low, A2-TIC15375 will raise the ratio setpoint of A2-FFIC15350, which will then bypass more amine acid gas around the Acid Gas Burner and raise the furnace temperature. The 1370°C furnace temperature for ammonia destruction discussed earlier is a calculated temperature. As stated earlier, the temperature indicated by an optical pyrometer is usually 100-2300°C lower than the calculated temperature for a given set of conditions, so a normal operating temperature of 1200°C as indicated by the pyrometer is suggested for the first zone in the Reactor Furnace. Operating experience will dictate the minimum indicated furnace temperature at which SWS gas can be admitted to the furnace. When the Train 1 SRU is operating at low flow rates, there may not be enough pressure drop in its Acid Gas Burner to give good control of the bypass acid gas with A2-FV15350. For this reason A2-FV15351 is designed to work together with A2-FV15350 over split ranges of the A2-FFIC15350 controller output. If A2-FV15350 goes fully open at lower flow rates, the controller output will continue to increase so that A2-FV15351 begins to "throttle" in the amine acid gas line to the burner and force more of the acid gas to flow through A2-FV15350. It is critical that A2-FV15351 never closes completely, as there should always be some amine acid gas flowing to the burner to be sure that the front zone of the Reactor Furnace does not become an oxidizing atmosphere. The DCS limit relay, A2-FY15351, will prevent this fail-open valve from closing completely by limiting the output to the valve to 75% and below.
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SULFUR BLOCK 9.5.5
Knock-Out Drum Pump Control Under ordinary conditions, little (if any) liquid will drop out in the Acid Gas Knock-Out Drum, A2-FA1530. During upsets, however, liquid can rapidly accumulate in the drum. For this reason, the Acid Gas Knock-Out Drum Pump, A2-GA1530A/B has been designed to automatically start and stop as required by the liquid level in the drum, based on the level signal sent to the DCS. Level signals are provided to the PLC by three LTs for use as a 2oo3 voting shutdown if the level continues to rise. The local H-O-A switches near the pumps allow the operator to place these pump in "auto" start mode. The DCS should start the pump when the liquid level reaches the "pump start" level in the drum. After the liquid is pumped out, the DCS should stop the pump when the level reaches the "pump stop" level. If the pump fails to start, or the liquid level is rising faster than the pump can keep up with, the DCS should give a LAH. If the level continues to rise, the PLC will activate the SRU ESD system when the level reaches the LAHH setpoint to prevent carry-over of liquids into the Acid Gas Burner and the Reactor Furnace. If the pump fails to stop, the DCS should give a LAL. Similarly, little (if any) liquid will drop out in the SWS Gas Knock-Out Drum, A2-FA1531 under normal conditions. It can also have liquids accumulate rapidly during an upset, however, so the SWS Gas Knock-Out Drum Pump, A2-GA1531A/B has also been designed to automatically start and stop as required by the liquid level in the drum, based on the level signal sent to the DCS. Level signals are provided to the PLC by three LTs for use as a 2oo3 voting shutdown. The local H-O-A switches near the pumps allow the operator to place these pumps in "auto" start mode. The DCS should start the pump when the liquid level reaches the "pump start" level in the drum. After the liquid is pumped out, the DCS should stop the pump when the level reaches the "pump stop" level. If the pump fails to start, or the liquid level is rising faster than the pump can keep up with, the DCS should give a LAH. If the level continues to rise, the PLC will close the SWS gas inlet valve when the level reaches the LAHH setpoint to prevent carry-over of liquids to the Acid Gas Burner. If the pump fails to stop, the DCS should give a LAL.
9.5.6
"Ride-Through" System Considerations Field experience has shown that a brief interruption in the electric power to a typical air blower will not cause a substantial drop in the air flow as
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SULFUR BLOCK long as power is restored before the blower "spins down" too much. The rotors in Process Air Blowers have relatively large moments of inertia so it takes a relatively long time (usually many seconds) for the rotational speed to decline to the point that the air flow drops enough to extinguish the flame in the associated burner. It is possible to take advantage of this phenomenon by including provisions in the emergency shutdown (ESD) systems that will allow the blowers in the SRUs to "ride-through" momentary power interruptions. If power is restored quickly enough, the blower in a unit will come back up to speed before enough air flow is lost to cause a "flame failure" shutdown, so that the unit will not have to be restarted. If the power loss lasts long enough, of course, the unit will shut down on "flame failure" and will have to be restarted manually. For power "blips", however, there is a good chance the unit will stay on-line. In order for the blowers to "ride-through", the motor starter circuit must include an auxiliary contact that is held-in during a power outage, so that if power is restored the starter contactor will re-engage. The generic motor starter schematic below shows one way of accomplishing the "ride-through".
The key features on the schematic are: There is a "run permissive" contact from the PLC in the main power supply to the starter circuit. If the unit ESD is activated for any reason ("flame failure", for instance), this contact opens so that the blower is
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SULFUR BLOCK stopped. If the ESD is activated during a power interruption, the blower will not restart when power is restored because this contact will be open. There is a "ride-through" contact from the PLC that parallels the usual "m" latch relay in the starter circuit. The PLC closes this contact when it receives the "run" status from the blower. If power is restored before the ESD is activated, this closed contact allows the starter contact to re-engage and restore the "m" latch to keep the motor going. The start/stop control for the motor is interlocked, and has a momentary "start" contact and a maintained "stop" contact. This ensures that the blower remains off when an operator stops a blower using its local start/stop control station, regardless of what the "ride-through" logic may be doing at that time. Within the PLC logic for each ESD system, the "run" status for each blower is connected to a TDO (time delay off) timer set for 10 seconds. Normally-open contacts from the TDO are used in the PLC logic that determines whether a particular blower is running, as well as the logic that determines whether any blowers are running. Thus, if power is lost to a blower and the starter contactor disengages, the TDO contacts will continue to maintain the "blower running" logic as "true" for up to 10 seconds. If power is restored to the blower within this time and the starter contactor re-engages, the ESD logic will remain satisfied and the unit will not shut down. If power is not restored to the blower within this time, the TDO contacts will open and cause the "blower running" logic to become "false" and activate the unit ESD. While the TDO timer is running, all of the unit shutdowns besides "no blower running" are still active. If any of these other shutdowns are tripped, the ESD will be activated immediately to shut down the unit. For example, if the flame is lost in the burner during this time, "flame failure" will activate the ESD and the unit will shut down immediately. Among other things, the ESD will then remove the "run permissive" from the blowers so that the blowers cannot restart. The logic for an air blower "run permissive" is similar to the ESD logic for that ESD system, but there are a couple of key differences. First, each unit ESD includes all of the shutdowns, while the "run permissive" does not include the "no blower running" or "flame failure" S/Ds to allow starting an air blower in the first place. Second, the unit ESD requires that the "MANUAL RESET" push-button be pressed to reset the unit ESD, but the
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SULFUR BLOCK "run permissive" is auto-resetting since it must occur before the "MANUAL RESET" push-button is pressed. The auto-resetting should be inhibited for 20 seconds after an ESD event by an internal timer in the PLC to allow time for the 10 second blower "ride-through" relays and timers to time out, plus other inherent time delays such as flame scanner delays and valve travel times.
9.5.7
Boiler Low-Low Level S/D Transmitter Testing Both of the boilers in each SRU (the Waste Heat Boiler and the Sulfur Condenser) have three independent level transmitters connected to the PLC that activate the SRU ESD system before the water level can get low enough to cause tube damage. The shutdown in activated when two out of three transmitters show a low-low level. These transmitters should be tested periodically to determine that they are functioning properly. Since 2oo3 voting is used for the low-low level shutdowns in the SRU ESDs, the level transmitters can be tested one at a time without having to bypass the ESD system. Consider A2-LT15401A on the SRU Train 1 Waste Heat Boiler, for example. The procedure for testing A2-LT15401B and A2-LT15401C will be similar, as will A2-LT15431A/B/C on the Sulfur Condenser. The procedure for testing A2-LT15401A is as follows:
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(1)
The outside operator notifies the DCS operator that he is preparing to test shutdown level transmitter "A" on the Waste Heat Boiler.
(2)
The DCS operator confirms that A2-LI15401B and A2-LI15401C are both indicating adequate level in the boiler, then notifies the outside operator to proceed.
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SULFUR BLOCK
CAUTION
DO NOT PROCEED UNLESS THE OTHER TWO LEVEL INDICATORS SHOW ADEQUATE LEVEL IN THE BOILER. OTHERWISE THE LOW-LOW LEVEL SHUTDOWN IN THE SRU ESD WILL BE ACTIVATED AS SOON AS THE OUTSIDE OPERATOR BEGINS DRAINING THE LEVEL TRANSMITTER IN THE NEXT STEP. (3)
After being notified to proceed by the DCS operator, the outside operator blocks-in A2-LT15401A by closing its block valves, then opens the drain valve on the bottom of the transmitter to drain the water from the instrument.
(4)
If the transmitter is operating properly, the DCS will alarm that there is a low level in the Waste Heat Boiler on A2-LI15401A. The DCS operator acknowledges the alarm on the DCS and reports it to the outside operator.
(5)
After being notified of the alarm, the outside operator closes the drain valve on A2-LT15401A, slowly opens its bottom block valve to allow the transmitter to fill with water then opens its top block valve. This should clear the low level alarm on A2-LI15401A in the DCS.
(6)
After confirming that the low level alarm has cleared, the other level transmitters can be tested in a similar fashion.
NOTE:
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The DCS operator must not begin another task until confirming that the low level alarm has cleared. This is to guard against having a level transmitter malfunction that causes an SRU ESD when the other transmitters are tested.
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SULFUR BLOCK 9.5.8
SRU Emergency Shutdown Systems The purpose of the Sulfur Recovery Unit Emergency Shutdown systems (Train 1 SRU ESD and Train 2 SRU ESD) is to shut off the flow of amine acid gas, SWS gas, fuel gas, and process air to the affected SRU when serious problems occur. The Cause and Effect Diagram for the Train 1 SRU, contained in the Instrumentation and Controls Diagrams section of the Basic Engineering Package, describes the SRU1 ESD system in block format. For reference, the causes and effects of the SRU1 ESD system shown on this diagram are explained below. (All of the instrument tag numbers used below refer to the instruments as they are numbered in the Train 1 SRU. The logic for the Train 2 SRU is identical.) As noted on the Cause and Effect Diagram, it is recommended that a 5 second delay be used for most of the process parameters included in the causes of the ESD system. This is to prevent the "nuisance" shutdowns that are sometimes caused by momentary fluctuations in the process or the sensing elements.
9.5.8.1
Causes Any one of the causes listed below will activate the SRU1 ESD system: d.
Manual Shutdown Switches, A2-HS15310 and A2-HS15313 An operator can activate the SRU1 ESD system using either of two manual shutdown switches: (1)
A2-HS15310 is a NORMAL / ESD selector switch in the DCS.
(2)
A2-HS15313 is a NORMAL / ESD selector switch mounted on the local Train 1 SRU control panel.
(3)
Acid Gas Scrubber A2-LT15305A/B/C
High-High
Liquid
Level,
These devices prevent liquids in the Acid Gas Scrubber from flowing into the hot combustion chamber of the Reactor Furnace and causing an explosion. They are set to actuate if the liquid level reaches 1,280 mm above the bottom seam of the vessel. Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD (i.e., at least two
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SULFUR BLOCK transmitters must show high-high level) to avoid spurious "trips" due to the malfunction of a single transmitter. e.
No Process Air Blower A2-GB1530B starter contacts
Running,
A2-GB1530A
and
If neither Process Air Blower is sending air to the Train 1 SRU, acid gas could flow backwards down the process air line and escape from either the blowers or their suction screens. The motor starter contacts on A2-GB1530A/B are used to determine whether a blower is running, and will activate the SRU1 ESD system if neither blower is running. f.
Acid Gas Burner A2-BY15369B
Flame
Failure,
A2-BY15369A
and
Dual flame scanners are aimed to observe the flames from the pilot, warmup, and main acid gas burners. If neither scanner detects a flame (2oo2), a "flame failure" occurs and activates the SRU1 ESD system. If only one scanner detects a flame (1oo2), a malfunction alarm is activated in the DCS, but the SRU1 ESD system is not activated. A third flame scanner, A2-BY15368, is furnished with the pilot to detect its flame, but it is used only to activate its status light (A2-GL15368) on the local Train 1 SRU control panel and a status indicator (A2-BL15368) in the DCS. g.
Reactor Furnace High-High Pressure, A2-PT15372A/B/C These devices protect against over-pressuring the SRU and blowing out its Sulfur Drain Seal Assemblies (which would emit toxic H2S to the atmosphere) due to plugging by solid sulfur somewhere in the plant, a surge in acid gas flow to the furnace, etc. by activating the SRU1 ESD system before the pressure gets too high. The sensing lines for the pressure transmitters are mounted on the process air line to avoid corrosion and/or plugging with sulfur. The shutdown setpoint is 0.85 kg/cm2(g). Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD.
h.
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Waste Heat Reclaimer A2-LT15401A/B/C
Sulfur Recovery
Low-Low
Water
Level,
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SULFUR BLOCK These devices activate the SRU1 ESD system to prevent the water level from dropping below the top of the cooling pass tubes in this boiler while hot gas is flowing through the tubes. Hot furnace combustion gas flows inside the tubes and will destroy these tubes if they are not cooled by water boiling outside the tubes. These devices are set to actuate if the level falls to within 75 mm of the top of the cooling pass tubes. Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD. i.
Reactor 1st Bed A2-TT15419A/B/C
Outlet
High-High
Temperature,
These devices shut down the Train 1 SRU if a temperature of 400°C or higher is measured at the outlet from the first catalyst bed in the Reactor. Such a temperature would indicate a sulfur fire inside this catalyst bed, which could cause damage by overheating the equipment if allowed to continue burning. Free oxygen can leave the Reactor Furnace and reach this catalyst bed if burner performance becomes poor due to burner damage, low H2S concentration in the acid gas, etc. Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD. j.
Sulfur Condenser Low-Low Water Level, A2-LT15431A/B/C These devices activate the SRU1 ESD system to prevent the water level from dropping below the top of the condensing pass tubes in this boiler while hot gas is flowing through the tubes, thereby averting high effluent temperatures and higher than normal tube wall temperatures. High effluent temperatures would result in lower sulfur recovery due to insufficient condensing of liquid sulfur, and high tube wall temperatures could possibly damage the tubes due to differential expansion. These devices are set to actuate if the level falls to within 75 mm of the top of the condensing pass tubes. Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD.
k.
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Neither Warmup A2-ZSC15454
Bypass
Sulfur Recovery
Valve
Closed,
A2-ZSC15441,
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SULFUR BLOCK Amine acid gas or SWS gas should not be fed to the Train 1 SRU if its warmup bypass line to the TTO is in use. Otherwise, very high concentrations of H2S would be sent to the TTO, possibly leading to a high-high temperature S/D of the TTO and venting of un-combusted H2S to the atmosphere. The "closed" limit switches on the warmup bypass valves (A2-HV15441 and A2-HV15454) must indicate that at least one of these valves is closed, or the SRU1 ESD system will be activated. Note that the SRU1 ESD system is not to be activated if the Train 1 SRU is firing supplemental fuel gas in its Acid Gas Burner. The amine acid gas and SWS gas shutdown valves, A2-HV15320 and A2-HV15331, respectively, are to be closed automatically and an alarm is to be generated, but the ESD system is not to be activated since the Train 1 SRU can continue to fire on fuel gas through its warmup bypass line. Example logic to accomplish this is shown below:
l.
Pilot Ignition Safety Interlock Timer Expired, BMS logic Once the pre-ignition steps have been completed and the BMS gives a "PERMIT TO IGNITE" for the pilot burner in the Acid Gas Burner (signaled by illuminating status indicator light A2-AL15394 on the local Train 1 SRU control panel), an ignition safety interlock timer is started in the BMS. If an ignition attempt is not made within 5 minutes, the SRU1 ESD system will be activated to shut down the sulfur plant. This prevents a potentially unsafe condition from persisting, where a leaking fuel gas valve could cause an explosive mixture to form in the
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SULFUR BLOCK Reactor Furnace, since the air flow is low at this point in the startup procedure. 9.5.8.2
Effects An SRU1 ESD shutdown, activated either manually or automatically, has the following effects on the Train 1 Sulfur Recovery Unit:
Issued 30 August 2011
a.
Shuts off the amine acid gas flow to the Acid Gas Burner by closing the acid gas shutdown valve, A2-HV15320.
b.
Shuts off the SWS gas flow to the Acid Gas Burner by closing the SWS gas shutdown valve, A2-HV15331.
c.
Shuts down the Process Air Blower, A2-GB1530A/B.
d.
Closes the air blower suction valves, A2-FV15333A/B, to prevent possible venting of any hazardous gases to the atmosphere.
e.
Closes the air blower discharge valves, A2-FV15334A/B, to prevent back-flow and possible venting of any hazardous gases to the atmosphere.
f.
Closes the air blower vent valves, A2-FV15335A/B, to prevent possible venting of any hazardous gases to the atmosphere.
g.
Initiates the Train 1 SRU Fuel Gas Burner Shutdown system, which performs the following actions: (1)
Shuts off and depressurizes the main fuel gas supply by closing block valves A2-NV15357 and A2-NV15359 and opening vent valve A2-NV15358.
(2)
Shuts off the pilot air supply by closing block valve A2-NV15367.
(3)
Shuts off and depressurizes the pilot fuel gas supply by closing block valves A2-NV15363 and A2-NV15365 and opening vent valve A2-NV15364.
(4)
De-energizes the ignition system, A2-BX15368.
(5)
Begins purging the pilot burner with nitrogen by opening block valve A2-HV15381.
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SULFUR BLOCK (6)
Begins purging the warmup burner with nitrogen by opening block valve A2-HV15382.
h.
Sends the Train 1 SRU S/D status to the TGCU ESD system. (The TGCU ESD system will shut down the TGCU if neither SRU is running and the TGCU is not in "startup" mode.)
i.
Cancels the "slow transfer over-ride" switch in the DCS, A2-HS15464, for the tailgas valves.
j.
Initiates purging of the Acid Gas Burner, A2-BA1531, and the Reactor Furnace, A2-BA1530, with nitrogen by opening block valve A2-KV15377 for 5 minutes.
When the amine acid gas flow to the Train 1 SRU is blocked, the pressure control system on the stripper in the upstream ARU should automatically divert acid gas to the flare as required. When the SWS gas flow to the Train 1 SRU is blocked, the pressure control system on the stripper in the upstream SWS should also automatically divert SWS gas to the flare as required. 9.5.8.3
Non-ESD Shutdowns and Alarms In addition to the devices listed in Section 9.5.10.1 that activate the SRU1 ESD system, there are several interlocks of significance that either generate an alarm or shut down an individual piece of equipment. These devices/interlocks and their effects are described in this section. a.
SWS Gas Scrubber High-High Liquid Level, A2-LT15325A/B/C These devices prevent liquids in the SWS Gas Scrubber from flowing into the hot combustion chamber of the Reactor Furnace and causing an explosion by closing the SWS gas shutdown valve. They are set to actuate if the liquid level reaches 1,490 mm above the bottom seam of the vessel. Note that there are three independent transmitters and 2oo3 voting logic is used for the S/D. Unlike the level transmitters on the Acid Gas Scrubber, this interlock does not activate the SRU1 ESD system. Instead, it closes only the SWS gas shutdown valve, A2-HV15331, to stop the flow of SWS gas. This valve does not re-open automatically when the level drops down and the shutdown
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SULFUR BLOCK resets. The plant operators must use A2-HIC15331 on the local control panel to open A2-HV15331 to reintroduce SWS gas into the SRU in a controlled fashion. b.
Process Air Blower Operation while in "Startup" Mode During normal operation, activating the SRU1 ESD system will shut down the Process Air Blower and close the suction, discharge, and blow-off valves on the blower. However, if the Train 1 SRU is firing on fuel gas through its Warmup Bypass Valves, the air blower will remain running (with its valves open) if the "flame failure" S/D (see Section 9.5.10.1.f) is tripped or one of the fuel gas pressures is not satisfied (see Sections 9.5.8.3.c and 9.5.8.3.d) All other shutdown devices (see Section 9.5.8.2) go to their shutdown positions. By leaving the air blower running when a fuel gas flame is lost, fewer blower restarts are necessary while re-lighting the burner, resulting in less "wear and tear" on the large motors driving these blowers.
c.
Acid Gas Burner Fuel Gas Supply Low-Low Pressure, A2-PT15354 During warmup while the Train 1 SRU is firing on fuel gas, loss of the fuel gas supply would cause the fuel gas pressure to drop. This device will shut off the fuel gas to the Acid Gas Burner before flame instability creates the potential for an explosion. The shutdown setpoint is 0.35 kg/cm2(g). Note that if the Train 1 SRU is firing on acid gas, the transmitter only activates the Train 1 SRU Fuel gas Burner Shutdown system (pilot fuel gas and main fuel gas), so the Train 1 SRU will continue running on acid gas. If, however, the Train 1 SRU is firing only fuel gas (as indicated by its acid gas firing selector switch, A2-HS15315, being set to "DISABLED"), the SRU1 ESD system is activated and the low-low pressure is reported to the "first out" alarm logic. Example logic to accomplish this is shown below:
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SULFUR BLOCK
d.
Acid Gas Burner Fuel Gas High-High Burner Pressure, A2-PT15361 During warmup while the Train 1 SRU is firing on fuel gas, malfunction of the fuel gas pressure control could cause excessive firing of the warmup burner in the Acid Gas Burner. This device will prevent this unsafe condition by shutting off the fuel gas to the Acid Gas Burner. The shutdown setpoint is 3.5 kg/cm2(g). Note that if the Train 1 SRU is firing on acid gas, the transmitter only activates the Train 1 SRU Fuel gas Burner Shutdown system (pilot fuel gas and main fuel gas), so the SRU will continue running on acid gas. If, however, the Train 1 SRU is firing only fuel gas (as indicated by its acid gas firing selector switch, A2-HS15315, being set to "DISABLED"), the SRU1 ESD system is activated and the high-high pressure is reported to the "first out" alarm logic, as shown by the example logic for the previous item.
e.
Complete Flowpath Interlock (see Logic Flow Diagrams for the limit switch tag numbers) In order for the Train 1 SRU to operate without over-pressuring its drain seals, there must be a complete flowpath from the SRU to the TTO. The ESD logic can determine whether such a complete flowpath exists by examining the status of the limit switches on the process gas valves. There are basically three different paths that the Train 1 SRU can take to reach the TTO:
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SULFUR BLOCK (1)
Both of its Warmup Bypass Valves, A2-HV15441 and A2-HV15454, are fully open to the TTO.
(2)
Its manual tailgas block valve, A2-HV15455, and its Tailgas Valve to the TTO, A2-HV15457, are both fully open to send the tailgas directly to the TTO.
(3)
Its manual tailgas block valve and its Tailgas Valve to the TGCU, A2-HV15462, are both fully open and the TGCU Complete Flowpath Interlock is satisfied, allowing the tailgas to flow through the TGCU and then to the TTO.
If the "open" limit switches do not indicate that at least one of these flowpaths is valid, the "complete flowpath interlock" alarm is activated. However, the SRU1 ESD system is not activated by this interlock. Because this interlock depends on a number of valve limit switches to determine whether a complete flowpath exists, there is always the potential for spurious "trips" even though all of the valves are actually in the proper positions. Since the SRUs are already protected against over-pressure (see Section 9.5.10.1.g), this interlock will alarm in the DCS (A2-QA15458) but is not included in the ESD. To prevent releasing excessive amounts of hazardous gases to the atmosphere from the TTO and/or possibly damaging the Thermal Oxidizer, the interlocks for the Train 1 SRU require that at least one of its Warmup Bypass Valves be closed before opening A2-HV15320 or A2-HV15331 and admitting amine acid gas or SWS gas, respectively, to the Train 1 SRU. Therefore, its Tailgas Valve to the TTO, A2-HV15457, must be open before closing its Warmup Bypass Valves when switching from fuel gas firing to acid gas firing. When the TGCU is already on-line processing tailgas from one of the SRUs, switching the tailgas from the other SRU into the TGCU requires gradually diverting its tailgas from the TTO to the TGCU. For the Train 1 SRU, this requires "throttling" both tailgas valves, A2-HV15457 and A2-HV15462, at the same time to make the switch without upsetting the TGCU. When throttling the tailgas valves in this manner, the limit switches on the valves will be indicating that neither of the tailgas valves is fully open, so the Complete Flowpath Interlock Issued 30 August 2011
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SULFUR BLOCK logic will not be satisfied for the Train 1 SRU. For this reason, there is a "slow transfer over-ride" switch in the DCS, A2-HS15464. When this switch is toggled to "OVER-RIDE", the limit switches on the two tailgas valves are ignored by the Complete Flowpath Interlock logic until the DCS operator finishes routing the Train 1 SRU tailgas into the TGCU to deactivate the over-ride. During this time, the DCS operator is responsible for ensuring that there is always a complete flowpath for the Train 1 SRU.
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SULFUR BLOCK
9.6
Process Principles and Operating Techniques The more important considerations involved in startup, operation, shutdown, maintenance, and emergency procedures for the Sulfur Recovery Units are discussed in the remaining sections of this portion of the operating guidelines. The operator should also be thoroughly acquainted with the equipment and the "Process Description" section in these guidelines before attempting to operate the plant in accordance with the operating techniques that follow. If the function of each portion of the plant equipment is understood, the sequence of steps outlined in the "procedures" sections will be more easily understood. In addition, the following general discussion of principles and techniques will clarify the reasons for some of the procedures.
9.6.1
Equipment Damage The refractory installed in the Reactor Furnaces can be damaged by too rapid heating or cooling. The Initial Cure and Normal Warmup schedules for the refractory should be provided by the refractory vendor. These schedules should be adhered to quite closely. After the initial startup, the sulfur plants will contain some sulfur throughout the system, and especially in the catalyst beds. Sulfur fires will ignite at temperatures as low as 150°C if sufficient oxygen is available. For this reason, it is very important to minimize the time periods when air (or combustion gas containing oxygen) is routed through the catalyst beds. Localized temperatures in excess of 150°C can exist in a catalyst bed even though the temperatures measured around the Reactor are less than 150°C. Because of this, sulfur ignition sometimes occurs in the catalyst beds when it is not anticipated by temperatures that are readily available for observation. Under ordinary circumstances, the only time when oxygen-bearing gases will be flowing through a Reactor is during the transition when switching from firing fuel gas for warmup to firing acid gas. During this time, observe the Reactor temperatures frequently. If the temperatures are rising more than 5°C to 10°C in a 30 minute period after the temperatures have reached 200°C, then there is possibly a fire present. The high temperature shutdown on the outlet of the first catalyst bed in each SRU will protect that SRU against excessive temperatures in its piping; however, localized excessive temperatures can occur in the catalyst beds prior to being indicated in the Reactor outlet lines. Steps should be taken to prevent the temperatures rising high enough to activate the shutdown
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SULFUR BLOCK as it will require some time to cool down the hot spot before proceeding with startup. Do not use water to quickly cool a Reactor after a fire. Not only will this damage the catalyst, the rapid cooling may cause structural damage to the Reactor. The acidic water that forms may cause corrosion damage to the Reactor or other equipment. Nitrogen is available in each SRU for use in cooling a hot catalyst bed. Explosive mixtures of air (oxygen) and gases in the equipment are a potential danger. During an automatic shutdown all air, oxygen, fuel gas, and acid gas flows are shut off simultaneously. Any malfunction of these devices could leak an explosive mixture into the unit. For this reason, the PLC requires purging of the Reactor Furnace before attempting pilot ignition, and requires re-purging the furnace if the burner does not light but fuel gas was admitted.
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SULFUR BLOCK
CAUTION NEVER "HYDROBLAST" THE TUBES (OR ANY OTHER STEEL SURFACES) IN THE SULFUR PLANT EQUIPMENT. NOT ONLY DOES THIS REMOVE THE PROTECTIVE SULFIDE FILM THAT FORMS ON CARBON STEEL AND PREVENTS CORROSION, THE WATER WILL REACT WITH THE SULFUR COMPOUNDS PRESENT IN THE EQUIPMENT TO FORM A VARIETY OF ACIDS (SULFUROUS, POLYTHIONIC, ETC.) THAT RAPIDLY CORRODE THE STEEL. THERE HAVE BEEN NUMEROUS INSTANCES OF SULFUR PLANT BOILERS BEING BLASTED DURING A TURNAROUND TO CLEAN THEM UP, THEN HAVING THE TUBES BEGIN LEAKING AS SOON AS THE BOILER IS RETURNED TO SERVICE. IF THE BOILER TUBES HAVE BECOME PLUGGED, THE BEST WAY TO CLEAR THE TUBES IS TO MECHANICALLY "ROD" THEM. IT IS OFTEN HELPFUL TO APPLY HEAT TO THE TUBES BEFORE "RODDING", AS THIS WILL MELT ANY SULFUR THAT MAY BE PART OF WHAT HAS PLUGGED THE TUBES. ONE WAY TO DO THIS IS TO DRAIN THE WATER FROM THE BOILER AND PUT STEAM ON THE SHELL, THEN DRAIN THE CONDENSATE PERIODICALLY TO KEEP LIVE STEAM ON THE TUBES.
9.6.2
Cold Catalyst Bed Startup Each sulfur plant is designed to be started up without first warming the Reactor catalyst. In the cold bed startup procedure, warmup gases are not routed through the Reactor catalyst beds. Fuel gas is burned with excess air on the warmup burner tips of the Acid Gas Burner mounted on each Reactor Furnace. The hot combustion products flow through the Reactor Furnace, through the Waste Heat Boiler tubes and the first condensing pass tubes of the Sulfur Condenser, and then to the warmup bypass line that is upstream of the first catalyst bed. This warms the furnace refractory lining and the process heat exchange surfaces up to normal operating temperatures.
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SULFUR BLOCK The combustion gases are routed to the atmosphere via the Thermal Oxidizer. Therefore, normal operating procedures require that the Thermal Oxidizer also be warming up according to its refractory warmup schedule (or already be on-line) during the period when the SRU(s) is(are) being brought up to operating temperatures. Do not admit acid gas to an SRU until the Thermal Oxidizer is at operating temperature and ready to accept SRU tailgas. The cold bed startup procedure includes the following steps: A.
Open the Warmup Bypass Valves, and close the Tailgas Valve to the Thermal Oxidizer and the Tailgas Valve to the TGCU. Startup cannot be attempted unless this flow path is open.
B.
Ignite the warmup burner in the Acid Gas Burner and fire on fuel gas with excess air, adjusting air and fuel gas rates to follow the appropriate warmup schedule.
C.
Once the Waste Heat Boiler and Sulfur Condenser start to make steam, their back-pressure controllers should be placed in service. The other tube passes in the Sulfur Condenser and the tube passes in the reactor feed heaters will come up to temperature as these boilers begin producing steam.
D.
When the furnace and all process heat exchangers are warmed up to normal operating temperatures and the Thermal Oxidizer is ready to accept SRU tailgas, reduce the fuel gas and air flow rates. Open the Tailgas Valve to the Thermal Oxidizer, then close the Warmup Bypass Valves. Add amine acid gas and reduce fuel gas in equal increments until the fuel gas is shut off.
E.
Gradually admit the full amine acid gas flow rate. Adjust the air flow to the proper air:amine acid gas ratio. Follow the procedures in these guidelines for introducing SWS gas into the SRU. Gradually admit the full SWS gas flow rate and readjust the air:acid gas ratio if necessary.
There are several advantages to using the cold bed startup procedure. First, the catalyst beds are not exposed to warmup gases containing free oxygen. This reduces the chance of fires in the catalyst bed during warmup, which can cause overheating damage to both equipment and catalyst.
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SULFUR BLOCK Second, the catalyst beds are not exposed to warmup gases that contain free carbon (soot). This reduces the chance of contaminating and plugging the beds with soot. Third, the cold bed startup procedure reduces catalyst sulfation and, therefore, keeps the catalyst active longer. Deactivation has been shown to be caused primarily by sulfate contamination of the catalyst surface. Sulfation occurs most readily at conditions encountered during a startup procedure which uses combusted fuel gas for catalyst heating. An additional benefit of having the warmup bypass line is that a sulfur plant can be kept on hot stand-by, firing on fuel gas, without exposing the catalyst beds to overheating, carbon deposition, or sulfation damage. The hot fuel gas combustion products will keep all process heat exchange surfaces at normal operating temperatures. Since most corrosion damage in sulfur plants occurs when the plants are allowed to cool down and stand cold, using the warmup bypass can greatly extend the service life of sulfur plants which require considerable stand-by time.
9.6.3
Sulfur Solidification Sulfur melts at 119°C. All surfaces in the SRUs must be maintained above this temperature during normal sulfur production operating periods. However, temperatures around the Sulfur Surge Tanks and the Sulfur Storage Tank should be kept below 158°C since sulfur undergoes a phase change at this temperature that can result in a tremendous increase in viscosity, which could overload any of the sulfur pumps. Maintaining the steam coil pressure in the Sulfur Surge Tank and the Sulfur Storage Tank at 5.0 kg/cm2(g) or less will ensure that the sulfur does not get too hot. All of the piping and valves in liquid sulfur service are steam-jacketed, as are the valves in sulfur vapor service and the vent stacks on the Sulfur Surge Tanks. The steam traps serving these heating systems should be checked regularly to verify proper operation. The simplest method to do this is to verify that sulfur will melt on the steam trap inlet; if the condensate there is hot enough to melt sulfur, then the steam in the jackets will be hot enough, too. It is also important to periodically sweep the non-condensibles out of the jackets and coils by giving their vent valves a good "blow". This will prevent the accumulation of non-condensibles that could create localized "cold" spots where sulfur can freeze.
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SULFUR BLOCK 9.6.4
Ammonia Salt Formation Hydrogen sulfide reacts with ammonia at low temperature to form ammonium hydrosulfide: NH3 + H2S
NH4HS
If the temperature is low enough, this ammonium hydrosulfide will precipitate as a solid salt. The temperature at which the solid phase will form is a function of the NH3 and H2S concentrations and the gas pressure, but generally ranges from 15°C to 40°C for most acid gas streams. It is recommended that all surfaces in contact with NH3-H2S be maintained 20-25°C above the solid formation temperature, so all of the equipment, piping, and instruments in the SRUs that is exposed to SWS gas are electric traced, steam traced or steam jacketed to keep them above 65°C.
CAUTION
TO PREVENT PLUGGING OF EQUIPMENT, PIPING, OR INSTRUMENTS WITH AMMONIA SALTS, THE TRACING OR STEAM JACKETING IN CERTAIN SECTIONS OF THE SRUS MUST BE LEFT IN SERVICE YEAR ROUND. THESE ARE ANY PIPING, EQUIPMENT AND INSTRUMENTATION IN SWS GAS SERVICE.
Essentially all of the ammonia in the SWS gas will be destroyed in the Reactor Furnace during normal operation. If, however, amine acid gas flow is interrupted (due to upsets in the ARU, etc.) and the SRUs are processing only SWS gas, the ammonia may not be completely destroyed and salts could begin to form in the downstream equipment (particularly the Sulfur Condensers). Loss of amine acid gas flow can also cause excessively high furnace temperatures, poor sulfur recovery, and poor operation or equipment damage in the TGCU or the Thermal Oxidizer downstream. For this reason, the operator must closely observe the SRUs if their amine acid gas flow is interrupted, and be ready to activate the SRU ESD systems if necessary to prevent equipment damage.
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SULFUR BLOCK 9.6.5
Catalyst Fouling The catalyst beds in the Reactors may be severely fouled by carry-over of hydrocarbon liquids or vapors from the ARU and/or Sour Water Stripper Units into the SRUs. This will cause permanent damage to the catalyst and is to be avoided if at all possible, even if shutting down the SRUs for periods is required. The catalyst may also be fouled by passing fuel gas combustion products through the beds when insufficient air to burn all of the fuel gas is being supplied to the Acid Gas Burner. This causes soot (carbon) formation which coats the catalyst and causes loss of activity. The catalyst beds in this plant will be warmed with fuel gas combustion products only during the initial startup. Excess air will be used during this warmup period, so the chances of fouling the catalyst in this manner are remote. The catalyst may also temporarily lose activity due to molten sulfur condensing on the beds. This can be corrected by raising the Reactor inlet temperatures by approximately 15-20°C for a few hours, then readjusting to the normal operating range. The catalyst activity will be completely restored in this manner by re-vaporizing the deposited sulfur. The reactor feed temperatures can be raised by appropriate adjustment of the temperature controllers on the gas outlet lines from the reheat exchangers.
9.6.6
Operation of SRUs in Parallel Train 1 SRU and Train 2 SRU are designed to operate in parallel with each other to provide maximum acid gas processing capacity. The SRUs are connected at their inlets, with the amine acid gas and SWS gas feedstocks split to flow through the units in parallel. Due to the relatively low pressure drops through the SRUs (normally 0.5-0.7 bar(g) at full rates, when the pressure drop of the associated TGCU is included), operating changes in one unit can significantly impact the other units because of the flow hydraulics. The acid gas flow controls for Train 1 SRU and Train 2 SRU are designed to allow automatic operation of the parallel units in a fashion that maximizes processing capacity and maximizes sulfur recovery efficiency. There are two basic schemes for operating SRUs in parallel: "base-load" operation of all-but-one SRU, or "cascade" operation of all SRUs. Each scheme has advantages and disadvantages relative to the other, depending on the operating characteristics of the particular feed units and
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SULFUR BLOCK SRUs, current operating conditions, and other factors. As a result, the choice of which operating mode to use is best determined based on field experience with the specific units. 9.6.6.1
"Base-Load" Operation on All-But-One SRU One operating mode is to "base-load" all but one SRU, and let the remaining SRU take the "swing." That is, the flow controllers are used to feed a fixed quantity of amine acid gas and/or SWS gas to one SRU, while a pressure controller is used to control the feed valves to the remaining SRU (either directly or via setpoint adjustment of the flow controllers). This mode allows one SRU to operate at steady feed rates, but requires that the remaining SRU take all of the variation in the flow of the amine acid gas and/or SWS gas feed to the sulfur facilities. The main advantage of this operating mode is that the "base-load" SRU has very steady feed gas rates, which in turn allows its air:acid gas ratio control scheme to keep the plant trimmed very close to optimum H2S:SO2 ratio under most circumstances. This means that the sulfur recovery efficiency of the "base-load" SRU is generally very high. The primary disadvantage of this operating mode is that the "swing" SRU can see very large fluctuations in its amine acid gas and/or SWS gas feed rates, since this unit has to take all of the flow variation. Consequently, the sulfur recovery efficiency can be considerably lower for this SRU than for the "base-load" unit because the air:acid gas ratio control scheme on the "swing" unit is unable to keep the plant as close to optimum H2S:SO2 ratio, resulting in wider and more frequent deviations from the optimum ratio. The impact of this disadvantage can be minimized if the total amount of acid gas to be processed is less than the maximum capacity of the units. By setting the "base-load" SRU to process its full capacity, a smaller quantity of acid gas will be processed in the "swing" SRU. This means that a larger portion of the total acid gas is processed in the SRU operating at the higher recovery. Depending on the quantity of SWS gas to be processed, it may be possible to send all of the SWS gas to one of the SRUs and process only amine acid gas in the remaining SRU. In this case, the SRU
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SULFUR BLOCK processing the SWS gas would be operated as the "base-load" unit for amine acid gas. This should give steadier operating conditions for this SRU, allowing better sulfur recovery efficiency and more reliable ammonia destruction in the SRU. And, since the "swing" SRU is processing only amine acid gas, its sulfur recovery efficiency will be higher than for a "swing" SRU processing both amine acid gas and SWS gas. The net result may be higher overall sulfur recovery efficiency for the SRUs than if SWS gas was processed in both the units (although this may not always be the case). 9.6.6.2
"Cascade" Operation of All SRUs The other operating mode is to place both the SRUs in "cascade" operation. Rather than feeding a fixed flow rate to one SRU and forcing the remaining SRU to take all of the "swing", the acid gas can be split in relative proportions between the SRUs. As the amount of available acid gas changes, the feed rates to both the SRUs will be adjusted proportionally. This mode spreads the variations in the flow of amine acid gas and/or SWS gas feed between the SRUs so that no unit is experiencing as much change as when operated as a "swing" unit. However, none of the units is operating on steady flow rates, as both the units must absorb the fluctuations in flow from the feed units. The primary advantage of this operating mode is that no SRU is experiencing large variations in feed flow rates, so there is less variation in sulfur recovery efficiency compared to operating as a "swing" SRU. This operating mode is generally also more reliable when the amount of SWS gas to be processed is high enough that both the SRUs must process SWS gas. The main disadvantage of this operating mode is that none of the units is processing at steady feed rates, so neither SRU can maintain its sulfur recovery efficiency as high as it can when operating as a "base-load" SRU. If the feed units are producing acid gas at reasonably steady rates, however, the magnitude of this loss in sulfur recovery efficiency from operating with both the SRUs in "cascade" mode can be relatively minor. The overall sulfur recovery efficiency for the SRUs as a whole will depend on how much acid gas is to be processed, the relative amounts of amine acid gas and SWS gas to be processed, relative catalyst activities within
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SULFUR BLOCK the reactors of the plants, and many other factors. As a result, the choice of which operating mode to use will often depend on the particular circumstances at any given time. As operating experience is gained with the units, past experience will probably serve as the best tool for choosing the operating mode in different situations.
9.6.7
Process air Blower Operation The Process air Blower is actually a multi-stage, low-head, centrifugal compressor. Although this air blower is less complicated to operate than conventional centrifugal compressors (like those used in fuel gas service, for instance), the blower does require some special attention when operating at low flow rates. These cases are discussed in the sections below.
9.6.7.1
Preventing "Surge" in the Process air Blower When centrifugal compressors are operated at low flow rates, they may enter a range of flow instability known as "surge." The startup air flow rate to an SRU is primarily controlled by throttling a valve in the blower suction. This method of flow control is preferred because suction throttling reduces the inlet air density and maintains a higher volumetric flow rate through the blower when the mass flow rate is lower. Because of this effect, the blower should be able to operate down to a lower flow rate before going into surge. Operating experience will establish what the stable operating range is for this blower. The primary indication of blower surge is erratic air flow rate. The first sign of this is usually audible – the check valve in the blower discharge line begins to "clatter." The air pressure gauge on the inlet to the Acid Gas Burner will usually fluctuate rapidly, and the burner flame can often be observed to "puff" back and forth, when the blower is in surge. If the surge is severe enough, it will cause high vibration levels on the blower. If the blower is in surge for an extended period, the blower casing will overheat due to re-circulation of hot air between stages of the machine. Regardless of the symptoms, the result of allowing a blower to operate in surge for long periods of time is physical damage to the blower, either from high vibration or from high temperature. For this reason, do not allow an air blower to remain in surge.
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SULFUR BLOCK To prevent the blower from surging at low flow rates, the discharge piping on each blower has a "blow-off" valve installed. The action of the blow-off valve is controlled by relays in the DCS. When the air flow is low, the PLC will open the blow-off valve and allow some of the air from the blower to vent to the atmosphere, increasing the air flow through the blower to keep it above the surge line. A silencer has been installed in the vent line to reduce the noise level around the blower when the blow-off is used. If the blower is surging, then adjust its blow-off valve to open more until the blower stops surging. It does no harm to open the blow-off more than necessary, although it does waste power by forcing the blower to compress more air than necessary. Adjusting the amount that the blow-off opens is simply a matter of making the appropriate configuration change in the DCS. 9.6.7.2
"Swapping" Process Air Blowers During Operation While a sulfur plant is running, it is often necessary to "swap" air blowers to bring the off-line blower on-line so that the other blower can be shut down. This can usually be accomplished with only a slight "bobble" to the process by starting and stopping the blowers in the proper manner. The procedure given below is one technique for swapping blowers. Since each SRU must remain on-ratio at all times for optimum sulfur recovery, it is important that the air flow to an SRU not be disturbed while swapping blowers. If the air flow fluctuates, the best that can happen is a minor disturbance in air:acid gas ratio and a small drop in sulfur recovery. At worst, the Acid Gas Burner may lose its flame, the SRU will shut down on "flame failure", and the acid gases will be diverted to the flare (a reportable emission episode). The "bias" controllers in the DCS together with the bias and flow control relays in the DCS, are designed to make swapping blowers relatively simple and avoid these problems. One of the complicated aspects associated with swapping blowers is the impact that starting the off-line blower can have on air flow. Each air blower has its own suction valve. Since the DCS will be sending the same control signals to the valves on both blowers, there is a potential to suddenly double the air flow when the off-line blower is first started. This would not only disturb the process, it could possibly blow out the flame in the burner.
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SULFUR BLOCK The bias relays in the DCS allow the DCS operator to slowly ramp up the flow from the off-line blower while ramping down the flow from the on-line blower. Although we have attempted to automate this concurrent ramping operation on a couple of past projects, we have not found this to be very satisfactory. The way that the blower controls need to be ramped will depend on the current plant throughput and whether or not the blower suction valve is still in control of the air flow from the blower. This is classic "fuzzy logic", something that is easy for a human to do but very difficult for a computer. The procedure below describes how to switch an SRU from the "A" blower to the "B" blower. That is, the "A" blower is running to the SRU and the "B" blower is not currently running. The procedure to switch from the "B" blower to the "A" blower in the SRU is similar. Make sure the SRU is operating stably before proceeding. A.
In the DCS, confirm that the “A” blower hand controller is currently set to 100% output so the blower relay is multiplying the signal it receives from the process air flow controller by 1.0 (i.e., no change). (If the setting is not already 100%, slowly increase it to 100% before proceeding, allowing time for the controls to respond.)
B.
Set the “B” blower hand controller in the DCS to 0% output. This means that its relay will be multiplying the signal it receives from the process air flow controller by 0.0, so all of the flow relays for the valves on the “B” blower will be receiving 0% as their inputs. After transformation by the suction, discharge, and vent relays in the DCS, this means that the positioners on the suction valve, discharge valve, and vent valve will be receiving control signals of 33%, 0%, and 100%, respectively.
C.
Switch the process air flow controller to "manual". This ensures that the input to the "bias" relays does not change during the blower swap procedure, so that the DCS operator can see the impact on air flow while adjusting the relays.
D.
On the off-line blower (B), confirm that: (1)
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Its suction valve is closed.
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SULFUR BLOCK
E.
(2)
Its discharge valve is closed.
(3)
Its blow-off valve is closed.
Start the off-line blower as follows: (1)
Press the local push-button to give the blower a "permit to start" and energize the solenoid valves on its suction and vent valves for 30 seconds.
(2)
Start the blower using its local start/stop control station.
(3)
Once the blower is running, the solenoid valve on its discharge valve is also energized.
The blower suction valve will open 33%, its vent valve will open, and its discharge valve will remain closed. The valves will all return to being closed if the blower is not started before the "permit to start" times out. Since the discharge valve will still be fully closed when the blower starts, there will be no change in the air flow to the SRU even though air will be flowing through the blower. All of the air will be flowing out of the blow-off valve and venting atmosphere. F.
In the DCS, begin to increase the output from the “B” blower hand controller. This will begin to increase the multiplier in the “B” relay from 0.0, and the output to the discharge valve will begin to increase as the output to the vent valve begins to decrease.
G.
Continue to increase the output from the “B” blower hand controller until the “B” blower develops enough discharge pressure to open its check valve and the air flow to the SRU begins to increase. Depending on current operating conditions in the SRU, this may happen as soon as the discharge valve begins to open, or it may not happen until the suction valve begins to open more. Once the discharge check valve on the “B” blower opens, the air flow to the SRU will begin to increase as the “B” blower starts to contribute to the air flow.
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SULFUR BLOCK H.
Begin to decrease the output from the “A” blower hand controller. This will begin to reduce the multiplier in “A” relay from 1.0 and begin to reduce the flow from the “A” blower. Depending on current operating conditions in the SRU, this may be due to throttling the suction valve more, or may be due to closing of the discharge valve.
I.
Continue to increase the output from the “B” blower hand controller and reduce the output from the “A” blower hand controller as necessary to control the air flow, until the “B” blower hand controller has 100% output and the “A” blower hand controller has 0% output. This will increase the air flow from the “B” blower and reduce the air flow from the “A” blower until all the flow to the SRU is from the “B” blower and the “A” blower is just venting air to the atmosphere.
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J.
Switch the air flow controller back to "automatic".
K.
Shut down the “A” blower using the local start/stop control station.
L.
The blower swap is now complete. Before leaving the area, visually confirm that: (1)
The off-line blower is stopped.
(2)
The suction, discharge, and v valves on the off-line blower are closed.
(3)
The on-line blower is running smoothly.
(4)
The process has returned to steady operation.
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SULFUR BLOCK 9.6.8
Reactor Furnace Temperature Each Reactor Furnace is designed to destroy the ammonia contained in the SWS gas feed by maintaining a high-temperature, reducing atmosphere in the front zone of the furnace. In order to control the temperature in the front zone of the furnace, a portion of the amine acid gas bypasses the Acid Gas Burner and flows to side injection ports on the Reactor Furnace, where the bypass gas mixes with the burner combustion products as they enter the second zone of the furnace. If less of the amine acid gas is routed to a burner, a greater portion of the H2S fed to that burner is actually combusted, raising the flame temperature and increasing the temperature in the front zone of that furnace. If more amine acid gas is routed to a burner, a smaller fraction of the H2S entering that burner is combusted, lowering the temperature in the front zone of that furnace. The amount of amine acid gas that is fed to the burner in the SRU is controlled using the flow ratio controller in the DCS to adjust bypass gas control valve to regulate the amine acid gas flowing to the side injection ports on its furnace (the bypass gas flow rate). In theory, the optical pyrometer mounted on the side of the furnace should measure the temperature inside the first zone of the Reactor Furnace and make appropriate adjustments to the bypass gas flow by changing the ratio setting on the flow ratio controller to control the desired temperature. In practice, however, the temperatures measured by optical pyrometers on similar furnaces have often given erratic responses to process changes. It is suspected that the cool bypass gas entering the side injection ports is influencing the temperature measurement, either due to a cooling effect on the refractory as the gas flows through the openings in the lining, or due to back-mixing caused by eddies arising from the "jet" effect of the combustion products leaving the Acid Gas Burner. If the temperature response of the pyrometers does prove to be unreliable, then the bypass gas ratio can be used for control purposes instead. The graph below shows the bypass gas ratio as a function of the ratio of SWS gas flow to amine acid gas flow. The bypass gas ratio is the amine acid gas bypassing the burner as indicated in the DCS versus the total amine acid gas as indicated in the DCS. Combustion of the ammonia in the SWS gas is very exothermic, so less of the amine acid gas must be bypassed to maintain the same front zone temperature as the ratio of SWS gas to amine acid gas increases.
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SULFUR BLOCK 0.215
0.214
0.213
Bypass Gas Ratio, Nm3/Nm3
0.212
0.211
0.210
Design Point (Normal Operation)
0.209
0.208
0.207
0.206
0.205 0.00
0.01
0.02
0.03
0.04
0.05
SWS Gas:Amine Acid Gas Ratio, Nm3/Nm3
The setpoint for the flow ratio controller can be set by the operator using the graph above. When operating in this mode, the temperature indicated on the optical pyrometer can be monitored to determine if changes to the setpoint on the flow ratio controller are necessary. If the temperature reading is lower than normal, raise the setpoint on the flow ratio controller to bypass more amine acid gas around the burner and raise the temperature. If the temperature reading is higher than normal, lower the setpoint on the flow ratio controller to bypass less amine acid gas around the burner and bring the temperature down. If field experience shows that the temperature measurement of the optical pyrometers on these SRUs will give acceptable control. Placing the flow ratio controller in "cascade" will allow the temperature controller to adjust its ratio setpoint, so that the amount of bypass gas is controlled appropriately with the flow ratio controller. Whether the bypass gas ratio is controlled directly or is set by the action of the temperature controller adjusting the bypass gas ratio, the following considerations apply to the bypass gas flow rate:
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SULFUR BLOCK (7)
The total bypass acid gas flow rate should never be allowed to exceed 67% (i.e., ⅔) of the total amine acid gas flow rate, as this will ensure that at least ⅓ of the total acid gas feed is always flowing to the burner regardless of the SWS gas flow rate. If less that ⅓ of the total H2S is fed to the burner, all of the oxygen in the process air fed to the burner may not be consumed. If this happens, free oxygen may enter the downstream catalyst beds and catch them on fire, leading to catalyst (and possibly equipment) damage.
(8)
65% is the recommended maximum bypass acid gas ratio to allow a safety margin for flow measurement errors, slow control response, plant upsets, etc.
(9)
It is always desirable to minimize the bypass acid gas ratio, as sending more of the amine acid gas feed to the burner means less chance of contaminating the downstream catalyst beds with hydrocarbons or carbon. Even the best-run amine systems will always pick up small amounts of hydrocarbon, which can subsequently contaminate the catalyst beds. Hydrocarbon fouling is the most common cause of poor catalyst life in refinery sulfur plants.
(10) The pressure drop through the Acid Gas Burner is the driving force that allows the bypass gas control valve to bypass part of the amine acid gas around the burner and into middle of the furnace instead. When the SRU is operating at low flow rates, there may not be enough pressure drop through the burner to give good control of the bypass acid gas. In such cases, the flow ratio controller will "pinch" the control valve in the acid gas line to the burner, increasing the pressure drop available for the bypass gas control valve. The DCS relay is designed to limit the output to the control valve in the acid gas line to the burner so that this valve is never completely closed. There should always be at least ⅓ of the amine acid gas flowing to the burner to be sure that the front zone of the Reactor Furnace does not begin to operate in an oxidizing atmosphere. (11) When an SRU is not processing SWS gas, it is not necessary to bypass any amine acid gas around its burner. When operating in this mode, place the flow ratio controller in "manual" and set its output to 0% to fully close the bypass gas control valve and send all the amine acid gas to the burner. With all of the amine acid gas
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SULFUR BLOCK flowing through the burner, it is less likely that hydrocarbons in the acid gas will leave the furnace un-combusted, so there is less chance of fouling the downstream catalyst beds.
WARNING
IT IS POSSIBLE FOR THE SIDE INJECTION PORT NOZZLES ON A REACTOR FURNACE TO OVERHEAT IF THERE IS NO BYPASS ACID GAS FLOWING THROUGH THE NOZZLES. ALTHOUGH THE HOT FURNACE GASES SHOULD NOT "BACK" INTO THE NOZZLES, THE INTENSE RADIANT HEAT FROM THE HOT FURNACE INTERIOR MAY CAUSE OVERHEATING OF THE NOZZLES. TO PREVENT ANY SUCH OVERHEATING, THE NITROGEN PURGE FOR THE INJECTION PORTS SHOULD BE PLACED IN SERVICE WHENEVER THERE IS NO BYPASS ACID GAS FLOW.
9.6.9
Ammonia Destruction Considerations It is generally accepted within the industry that sulfur plants processing ammonia-bearing streams (sour water stripper off-gas, for instance) must be designed to destroy essentially all of the ammonia, probably down to PPM levels, to avoid plugging with ammonia salts in the downstream equipment. For this reason, many sulfur plant designers impose upper limits on the ratio of SWS gas to amine acid gas to ensure successful operation of their SRUs. We do not believe this is necessary, however, if the reactor furnace is designed for ammonia destruction in a reducing atmosphere like the furnace in this SRU is. Years ago, ammonia was destroyed in one section of a reactor furnace by literally burning it in the presence of excess air. A notable number of undesirable side effects result when the ammonia is destroyed in this oxidizing atmosphere, as a significant amount of sulfur trioxide (SO3) is formed in this oxidizing step since the ammonia-bearing feed stream also contains sulfur compounds. This SO3 can cause significant problems throughout the process. First, it readily reacts with any free ammonia
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SULFUR BLOCK throughout the process to form heat-stable salts that deposit and accumulate. (Frequently, small amounts of ammonia enter the process in the amine acid gas stream to participate in this salt accumulation problem.) Second, the SO3 can react with the Claus catalyst surface to form sulfate salts that deactivate the catalyst. Third, the SO3 can condense on and corrode the cooler surfaces in the unit very rapidly during upset periods. Fourth, the SO3 absorbs in the sulfur product and causes it to be corrosive. As these problems were diagnosed and studied, Amoco and others discovered and demonstrated that the ammonia could be successfully destroyed in a Claus SRU by thermal decomposition in a reducing atmosphere. This process change essentially eliminated the formation of SO3 in the unit. Amoco found that large quantities of ammonia could be destroyed in a reducing atmosphere at elevated temperatures, and obtained patents covering this mode of operation in 1973. As Amoco licensees, our SRUs are designed for reducing-atmosphere ammonia destruction in a two-zone reactor furnace, with careful attention to controlling the front zone temperature at or above 1370°C to ensure near complete ammonia destruction. Surprisingly, though, we have found that our clients do not always operate our SRUs in strict accordance with the published operating procedures regarding such matters as minimum furnace temperature, feedstock ratios, etc. In fact, some of our clients have operated their SRUs on just sour water stripper off-gas for days at a time because of operating problems in the amine unit. Although there was undoubtedly ammonia escaping from the furnace when operated in this manner, there has never been any plugging with salts during this time. This has led us to conclude that avoiding SO3 formation, not complete ammonia destruction, is the critical element in the reliability of our reducing-mode SRUs. If you examine the melting points of the various salts that can result from ammonia and the sulfur compounds that might be found in a sulfur plant, only ammonium sulfate, (NH4)2SO4, has a melting point that is higher than the freezing point of sulfur. Since all of the surfaces in a sulfur plant must be maintained above the sulfur freezing point, none of the other salts can precipitate under normal operating temperatures. Thus, as long as the furnace is operated in a reducing atmosphere so that there is no SO3 to combine with water and the
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SULFUR BLOCK residual ammonia to form ammonium sulfate, salt precipitation should not occur in the SRU. Since these SRUs are followed by an amine-based tailgas cleanup unit, though, there will be cooler pieces of equipment downstream of the SRU. However, the first cool section is the quench water system in the TGCU, which will easily scrub the ammonia from the gas streams since ammonia dissolves readily in water. Because this serves to raise the pH of the quench water and counteract the drop in pH as H2S, CO2, and trace quantities of SO2 dissolve in the water, this ammonia is actually beneficial to the process. Depending on the amount of ammonia in the gas, some may escape from a quench tower and dissolve in the downstream amine solution, but periodically purging a small amount of water from the stripper reflux system will prevent the ammonia from concentrating enough to cause salt problems.
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SULFUR BLOCK 9.6.10
Sulfur Recovery Efficiency The sulfur recovery efficiency of an SRU depends on a number of factors. These sulfur plants are designed to achieve an average sulfur recovery of at least 94-96%, but should be capable of recoveries somewhat higher than this. Operator attention to the following aspects of sulfur plant operation will ensure consistently good recovery levels in these SRUs.
9.6.10.1
H2S:SO2 Ratio Maximum sulfur recovery is obtained when the H2S to SO2 ratio in the process gas upstream of the first catalyst bed is exactly 2:1. It is virtually impossible to maintain this exact ratio, but efforts should be made to control near 0% air demand on the air demand analyzer. For instance, the changing air temperature and relative humidity between day and night will cause some variation in the air flow rate, resulting in variations in percent air demand (a function of the H2S:SO2 ratio). The air demand analyzer will continuously analyze the process gas and calculate the percent air demand, allowing the air demand controller to automatically trim the air:acid gas ratio to stay close to a 2:1 H2S:SO2 ratio. If the analyzer is out of service or needs to be checked, the procedures in Section 9.10 of these guidelines can be used to manually sample the process gas and determine the H2S:SO2 ratio, so that the appropriate change can be made to the air:acid gas ratio.
9.6.10.2
Reactor Feed Temperatures The optimum feed temperature to a Claus reactor is a complex function of several factors, which often have conflicting effects on overall sulfur recovery. Some general guidelines used by sulfur plant designers are:
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(1)
Catalytic conversion temperatures.
is
(2)
Hydrolysis (conversion) of organic sulfur compounds (such as COS and CS2, which are formed by side reactions in the Reactor Furnace) back into H2S is favored by higher operating temperatures.
Sulfur Recovery
favored
by
lower
operating
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SULFUR BLOCK (3)
Liquid sulfur will be adsorbed in the catalyst pores (rendering the catalyst temporarily inactive) if the reactor operating temperature is too close to the sulfur dewpoint.
These factors were carefully considered when these SRUs were designed and the temperatures shown on the process flow diagram were chosen, but provisions have been included to control and/or change these temperatures. If desired, the optimum reactor feed temperatures can be determined for the actual operating conditions by making changes and observing whether the amount of sulfur in the tailgas goes up or down. The H2S and SO2 concentrations in the SRU tailgas indicated by the air demand analyzer for the SRU in question will give a direct indication of whether the sulfur recovery has improved (i.e., a lower total concentration for the two) or suffered (i.e., a higher total concentration for the two) when a change is made. The sulfur recovery is affected by the catalyst bed feed temperatures. Maximum sulfur recovery is usually obtained when the catalyst bed inlet temperatures are controlled at the lowest level that will allow the reaction to continue. The feed temperatures must be sufficiently high to prevent catalyst deactivation due to condensation and deposition of liquid sulfur on the catalyst. The catalyst bed feed temperatures should be controlled at 230°C or higher during startup periods, and during other periods of upset or unusual operating conditions. Calculations indicate that catalyst bed feed temperatures may be reduced to 200-210°C or slightly lower during periods of stable operation without causing problems, particularly in the second and third catalyst beds. However, lowering the feed temperature to the first catalyst bed may not increase recovery, due to lower hydrolysis of organic sulfur compounds in this catalyst bed. Calculations indicate that the optimum sulfur recovery for these SRUs is obtained then the first catalyst bed is operated at high temperature, due to the higher conversion of the organic sulfur compounds to H2S, which is subsequently recovered in the downstream catalyst beds. As shown on the Process Flow Diagram, the feed temperature to the first catalyst bed will normally be around 225-235°C. Operating experience will show whether lower reactor outlet temperatures still
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SULFUR BLOCK give satisfactory performance with the catalyst used in this catalyst bed.
9.6.11
Operation at Low Flow Rates Generally speaking, most sulfur plants can operate down to about 20-25% of design throughput without much loss in recovery efficiency and without requiring much operator attention. This is often referred to as the turndown range or turndown ratio of the plant. Turndown to 20-25% of design rate corresponds to a turndown ratio of 5:1 to 4:1. When an SRU must operate at rates lower than 20-25% of design, there are several operating problems that often occur. These problems, and ways to solve them, are discussed below.
9.6.11.1
Loss of Sulfur Recovery Efficiency The H2S:SO2 ratio in the process gas is the single factor that most affects sulfur recovery. This ratio is a function of the air:acid gas flow ratio. At low flow rates, the flow meters on the amine acid gas, SWS gas, and process air become less accurate, due to the low differential pressures the flow transmitters must measure. This loss of accuracy in measuring the flows to the SRU reduces the effectiveness of the feed-forward part of the air ratio control loop, requiring the feed-back part of the loop (the Air Demand Analyzer) to make bigger corrections to try to keep the H2S:SO2 ratio at 2:1. The result is a loss in recovery because the H2S:SO2 ratio oscillates more widely from the optimum 2:1 ratio. This poor sulfur recovery performance due to flow meter limitations can be corrected by adjusting the flow meters for the lower rates. Depending on the particular circumstances, this can be accomplished in a number of ways: (4)
Issued 30 August 2011
If the SRU must operate at low flow rates permanently, or for long periods of time, installing new orifice plates with smaller bores may be an attractive solution. This will increase the differential pressures measured by the meters to put the flow transmitters back into good operating ranges. The disadvantages of this technique are that a plant shutdown is required to make the change, and that the plant cannot operate at high flow rates again without changing orifice plates.
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SULFUR BLOCK
9.6.11.2
(5)
If the SRU must operate at low flow rates temporarily, re-calibrating the flow transmitters to span lower differential pressure ranges may be a better method since this change can be made while the plant is running. In fact, with "smart" transmitters and the required I/O modules in the DCS, this change can be made from the control room.
(6)
If the SRU must operate at variable flow rates, using dual flow transmitters calibrated for low and high differentials can provide accurate flow measurement over a much wider range. With proper programming in the DCS, the dual transmitters allow "seamless" metering of the flow.
Deactivation of Catalyst Beds by Sulfur "Fog" As a sulfur condenser is operated at lower and lower rates, it reaches a point where the bulk gas cooling rate caused by radiation and conduction heat transfer exceeds the dewpoint reduction rate caused by sulfur condensation on the tube walls. Instead of condensing along the walls of the tubes, sulfur begins to condense into tiny droplets out in the gas. Due to the low flow rates, there is not enough turbulence in the gas to make the droplets coalesce along the tube walls. The droplets come out of the tubes as a "fog" that cannot be removed in the downstream separator section, and are carried over into the reactor feed heaters. The feed heaters cannot vaporize all of the carry-over liquid sulfur, probably because the small surface area of the droplets (relative to their volume) causes slow mass transfer of vaporized sulfur away from the droplets that impedes heat transfer. This causes the liquid sulfur droplets to enter the reactor catalyst beds. The liquid sulfur is then adsorbed into the pores of the catalyst where it blocks the active sites, rendering the catalyst inactive. The catalyst activity can be restored by raising the reactor feed temperature and vaporizing the liquid sulfur out of the pores, but this can be very hard to do when the condensers are carrying over liquid sulfur. The symptom of sulfur carry-over into the catalyst beds is a gradual decline in the temperature rises across the beds. Since the Claus reaction is exothermic (heat releasing), the catalyst bed T is a direct indication of the amount of reaction occurring. As the liquid sulfur
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SULFUR BLOCK deactivates the catalyst, there will a gradual decrease in the reactor bed temperatures, starting at the top and moving downward. Experience has shown that when the condenser passes begin to fog, the liquid sulfur will accumulate in the outlet channels of the heating passes in this style of sulfur plant. Due to the arrangement of these "package" sulfur plants, the heating pass outlet channels are low spots in the flow paths from the condenser outlets to the reactor inlets. It is believed that as the gas flowing out of the heating pass tubes turns 90° to exit through the channel outlet nozzles, centrifugal force causes the sulfur droplets to impinge upon the endplates of the channels with enough force to make the small droplets coalesce into droplets too large to leave with the gas. Over a period of time, sulfur will accumulate to the point where it begins to cause fluctuations in the operating pressure of the affected SRU. The pressure drop will build up enough to "lift" some of the sulfur into the downstream catalyst bed, at which point the pressure drop will immediately become much lower. These SRUs have been designed to take advantage of this phenomenon and drain the liquid sulfur out of the reheat passes before it builds up enough to cause pressure drop problems and be carried into the Reactor. Each heating pass outlet channel has a steam-jacketed sulfur drain valve on it. The drain valves are connected together in a steam-jacketed line that is connected to the cooling pass outlet line. At low flow rates, the pressure drop through an SRU is very low, so the static head of the accumulated liquid sulfur is enough to cause the sulfur to drain into the cooling pass outlet line, where it can flow into the first condensing pass and then drain into the Sulfur Collection Header. If sulfur carry-over is suspected (due to a gradual decline in Reactor bed temperatures or because of SRU pressure fluctuations), these drain valves can be used to drain sulfur from the heating passes by opening them periodically to allow the sulfur to drain. Open each drain valve, one at a time, for one or two minutes, then close the valve. Do this every 4 to 8 hours, using the Reactor bed temperatures as an indication of whether to use the drains more or less frequently. Do not leave the drain valves open. Once the sulfur has drained out of the heating pass channels, hot gas from the cooling pass outlet will flow back up the drain line and disturb the
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SULFUR BLOCK operation of the downstream catalyst beds if the drain valves are left open. 9.6.11.3
Loss of Steam Pressure in Boilers The heat released in the tubes of the Waste Heat Boiler is proportional to the amount of feed gas processed. At very low flow rates, generally less than 10% of the original design, the heat loss to the surroundings can be more than this heat release, to the point where the Waste Heat Boiler is no longer producing steam. When this happens, the reheat exchangers will not be able to keep the reactor feeds as hot as desired and liquid sulfur can begin to condense on the catalyst beds and render the catalyst inactive. The heat release in the Waste Heat Boiler can be increased by burning supplemental fuel gas on the warmup ring of the Acid Gas Burner. This burner is designed to burn fuel gas without forming soot while processing acid gas. The warmup burner tips are installed in the air plenum of the burner upstream of the acid gas tip so that the fuel gas burns in an air-rich atmosphere, and the oxygen remaining after combusting the fuel gas then reacts with the acid gas. To make firing supplemental fuel gas easier, the air flow control system is designed to automatically add air for the fuel gas like it does for the acid gas. The air:acid gas ratio control system will automatically add more process air for the fuel gas when firing supplemental fuel gas. The air demand analyzer in the SRU will continue to keep the air flow at the proper rate via the air controller. Since the supplemental fuel gas requires an increase in the process air flow to the sulfur plant, burning supplemental fuel gas will also increase the mass flow rate through that plant. As a result, this mode of operation can be used to help prevent sulfur "fog" problems discussed earlier from occurring in a Sulfur Condenser. If the plant throughput is near the range at which fogging occurs, firing some supplemental fuel gas may be enough to avoid the problem.
9.6.11.4
Long Term Low-Flow Operation Should the need arise for an SRU to operate at inlet rates below 15 to 20% for extended periods of time, consideration may be given to plugging some of the condensing pass tubes in the Sulfur Condenser. This will increase the flow rates through the remaining
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SULFUR BLOCK tubes so that they are then above the "fog" formation rate and sulfur carry-over is eliminated. Soft iron plugs can be inserted into the inlet ends of the tubes for this purpose. (Do not plug the outlet ends of the tubes. Since the boiler slopes from its inlet end to its outlet end, liquid sulfur would accumulate in the tubes and could cause localized corrosion, plugging, etc.)
9.6.12
Pressure Drop Surveys A commonly encountered problem in sulfur plants (and Tailgas Cleanup Units and Thermal Oxidizers) is a flow restriction due to high pressure drop. High pressure drop is typically caused by a restriction at one point in the equipment or piping, due to: 5.
Accumulation of liquid (sulfur, etc.) in equipment or piping
6.
Partial plugging of a catalyst bed (soot, carbon, polymers, etc.)
7.
Partial plugging of a mist eliminator (sulfur, soot, catalyst, etc.)
The first step in identifying the cause of the high pressure drop is to determine which equipment pass or section of piping contains the restriction. (It is unusual to have more than one area of high pressure drop at any one time.) This is best accomplished by making a pressure survey of the process side of the SRU (and Tailgas Cleanup Unit and Thermal Oxidizer, if necessary). Due to the low operating pressure in a sulfur plant (generally 0.7 kg/cm2(g) or less) and the low pressure drop in each equipment pass (generally 0.00-0.04 bar per pass), a single pressure gauge must be used to make the pressure survey in order to get meaningful results. The gauge should be a low-pressure gauge for best results (a -1 – 0 – +1.5 kg/cm2 gauge is recommended). Beginning at the front end of the sulfur plant of interest, use the pressure tap valves on the inlet and outlet lines from each equipment pass to measure the pressure at each point in the process. Proceed toward the back end of the process until the pass with the high pressure drop is found. Note that some of the pressure tap valves may be plugged with solid sulfur. Rod-out the sample valves as necessary to obtain an accurate pressure reading.
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SULFUR BLOCK
WARNING
ALWAYS OBSERVE PROPER PROCEDURES AND PRECAUTIONS WHEN USING THE PRESSURE TAP VALVES, PARTICULARLY IF THE VALVES ARE PLUGGED AND MUST BE CLEARED. ALTHOUGH THE VALVES ARE ORIENTED TO MINIMIZE THE POSSIBILITY OF FILLING WITH MOLTEN SULFUR, HOT SULFUR MAY SUDDENLY BE EXPELLED FROM A VALVE WHEN THE PLUG IS CLEARED. RELEASE OF TOXIC GASES (H2S AND SO2, IN PARTICULAR) IS ALSO A POSSIBILITY. THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES SHOULD BE CONSULTED IF THERE IS ANY DOUBT ABOUT HOW TO WORK SAFELY WHEN H2S, SO2, OR MOLTEN SULFUR MAY BE PRESENT. When troubleshooting problems of this nature, it is very helpful to have pressure survey information taken previously when the units were operating properly. It is recommended that one or more pressure surveys be performed early in the operating life of the plants, for comparison purposes later if problems are encountered. Since the pressure drop of a sulfur plant is a function of plant throughput (pressure drop is roughly proportional to the square of the flow rate), it is even more helpful for troubleshooting purposes if the early pressure surveys are performed at different plant throughput rates. It is also important to record the gas flow rates (amine acid gas, SWS gas, process air) during each pressure survey, since pressure drop depends so strongly on plant throughput.
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SULFUR BLOCK 9.6.13
Boiler Water Treatment SAMSUNG TOTAL PETROCHEMICALS CO., LTD. IS RESPONSIBLE FOR ESTABLISHING AND MONITORING THE BOILER AND WATER CHEMICAL TREATMENT PROGRAM. Proper boiler water chemical treatment is essential to achieving long service life for the Waste Heat Boilers and Sulfur Condensers. Without good day-to-day control of the water quality, solids buildup, corrosion, and attack by the treating chemicals themselves can occur. It is Samsung Total Petrochemicals Co., Ltd.’s responsibility to see that a proper chemical treating program is initiated prior to startup and that the program is properly monitored and refined throughout the service life of the plant. There are many qualified boiler and water treatment companies that can advise the owner/operator on chemical treatment testing and controls. It is recommended that only those companies that have local technicians with extensive experience specifically in boiler water treatment be selected to assist with Samsung Total Petrochemicals Co., Ltd.’s program. The design details incorporated in the boilers in these SRUs have proven to be very reliable when combined with good operator practice regarding water treatment. However, even properly designed equipment can be severely damaged during a short period of operation if the water treatment program is inadequate or improper. The Waste Heat Boilers and the Sulfur Condensers are equipped with continuous blowdowns to remove suspended and dissolved solids from the water inside the boilers. In addition, these boilers are equipped with intermittent blowdown connections on the bottom of their shells. These intermittent blowdown valves should be used on a regular basis to give the boilers a good "blow" to prevent sludge from accumulating in the bottom of the shells. This is particularly important for the Waste Heat Boiler because sludge must not be allowed to coat the tubes. The consequence of fouling the outside of the tubes is tube failure from overheating, as the fouling will impair the heat transfer and allow the hot combustion gases to destroy the tubes. Prior to using the intermittent blowdown valves, use the level controllers in the DCS to raise the water level up to the high level alarm point. Then open the intermittent blowdown valves, one at a time, until the level drops
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SULFUR BLOCK back to the normal liquid level. Watch the boiler level in the sight glasses throughout this operation to ensure that the level is not lost (which would activate the SRU ESD and shut down that plant). Remember to reset the level controllers at the conclusion of this procedure.
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SULFUR BLOCK
9.7
Precommissioning Procedures Prior to the initial startup, there are a number of precommissioning activities that are necessary to ensure that the newly constructed plant is ready to be placed in service. The activities outlined below should serve as a guide, but there may be others required as a part of your normal plant procedures.
9.7.1
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Preliminary Check-out A.
Check all equipment to ensure that it is properly installed. This will probably require consulting the Manufacturer's literature as well as construction drawings.
B.
Check and lubricate all equipment in accordance with the Manufacturer's recommendations.
C.
Check the rotation of the Process Air Blowers, the Acid Gas Knock-Out Drum Pumps, and the SWS Gas Knock-Out Drum Pumps: (1)
Operate each Process Air Blower for a short period (20 seconds or less) with its discharge valve closed.
(2)
"Bump" each Acid Gas Knock-Out Drum Pump and check for proper rotation.
(3)
"Bump" each SWS Gas Knock-Out Drum Pump and check for proper rotation.
D.
Check all piping and equipment to be sure that all blinds have been removed and that no valves are vented to atmosphere.
E.
Place the Instrument Air System in service to all instruments and check the action of controllers and control valves.
F.
Turn on the steam supplies to all of the steam-jacketed sulfur vapor valves and use the vent valves on each jacket section to vent the air from the jackets. "Stroke" each valve to confirm it moves freely.
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SULFUR BLOCK 9.7.2
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Shutdown System Check-out G.
Fill the Waste Heat Boilers and the Sulfur Condensers with treated boiler feed water up to the high-level alarm points. As the level is rising, check the level transmitters and the high level alarms for proper operation.
H.
Use the quick-opening blowdown valves to lower the water levels in the boilers and check for proper operation of the level transmitters, the low level alarms, and the low-low level shutdowns.
I.
Fill the boilers with treated boiler feed water back up to the normal liquid levels.
J.
Physically check all shutdown activating devices to ensure that they activate the SRU ESD system.
K.
Physically check all devices activated by the SRU ESD system to ensure that they operate properly.
L.
Check all relief valves to ensure that they are installed in the proper locations and set for the correct relieving pressures.
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SULFUR BLOCK 9.7.3
Leak Testing the Process Piping and Equipment
CAUTION
THE LOW PRESSURE PROCESS PIPING (ACID GAS, SULFUR VAPOR, PROCESS AIR) AND LOW PRESSURE PROCESS EQUIPMENT IN THESE SRUS ARE NOT DESIGNED TO BE FILLED WITH WATER AFTER INSTALLATION OF REFRACTORY AND CATALYST. ONLY THE EQUIPMENT AND PIPING UPSTREAM OF AMINE ACID GAS AND SWS GAS SHUTDOWN VALVES CAN BE FILLED WITH WATER AND HYDROTESTED. USE THE FOLLOWING PROCEDURE TO LEAK-TEST THE REST OF THE SRUS. The process piping and equipment in each SRU can be checked for leaks by using a Process Air Blower to pressurize the process side of the equipment and piping to about 0.6-0.7 kg/cm2(g), then checking flanges, etc. for leaks (usually by applying masking tape or "Snoop" to the flanges, and by listening for other leaks). In order to develop this pressure, the blower can be operated with the tailgas block valves and the warmup bypass valves in the SRU closed, and the blow-off valve on the blower "pinched". This procedure requires some special preparations to operate the blower in this manner, as detailed below. The Complete Flowpath Interlock must be temporarily disabled in order to operate the SRU in this manner. The Leak Test switch on each local SRU control panel is used to position the process gas valves as described above and also directs the PLC to bypass most of the unit shutdowns. This means that "jumpers" on the limits switches and "forces" in the PLC are not necessary to perform this test. It also means that it is not necessary to have water in the boilers (Waste Heat Boiler and Sulfur Condenser) during the test since the low-low water level S/Ds are also bypassed. This same procedure can be used to leak test each SRU before restarting it following maintenance. Whenever plant maintenance requires opening one or more of the flanged connections in an SRU, it is good practice to leak test that SRU before returning it to service. This allows detecting any
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SULFUR BLOCK leaking connections that may have resulted from the maintenance operations before acid gas is reintroduced into that unit. Although the SRU is pressurized with air to perform the leak test, there is no air flow through the units during the testing procedure so there is very little jeopardy of having sulfur fires in the catalyst beds. Note that the SRU warmup bypass line is not leak tested during this procedure. This line can be checked for leaks using the nitrogen purge on the piping as described in a later section of these guidelines. To perform leak testing in the SRU, proceed as follows: M.
Switch the process air flow hand switch in the DCS to "local" to give control of the valves on the air blower to the air flow controller (HIC) on the local SRU control panel.
N.
Confirm that the Reactor Cool-Down switch on the local SRU control panel is set to "NORMAL".
O.
Confirm that the manual block valve in the SRU Tailgas line is open.
P.
Switch the Startup/Run selector switch on the local SRU control panel to "STARTUP". The PLC and DCS should perform the following actions: (1)
The two Warmup Bypass Valves are opened.
(2)
The nitrogen purge valve between the warmup bypass valves is closed.
(3)
The Tailgas Valve to the Thermal Oxidizer is closed.
(4)
The Tailgas Valve to the TGCU is closed.
Confirm that the "WARMUP OPEN" light on the panel is illuminated, and that the "TTO OPEN" and the "TGCU OPEN" lights on the panel are extinguished.
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SULFUR BLOCK Q.
Turn the Leak Test key switch on the local SRU control panel to "TEST". The PLC should perform the following actions: (1)
The two Warmup Bypass Valves are closed.
(2)
The nitrogen purge valve is opened.
(3)
All of the ESDs for that SRU are bypassed, except for the high-high furnace pressure S/D and the manual S/D switches.
Confirm that the "WARMUP OPEN" light on the local SRU control panel is now extinguished. R.
Set the air flow controller on the local SRU control panel to 0% output and confirm that the suction, discharge, and blow-off valves on the air blowers are fully closed.
S.
Start a Process Air Blower: (1)
Press the local "permit to start" push-button for the selected blower.
(2)
Start the blower using its local start/stop control station.
The blower suction valve will open 33%, its vent valve will open, and its discharge valve will remain closed when the "permit to start" push-button is pressed. Once the blower is started and comes up to speed, a flow of air will be established out of the blow-off valve and its silencer. T.
Use the local air flow controller as needed to open the discharge valve on the blower and send air to the SRU to begin pressurizing it. Although the blower discharge valve will begin to open as the output from the controller is increased, air will not flow through the sulfur plant once pressure builds because the warmup bypass valves and the tailgas valves are all closed.
At this point, two operators will be necessary to control and monitor the Process Air Blower. One operator should be stationed at the local SRU control panel, and one stationed near the blower area.
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SULFUR BLOCK
CAUTION
DO NOT LET THE AIR BLOWER GO INTO SURGE. THE OPERATOR STATIONED NEAR THE BLOWER SHOULD LOOK AND LISTEN FOR INDICATIONS OF SURGE. IF SURGE IS DETECTED, REDUCE THE OUTPUT ON THE AIR FLOW CONTROLLER TO OPEN THE BLOW-OFF VALVE MORE AND INCREASE THE AIR FLOW ENOUGH TO BRING THE BLOWER OUT OF SURGE. IT MAY NOT BE POSSIBLE TO RAISE THE DISCHARGE PRESSURE ALL THE WAY TO 0.6-0.7 KG/CM2(G) WITHOUT CAUSING THE BLOWER TO SURGE. U.
Slowly increase the output from air flow controller to "pinch" the blow-off valve on the air blower until the discharge pressure from the blower reaches 0.6-0.7 kg/cm2(g) as measured by the pressure gauge on the process air line to the burner. Due to the volume inside the SRU, it will take several minutes for the pressure to build up in the SRU.
V.
Once the desired discharge pressure has been achieved, and the blower is operating stably, check all of the equipment and piping connections for visible or audible signs of leakage. Continue to monitor the air blower to be sure it is operating stably. NOTE:
Do not allow the pressure to reach the high-high pressure S/D, since this shutdown is still active and will activate the SRU ESD system if this happens.
W.
After the leak test has been completed, press the ESD push-button on the local SRU control panel to activate the SRU ESD system and shut down the air blower.
X.
Turn the Leak Test switch on the local SRU control panel to "NORMAL". The PLC should perform the following actions:
Issued 30 August 2011
(1)
The two Warmup Bypass Valves are opened.
(2)
The nitrogen purge valve is closed.
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SULFUR BLOCK (3)
All of the ESDs for the SRU are enabled again.
Confirm that the "WARMUP OPEN" light on the local SRU control panel is now illuminated. Y.
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Confirm the following: (1)
The air blower is shut down, and its suction, discharge, and blow-off valves are closed.
(2)
The two Warmup Bypass Valves are both open.
(3)
The Tailgas Valve to the Thermal Oxidizer and the Tailgas Valve to the TGCU are both closed.
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SULFUR BLOCK 9.7.4
Purging the Inlet Knock-Out Drums Since inert nitrogen gas is available in the SRU area, it can be used to purge the Acid Gas Knock-Out Drum and the SWS Gas Knock-Out Drum prior to removing the blinds in their inlet lines. One procedure for doing so is as follows.
WARNING
UNTIL THE AIR IS PURGED FROM THE KNOCK-OUT DRUMS, THERE MAY BE FLAMMABLE GAS MIXTURES PRESENT IN THE VESSELS AND THEIR PIPING. ENSURE THAT ALL IGNITION SOURCES, INTERNAL AND EXTERNAL TO THE VESSELS, HAVE BEEN REMOVED BEFORE PROCEEDING.
Issued 30 August 2011
A.
Verify that the blinds are in place in the inlet amine acid gas line and the inlet SWS gas line. Do not attempt this procedure if these lines are not blinded from their respective acid gas sources.
B.
The sulfur plant downstream of the drums does not need to be purged with nitrogen. Verify that the amine acid gas and SWS gas flow controllers on the local SRU panel are set to 0% output and that the inlet amine acid gas valve and the inlet SWS gas valve are closed.
C.
Open the suction valve and close the discharge valve on each Acid Gas Knock-Out Drum Pump.
D.
Open all of the vent and drain valves on the level and pressure instruments on the Acid Gas Knock-Out Drum and each Acid Gas Knock-Out Drum Pump, and the vent and drain valves on each Acid Gas Knock-Out Drum Pump.
E.
Remove the blind from the drain valve on the pump suction line and use a hose or other means to temporarily connect nitrogen to the valve. Commence the flow of nitrogen into the Acid Gas Knock-Out Drum and each Acid Gas Knock-Out Drum Pump, so that nitrogen is flowing out of all of the open valves. Be sure to include the acid gas inlet line from the Amine Regeneration Unit.
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SULFUR BLOCK F.
Allow the nitrogen to continue flowing long enough to reduce the oxygen concentration in the vessel and piping to less than 1%. Use a portable oxygen analyzer to determine the oxygen concentration.
G.
When the oxygen concentration is below 1%, begin closing the vent and drain valves. Close the valves on each Acid Gas Knock-Out Drum Pump first, then the valves on the Acid Gas Knock-Out Drum level instruments. Leave the sample connection valve open on the outlet line from the Acid Gas Knock-Out Drum.
H.
Close the valve where the nitrogen hose is connected to stop the flow of nitrogen, then close the sample connection valve.
I.
Repeat Steps C through H for the SWS Gas Knock-Out Drum and the SWS Gas Knock-Out Drum Pump. The sample connection valve on the outlet line from the SWS Knock-Out Drum should be the last valve closed, after stopping the flow of nitrogen.
Leave each system blocked-in like this until ready to bring acid gas into the SRU.
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SULFUR BLOCK 9.7.5
Commissioning Fuel Gas and Instrument Air to the Process The fuel gas and instrument air supplies to the process side of an SRU must be made ready for use prior to starting up the SRU using the procedures in Section 9.8 of these guidelines. This requires blowing down each section of piping to ensure that there are no liquids and/or construction debris in the headers and supply lines. The procedure below can be used to make sure that these gas utility systems are ready for service. A.
Select local manual control for the main fuel gas control valve by switching the fuel gas hand switch in the DCS to "local".
B.
Set the fuel gas controller on the local SRU control panel to 0% output.
C.
Confirm that the following fuel gas and instrument air valves are closed: (7)
The manual block valve in the main fuel gas supply line.
(8)
The two automated block valves and the flow control valve downstream of the manual block valve in the main fuel gas line to the Acid Gas Burner.
(9)
The upstream manual block valve, the two automated block valves, and the downstream manual block valve in the fuel gas supply line to the pilot.
(10) The manual block valve(s), and the automated block valve in the air supply line to the pilot. (11) The manual block valve in the instrument air supply line to the Air Demand Analyzer. (12) The block valves in the instrument air supplies to the level transmitters, on the Sulfur Surge Tank.
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D.
Confirm that all of the manual vent/drain valves in the main fuel gas, pilot fuel gas, and pilot air piping are closed.
E.
If the orifice plate has already been installed in the fuel gas flow meter remove it for now.
F.
Disconnect the fuel gas and instrument air from the burner systems by performing the following steps:
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SULFUR BLOCK
G.
H.
Issued 30 August 2011
(1)
Unbolt the flanged connection at the burner in the main fuel gas supply line.
(2)
Disconnect the fuel gas supply tubing where it connects to the pilot.
(3)
Disconnect the instrument air supply tubing where it connects to the pilot.
(4)
Cover the open ends of these connections on the burner and pilot to prevent debris from entering when the upstream piping is blown down.
Remove the following pressure regulators, then cover the downstream piping to prevent debris from entering when the upstream piping is blown down: (1)
The main fuel gas supply regulator.
(2)
The pilot instrument air supply regulator.
(3)
The pilot fuel gas supply regulator.
"Force" the PLC to open the following valves: (1)
The automated block valves in the main fuel gas supply line.
(2)
The automated block valves in the fuel gas supply line to the pilot.
(3)
The automated block valve in the instrument air supply line to the pilot.
I.
Confirm that these automated valves have moved to the proper positions.
J.
"Crack" the manual block valve in the main fuel gas supply line and allow fuel gas to blow through the piping until it is clear. Then close the gate valve, reinstall the main fuel gas pressure regulator, and reopen the block valve.
K.
Using the pressure gauge and the vent valve downstream of the main fuel gas pressure regulator, adjust the main fuel gas regulator to its specified setpoint.
L.
Use the main fuel gas flow controller on the local control panel to fully open the fuel gas flow control valve in the main fuel gas line,
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SULFUR BLOCK then use the downstream vent valve to blow out this section of piping. Close the vent valve when the piping is clear.
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M.
"Crack" the manual block valve downstream of the fuel gas flow control valve and allow fuel gas to blow through the piping until it is clear. Then close the manual block valve and the control valve.
N.
"Crack" the upstream manual block valve in the fuel gas supply line to the pilot and allow fuel gas to blow through the piping until it is clear. Then close the ball valve, reinstall the pilot fuel gas pressure regulator and reopen the block valve.
O.
Using the pressure gauge and the vent valve downstream of the pilot fuel gas pressure regulator, adjust the pilot fuel gas regulator to its specified setpoint.
P.
"Crack" the manual block valve downstream of pilot fuel gas automated block valves and allow fuel gas to blow through the piping until it is clear. Then close the manual block valve.
Q.
"Crack" the upstream manual block valve in the instrument air supply line to blow air through the piping until it is clear. Then close the block valve, reinstall pressure regulator the instrument air pressure regulator and reopen the block valves.
R.
Using the pressure gauge and the vent valve downstream of the instrument air pressure regulator, adjust the pilot instrument air regulator to its specified setpoint.
S.
"Crack" the manual block valve downstream of automated instrument air block valve and allow instrument air to blow through the piping until it is clear. Then close the manual block valve.
T.
Disconnect the air supply line at the Air Demand Analyzer, cover the open end of the downstream piping, and "crack" the manual block valve to blow air through the piping until it is clear. Then close the manual block valve, reconnect the piping, and reopen the block valve.
U.
Disconnect the upstream fitting in the air supply to purge the rotameter for the bubbler-type level transmitter on the Sulfur Surge Tank, then open the block valve in the air supply line briefly to blow any liquids or debris from the purge line. Reconnect the FI, disconnect the fitting where the purge enters the bubbler tube, and
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SULFUR BLOCK cover the opening. Open the block valve briefly to blow any liquids or debris from the purge line, then reconnect the purge to the bubbler tube. Reopen the block valve and adjust the FI to a small air flow (0.8-1.6 Nm3/Hr). Place the other level transmitters in service in the same manner.
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V.
Remove the "forces" from the PLC and confirm that all of the automated block valves close and all of the automated vent valves open.
W.
Close the manual block valve in the main fuel gas supply line and the manual block valve in the instrument air line supply until the SRU is ready for startup.
X.
Reconnect the fuel gas and instrument air to the burner systems by performing the following steps: (1)
Bolt the flanged connection at the burner in the main fuel gas supply line back together.
(2)
Reinstall the fuel gas supply tubing where it connects to the pilot.
(3)
Reinstall the instrument air supply tubing where it connects to the pilot.
(4)
Reinstall the orifice plate in the fuel gas flow meter.
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SULFUR BLOCK 9.7.6
Commissioning Nitrogen to the Process The nitrogen supplies to the process side of each SRU must be made ready for use prior to starting up the SRUs using the procedures in Section 9.8 of this manual. This requires blowing down each section of piping to ensure that there are no liquids and/or construction debris in the headers and supply lines. The procedure below can be used to make sure that this gas utility system is ready for service. A.
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Confirm that the following nitrogen valves are closed: (1)
The manual block valves in the N2 purge line to the bypass acid gas injection nozzles on the Reactor Furnace.
(2)
The ball valves in the purge lines to the burner instruments.
(3)
The block valves in the purge lines to the optical pyrometer.
(4)
The gate valves in the nitrogen supply lines located near the Reactor and the nitrogen supply line located near the Acid Gas Burner.
(5)
The ball valves in the purge lines to the SWS gas flow transmitter and pressure gauge.
(6)
The gate valve in the nitrogen supply line to the Air Demand Analyzer.
(7)
The gate valve upstream and the ball valve downstream of the rotometer in the purge line on the SRU warmup bypass line.
B.
Confirm that the H.P. nitrogen and L.P. nitrogen supply headers have been placed in service, with the pressure regulator(s) set at the values specified on the P&IDs and safety relief valves in service, and that the main supply header piping has been blown down and drained.
C.
Open the gate valve in each of the three nitrogen supply lines located near the Reactor and the nitrogen supply line near the Acid Gas Burner until each line is clear.
D.
Remove pressure regulator in the purge line for the optical pyrometer viewport and nozzle, cover the open end of the downstream piping, open the gate valve, and "crack" the ball valve in the supply line to blow nitrogen through the piping until it is clear. Then close the gate valve and the ball valve and reinstall the regulator.
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SULFUR BLOCK E.
Disconnect the purge tubing from the viewports on the optical pyrometer and cover the opening.
F.
Open the gate valve and the ball valve in the nitrogen supply. Using the pressure gauge, adjust the regulator to its specified setpoint. Allow nitrogen to blow through the tubing until it is clear. Reinstall the purge tubing to the pyrometer. Leave the gate valve and the ball valve in the supply line open.
G.
Remove the plug and use the drain valve at the end of the supply line to the purges for the burner instruments to blow out this section of piping until it is clear, then close the drain valve and reinstall the plug.
H.
Each of the low pressure purges for the burner instruments and for the bypass acid gas nozzles has a rotameter (FI) near where it connects to the process. Disconnect the upstream fitting at each FI and cover the opening, then open its upstream ball valve briefly to blow any liquids or debris from the purge line. Reconnect each FI, disconnect the fitting where each purge enters the process and cover the opening, open its upstream ball valve, then open its downstream valve briefly to blow any liquids or debris from the purge line. Then reconnect each purge to the process and open its downstream valve to place it in service.
I.
The SWS gas flow transmitter has low pressure purges for both of its sensing lines, each with a rotameter near where it connects to the sensing line. Disconnect the upstream fitting at each FI and cover the opening, then open its upstream ball valve briefly to blow any liquids or debris from the purge line. Reconnect each FI, disconnect the fitting where each purge connects to the sensing line and cover the opening, open its upstream ball valve, then open its downstream ball valve briefly to blow any liquids or debris from the purge line. Then reconnect each purge to the sensing line and open its downstream ball valve to place it in service. NOTE: The two rotameters must be adjusted to the same flow rate so that the pressure drop of the purge gas in the sensing lines does not affect the reading of the flow transmitter. One way to do this is to confirm that the equalizing valve on the flow transmitter manifold is closed, set the rotameter on the upstream sensing line to a small flow rate
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SULFUR BLOCK (~0.8-1.6 Nm3/Hr), and then adjust the flow rate of the other rotameter until the flow meter reads zero.
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J.
The SWS gas pressure gauge also has a low pressure purge for its sensing line with a rotameter near where it connects to the sensing line. Disconnect the upstream fitting at the FI and cover the opening, then open its upstream ball valve briefly to blow any liquids or debris from the purge line. Reconnect the FI, disconnect the fitting where the purge connects to the sensing line and cover the opening, open its upstream ball valve, then open its downstream ball valve briefly to blow any liquids or debris from the purge line. Then reconnect the purge to the sensing line and open its downstream ball valve to place it in service.
K.
Disconnect the nitrogen supply line at the Air Demand Analyzer, cover the open end of the downstream piping, and "crack" the gate valve to blow nitrogen through the piping until it is clear. Then close the gate valve, reconnect the piping, and reopen the gate valve.
L.
If necessary, "force" the PLC to close the two Warmup Bypass Valves and open the N2 purge valve. Disconnect the upstream fitting at the rotometer (FI) and cover the opening, then open its upstream gate valve briefly to blow any liquids or debris from the purge line. Reconnect the FI, then disconnect the fitting where the purge enters the process and cover the opening. Open the upstream gate valve, open the downstream manual block valve briefly to blow any liquids or debris from the purge line, then reconnect the purge to the process.
M.
Open the manual block valve downstream of the FI and allow the nitrogen to pressurize the piping between the two Warmup Bypass Valves. Check all of the piping connections for visible or audible signs of leakage (by applying masking tape or "Snoop" to the flanges, listening for other leaks, etc.). When this leak checking complete, if the PLC was "forced" in the previous step, remove the "force" and confirm that the Warmup Bypass Valves open and the purge valve closes. Leave the manual block valve downstream of the FI open.
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SULFUR BLOCK 9.7.7
Commissioning the Sulfur Surge Tank Heating and Ventilation The heating and ventilation systems for each Sulfur Surge Tank can be placed in service at any time prior to the beginning of sulfur production from the associated SRU. It is advantageous to place these systems in service prior to startup of the SRU so that any problems can be corrected without impacting the schedule for commissioning the SRU. To place the heating and ventilation systems in service, proceed as follows:
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A.
Confirm that the steam supply valves to the steam coils in the Sulfur Surge Tank are all closed, and that the steam trap stations on each of the coils are all blocked in.
B.
Open the vent valves on each of the steam coils.
C.
Establish steam flow into each of the coils by opening the steam supply valves to each coil.
D.
Allow air (and any liquids or debris) to purge from the vent valves. Close each vent valve as it begins to blow steam.
E.
Open the upstream block valve of the steam trap on each coil and use the bleeder on each trap to drain water (and any other liquids) from each coil. Close the bleeder on each trap once hot condensate begins flowing through the trap.
F.
Open the test valve on each trap and confirm that each trap is operating properly. Then close the test valve and open the downstream block valve on each trap to place the traps in service to the condensate header.
G.
Repeat Steps A through F to commission the heating systems on each of the four sulfur rundown lines from the Sulfur Condenser and their associated Sulfur Drain Seal Assemblies. Open all of the vent valves on the steam jackets long enough to vent the air from the jackets.
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SULFUR BLOCK
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H.
Repeat Steps A through F to commission the heating systems on the air sweep vent stack, the Sulfur Surge Tank Vent Ejector, A2-EE1530 (A2-EE1540), the ejector suction line, and the ejector discharge line. Open all of the vent valves on the steam jackets long enough to vent the air from the jackets. In particular, use the vent line on the air sweep vent stack to vent the air from its steam jacket.
I.
Make sure that the breather vents at each end of the Sulfur Surge Tank are unobstructed and that the air sweep vent stack has begun to draft air into the tank through the breather vents.
J.
Check that the suction valve on the Sulfur Surge Tank Vent Ejector is closed and the discharge valve is open.
K.
Confirm that the globe valve in the motive steam line to the Sulfur Surge Tank Vent Ejector is closed, then open the upstream manual block valve in the line.
L.
Slowly open the globe valve to establish motive steam flow to the ejector. Verify that the steam is flowing at the proper rate (about 500 kg/H) on the steam flow meter in the DCS.
M.
Open the ejector suction valve. The ejector should now begin to overcome the natural-draft driving force of the air sweep vent and route the ventilation air from the pit to the Thermal Oxidizer.
N.
Confirm that all steam traps are functioning properly and that steam is flowing to the ejector before directing your attention away from the Sulfur Surge Tank.
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SULFUR BLOCK 9.7.8
Pre-filling the Sulfur Drain Seal Assemblies The Sulfur Drain Seal Assemblies, A2-ME1530A-D (A2-ME1540A-D), must be filled with molten sulfur in order to seal the pressurized process gases inside the SRU. The initial sulfur production when the SRU is first started up can be used to accomplish this as described in Section 9.8.2 of these guidelines. It is often convenient, however, to pre-fill the seals with sulfur prior to starting up the SRU. The blind flange on the top of each assembly can be removed to allow pouring sulfur into the drain seal to fill it. Pre-filling of the seals can be accomplished at any time after the steam heating for the sulfur rundown lines and Drain Seal Assemblies has been placed in service as described in the preceding section. Both molten sulfur and solid sulfur prills have been used for this purpose. If sulfur prills are used, proceed slowly enough so that the steam jackets on the seals can melt the sulfur. Continue to add sulfur to each seal until molten sulfur pours from its spill-over spout into its collection basin. Then bolt the blind flange back on the top of each seal assembly. If the drain seals are pre-filled in this fashion, the block valves in the sulfur rundown lines can be left open during the initial plant startup. Otherwise, these block valves must be closed when acid gas is first introduced to prevent hazardous process gases from escaping from the SRU. Section 9.8.2 of this manual describes how to use the sulfur produced during startup to fill the drain seals if they are not pre-filled.
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SULFUR BLOCK
9.8
Startup Procedures The procedure used to start up an SRU depends on whether the Reactor catalyst contains sulfur, and whether the refractory in the Reactor Furnace is up to operating temperature. This first section describes the procedure for the initial startup of a new plant. Subsequent startups will require a different procedure, and are discussed later (Sections 9.8.5 and 9.8.6 of this manual).
9.8.1
Initial Firing / Refractory Cure-out Only during the initial startup of an SRU can the warmup gases be routed through the entire sulfur plant. After a sulfur plant has been operated to produce sulfur, residual sulfur will always be present in the catalyst beds. If warmup gases containing free oxygen are routed through the catalyst beds during subsequent warmup periods, this residual sulfur will ignite, resulting in excessive temperatures which can cause equipment and/or catalyst damage. It should be noted that the auto-ignition temperature of sulfur on catalyst beds can be as low as 150°C when sufficient oxygen is present. During the initial startup, the Reactor Furnace and downstream equipment will be warmed up to operating conditions following the refractory vendor's cure-out schedule for the Reactor Furnace.
CAUTION IT IS CRITICAL THAT THE WARMUP PROCEDURES BE FOLLOWED VERY CLOSELY. THE REFRACTORY MATERIAL MUST BE HEATED SLOWLY TO ALLOW THE CONTAINED WATER TO VAPORIZE AND ESCAPE FROM THE REFRACTORY LINING, WITHOUT EXERTING EXCESSIVE INTERNAL PRESSURE AND CAUSING LINING DAMAGE.
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SULFUR BLOCK 9.8.1.1
Initial Preparations A.
Check that all devices in the SRU ESD have been satisfied, except for the following: (1)
Neither blower running.
(2)
Flame failure.
The PLC logic provides bypasses for these two conditions so that the system can be started up.
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B.
Confirm that the manual block valve in the SRU tailgas line is open.
C.
Confirm that the amine acid gas flow on/off switch, is set to "on" so that this flow will be included in the air:acid gas ratio control system.
D.
Select local manual control for the control valves on the Process Air Blower by switching process air hand switch (HS) in the DCS to "local".
E.
Place the air flow controller in "cascade".
F.
Place the air demand controller in "manual" and set its output to 50%.
G.
Confirm that the manual signal bias control for the blower to be used is set to 100% so that the control signals to the blower valves are not modified.
H.
Select local manual control for the fuel gas flow control valve, by switching the main fuel gas hand switch (HS) in the DCS to "local".
I.
Place the fuel gas flow controller in "automatic".
J.
Confirm that the fuel gas flow on/off switch is set to "on" so that this flow will be included in the air:acid gas ratio control system.
K.
Place the Reactor Furnace front zone temperature controller in the DCS in "automatic".
L.
Place the bypass acid gas flow ratio controller in "manual" and set its output to 0% so that control valve the bypass acid gas control valve will be fully closed.
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SULFUR BLOCK M.
Confirm that both boilers (Waste Heat Boiler and Sulfur Condenser) are filled with water up to their normal liquid levels.
N.
Verify that the four block valves in the sulfur rundown lines from the Sulfur Condenser are closed (unless the Sulfur Drain Seal Assemblies have been pre-filled with sulfur as described in Section 9.7.8 of this manual).
O.
During the early part of refractory cure-out, the startup thermocouple assembly furnished with the optical pyrometer, will be used to measure the furnace temperature, using their furnished hand-held digital display units. (Optical pyrometers are unreliable at temperatures below 200°C.) The thermocouple will be used until the third "hold" point (about 500°C) in the warmup schedule is reached. Loosen the wing nut on the hinged pyrometer fixture and swing the pyrometer out of the way. Unscrew the viewport len and remove it (be careful with the rubber o-ring gasket). Store the viewport lens in a safe place. Screw the thermocouple adapter housing onto the pyrometer mounting plate (with the o-ring in place). Open the pyrometer block valve, slide the thermocouple into the furnace, and tighten the packing gland on the end of the adapter housing.
P.
Confirm that the Acid Gas Firing switch on the local SRU control panel is set to "DISABLED".
Q.
Confirm that the Leak Test switch on the local SRU control panel is set to "NORMAL".
R.
Confirm that the Reactor Cool-Down switch on the local SRU control panel is set to "NORMAL".
S.
Set the manual amine acid gas control (HIC) on the local SRU control panel to 0% output. Visually confirm that the amine acid gas inlet valve is closed.
T.
Set the manual SWS gas control (HIC) on the local SRU control panel to 0% output. Visually confirm that the SWS gas inlet valve is closed.
U.
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Set the manual fuel gas control (HIC) on the local SRU control
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SULFUR BLOCK panel to 0% output. Visually confirm that the main fuel gas valve and the two automated shutdown valves are closed.
9.8.1.2
V.
Set the manual air control on the local SRU control panel to 0% output.
W.
Verify that the acid gas control valve in the amine acid gas line to the burner is fully open.
X.
Verify that the bypass acid gas control valve in the bypass acid gas line is fully closed.
Y.
Verify that the pilot burner mounting nozzle is being purged with nitrogen as indicated by its rotameter.
Igniting the Pilot Burner A.
Switch the Startup/Run selector switch on the local SRU control panel to "STARTUP". The PLC should perform the following actions: (1)
The two Warmup Bypass Valves are opened. The "WARMUP OPEN" status light on the local SRU control panel will flash until these valves have moved to the proper position, then remain steadily illuminated.
(2)
The nitrogen purge valve is closed.
(3)
The Tailgas Valve to the TTO is closed. The "TTO OPEN" status light will flash until this valve has moved to the proper position, then will be extinguished.
(4)
The Tailgas Valve to the TGCU is closed. The " TGCU OPEN" status light will flash until this valve has moved to the proper position, then will be extinguished.
NOTE:
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If a status light limit switches confirmed that position. If this
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continues to flash, it means that the on the associated valve(s) never the valve(s) moved to the proper occurs, the startup sequence will not
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SULFUR BLOCK be allowed to proceed until the problem is corrected and the valve(s) move to the proper position. Note that the valve may have actually moved to the proper position, but a faulty limit switch may not be detecting that the valve is in the proper position. Confirm that these valves have moved to the proper positions. Confirm that the "WARMUP OPEN" light on the panel is illuminated, and that the "TTO OPEN" and the "TGCU OPEN" lights on the panel are extinguished. B.
Verify that the local start/stop controls for the Process Air Blowers have their selector switches turned to the "STOP" position.
C.
Verify that the suction, discharge, and blow-off valves on both blowers are all closed.
D.
Start a Process Air Blower: (1)
Press the local push-button to give a “permit to start” for the desired blower. This will energize the solenoid valves on the blower suction and vent valves. The blower suction valve will open 33% and the blow-off valve will open 100%, but the discharge valve will remain closed. These valves will close again if the blower is not started within 30 seconds when the "permit to start" times out.
(2)
Start the blower using the local start/stop control station for that blower. When the blower starts, the solenoid valve on the blower discharge valve is also energized, but the valve will remain closed because the local process air flow controller (HIC) is set to 0% output.
Once the blower is started and comes up to speed, a flow of air will be established out of the blow-off valve and its silencer. Starting the blower with its suction throttling valve "pinched" allows the blower to start in an unloaded condition, which imposes less of a load on the blower and its motor.
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SULFUR BLOCK E.
Confirm that the air blower is running, then press the "ESD RESET" push-buttonon the local SRU control panel to reset the SRU ESD and extinguish the "RESET REQUIRED" light. This will illuminate the "PURGE REQUIRED" light.
F.
Verify that the "LIMITS SATISFIED" light is glowing steadily (not flashing) on the local SRU control panel. NOTE:
If the "LIMITS SATISFIED" light is flashing, this means that either a limit switch or a pressure transmitter is not satisfied. The limit switches on the amine acid gas valve, the SWS gas valve and the main fuel gas valves must all indicate that their respective valves are closed. The low-low pressure setpoint on the fuel gas supply and the high-high pressure setpoint on the fuel gas to the burner must both be satisfied. For safety reasons, the PLC will not allow the light-off sequence to proceed until all these conditions are satisfied. Once the problem with the valves, their limit switches, or the pressure transmitters has been corrected, the "LIMITS SATISFIED" light will stop flashing and glow steadily, and the light-off sequence can proceed.
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G.
Adjust the output of the air flow control (HIC) on the local SRU panel to open the blower control valves and allow a large air flow, 80% or more on the flow indicator on the local SRU control panel, to purge the entire system for about 5 minutes. The "PURGE REQUIRED" light will be extinguished and the "PURGE COMPLETE" light will be illuminated after about 30 seconds, but continue to purge the system for a full 5 minutes prior to this first time ignition attempt.
H.
Open the following manual block valves: (1)
The manual block valve(s) in the main fuel gas supply line.
(2)
The manual block valve(s) in the fuel gas supply line to the burner.
(3)
The manual block valve(s) in the fuel gas supply to the pilot.
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SULFUR BLOCK
I.
(4)
The manual block valve(s) in the instrument air supply to the pilot.
(5)
The manual block valve(s) in the instrument air supply to the pilot.
Adjust the output of the air flow control (HIC) on the local SRU panel to reduce the air flow to 10-20%. This will extinguish the "PURGE COMPLETE" light and illuminate the "PERMIT TO IGNITE" light and the PLC will "enable" the ignition circuit. NOTE:
Once the "PERMIT TO IGNITE" light is illuminated, an ignition safety interlock timer starts. If an ignition attempt is not made within 5 minutes, the SRU ESD system will be activated to shut down the sulfur plant. This prevents a potentially unsafe condition from persisting, where a leaking fuel gas valve could cause an explosive mixture to form in the Reactor Furnace, since the air flow is low at this point in the startup procedure. If either flame scanner detects a flame before the "IGNITION" push-button is pressed, this will activate the SRU ESD system and the "flame scanner malfunction" alarm in the DCS. This will stop the air blower and extinguish the flame (unless of course, a flame scanner is giving a false indication). A flame prior to ignition usually indicates a leaking fuel gas or acid gas valve. If this occurs, check these valves before proceeding with startup, as a leaking valve can allow an explosive mixture to form in the Reactor Furnace without warning.
J.
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Press the "IGNITION" push-button on the local SRU control panel to initiate an ignition attempt. The PLC will do the following: (1)
The nitrogen purge valve for the pilot burner is closed.
(2)
The pilot air automated block valve is opened.
(3)
The pilot gas automated vent valve is closed and the automated block valves are opened.
(4)
The ignition system is energized to begin sparking the
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SULFUR BLOCK ignitor inside the pilot. (5) K.
The air and fuel gas pressure regulators for the pilot may require some adjustment when first put in service before the pilot will light. However, once set properly, the pilot should ignite readily on subsequent startups. Refer to Section 9.11 of these guidelines for a suggested procedure to adjust these regulators.
L.
If neither flame scanner detects a flame after 15 seconds of sparking the ignitor, the ignition try is aborted, the SRU Burner Shutdown system is activated, and the PLC causes the sequence to return to Step G.
M.
When either flame scanner detects a flame from the pilot burner, the appropriate "MAIN FLAME ON" light(s) are illuminated. The pilot air and fuel gas valves will remain open after the ignition trial, and the PLC will perform the following activities:
N.
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The "PILOT ON" light is illuminated.
(1)
The "LIMITS SATISFIED" and "PERMIT TO IGNITE" lights are extinguished.
(2)
The "PILOT ON" light remains illuminated.
(3)
The ignition system is de-energized.
(4)
The startup bypass in the PLC for the "flame failure" S/D is disabled.
(5)
The "MAIN FUEL START" push-button on the local SRU control panel is enabled.
(6)
The "RUN" position on the Startup/Run selector switch on the local SRU control panel is enabled.
After the pilot is lit, use the air flow control (HIC) on the local SRU panel to increase the air flow rate to about 50% of scale, or as high a rate as can be maintained without blowing the pilot out. When curing refractory, it is best to keep the air flow as high as possible to help distribute the heat more evenly and to heat the downstream equipment more quickly.
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SULFUR BLOCK 9.8.1.3
Routing Warmup Gases Through the Entire SRU At this point, the warmup gases from the Acid Gas Burner are only flowing through the Reactor Furnace, the Waste Heat Boiler, and the first pass of the Sulfur Condenser. The Warmup Bypass Valves divert the gases from the first pass outlet of the Sulfur Condenser to the Thermal Oxidizer (the normal "startup" mode). For the initial firing of the SRU, the warmup gases are to be routed through the entire SRU as follows to cure-out the refractory in Reactor and to heat up all of the unit. A.
Switch the Startup/Run selector switch on the local SRU control panel to "RUN". The PLC will perform the following actions: (1)
The Tailgas Valve to the TTO is opened. The "TTO OPEN" status light will flash until this valve has moved to the proper position, then remain steadily illuminated.
(2)
After the limit switches prove this valve open, the two Warmup Bypass Valves are closed. The "WARMUP OPEN" status light will flash until these valves have moved to the proper position, then will be extinguished.
(3)
After the limit switches prove that at least one of these valves is closed, the nitrogen purge valve to the Warmup Bypass Line is opened.
NOTE:
If a valve status light continues to flash, it means that the limit switches on the associated valve(s) never confirmed that the valve(s) moved to the proper position. If this occurs, the startup sequence cannot proceed until the problem is corrected and the valve(s) move to the proper position.
Confirm that these valves have moved to the proper positions. Confirm that the "WARMUP OPEN" light on the panel is extinguished, the "TTO OPEN" light on the panel is illuminated, and the "TGCU OPEN" light on the panel remains extinguished.
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SULFUR BLOCK
9.8.1.4
B.
Open the vent valves on each of the two boilers to vent air from the steam sections.
C.
Confirm that the BFW level controllers and control valves to the Waste Heat Boiler and Sulfur Condenser are in service and functioning properly.
D.
The heat input from the pilot should be sufficient to reach the first "hold" point in the refractory warmup schedule, 100-150°C. If the temperature is too high, increase the air flow rate. If the temperature is too low, decrease the air flow rate.
Igniting the Main Warmup Burner When the firing rate needs to be increased to raise the furnace temperature, the main warmup burner can be placed in service. The control valve in the main fuel gas line will be used to control the fuel gas flow rate. A.
Confirm that the flow control valve in the main fuel gas line is fully closed.
B.
Confirm that the manual block valve(s) in the main fuel gas line to the burner is (are) open.
C.
If the air flow rate is not at 50% of scale, use the air flow control (HIC) on the local SRU panel to set the air flow at about 50% of scale.
D.
Press the "MAIN FUEL START" push-button on the local SRU control panel to commission the main fuel gas. The PLC performs the following actions:
E.
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(1)
The nitrogen purge valve for the main warmup burner is closed.
(2)
The main fuel gas automated vent valve is closed.
(3)
The main fuel gas automated block valves are opened.
(4)
The "MAIN FUEL ON" light on the local control panel is illuminated.
Adjust the output of the main fuel gas flow control (HIC) on the local SRU control panel to slowly open the control valve to commence fuel gas flow to the warmup burner ring. Adjust the
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SULFUR BLOCK fuel gas flow rate until a stable flame can be maintained. Note that the fuel gas flow rate will be indicated on the local panel and in the DCS. 9.8.1.5
Refractory Cure-out and Warmup With the main fuel gas ring on the Acid Gas Burner in service, its firing rate can now be adjusted to control the refractory cure-out of the Reactor Furnace. A.
Adjust the fuel gas flow rate with the main fuel gas flow control (HIC) on the local control panel as necessary to cause the furnace temperature to follow the refractory cure-out schedule for the initial cure supplied by the refractory vendor. It is often helpful to maintain a log of the air flow, the fuel gas flow, and the furnace temperature during the cure-out for future reference.
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B.
Frequently confirm that the proper water levels are maintained in the Waste Heat Boiler and the Sulfur Condenser. Confirm that the level control systems are functioning properly.
C.
As the steam pressure starts to build in the Waste Heat Boiler, put the Waste Heat Boiler Steam pressure controller in the DCS in "automatic" with a setpoint of 48.5 kg/cm2(g).
D.
Place the three temperature controllers for the Reactor feeds in "manual" and set their outputs to 100% to fully open the valves in the condensate outlet lines from the reheat exchangers. This will ensure that the feeds are as hot as possible for curing the refractory in the three chambers of the Reactor.
E.
As the steam pressure starts to build in the Sulfur Condenser, put the Sulfur Condenser steam pressure controller in the DCS in "automatic" with a setpoint of 4.2 kg/cm2(g).
F.
Once the third "hold" point in the cure-out schedule has been reached (about 500°C), the optical pyrometer can be placed in service. After the furnace temperature has stabilized, loosen the packing gland on the thermocouple adapter housing and slide the thermocouple out until the "keeper" stops it. Close the pyrometer block valve then unscrew the adapter housing and
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SULFUR BLOCK store it in a safe place. CAUTION:
THE THERMOCOUPLES WILL BE VERY HOT. HANDLE THEM CAREFULLY TO AVOID BURNS AND TO AVOID DAMAGING THE THERMOCOUPLES.
Screw the viewport lens back onto the pyrometer mounting plate (with the o-ring in place), swing the pyrometer back into place, tighten the wing nut, and open the pyrometer block valve. Open the block valve in the pyrometer purge system to begin purging the viewport lens and nozzle with nitrogen. Verify that the purge to the pyrometer viewport is operating properly. The furnace temperature will now be indicated over the full range of the pyrometer on the local digital indicators mounted near the pyrometer. The controller in the DCS will also indicate the furnace temperature. G.
Commission all steam heating systems on the sulfur rundown lines, sulfur drain seals, sulfur surge tank, sulfur pumps, and valve jackets if these are not already in service. Check all steam traps for proper operation, and use the vent valves to sweep non-condensibles out of the steam spaces.
H.
As the equipment and piping heat up, inspect all of the equipment and piping for the effects of thermal expansion.
I.
As the steam pressures build in the boilers, the vent valves on the steam spaces may be closed.
At the conclusion of this procedure, the SRU is ready to process acid gas. However, if the acid gas feed from the Amine Regeneration Unit is not yet available, the SRU can run indefinitely in this mode until the other systems are ready. Monitor the Reactor Furnace temperature and make adjustments to the fuel gas flow as needed to control this temperature around 1200°C.
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SULFUR BLOCK 9.8.2
Amine Acid Gas Flow At the end of the refractory cure-out schedule, the SRU is firing on fuel gas and is ready to accept acid gas. The switch to acid gas firing is accomplished by gradually swapping acid gas for fuel gas. A.
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Before commencing acid gas flow, confirm that the following conditions are all true: (1)
The feed temperatures to all three chambers of the Reactor are 205°C or higher.
(2)
The steam pressure in the Sulfur Condenser is 4.2 kg/cm2(g) or higher.
(3)
The Thermal Oxidizer is ready to accept SRU tailgas.
(4)
All vent and drain valves on the Acid Gas Knock-Out Drum, its piping, and the Acid Gas Knock-Out Drum Pump are closed and plugged.
(5)
Any blinds installed in the amine acid gas line have been removed.
(6)
The block valves are lined up to place an Acid Gas Knock-Out Drum Pump in service, the selector switch on that pump is set to "AUTO", and the pump level control transmitter is in service.
B.
Confirm that the bypass acid gas flow ratio controller in the DCS is still in "manual" with its output set to 0%. This ensures that the bypass acid gas control valve will remain closed so that all of the amine acid gas will flow to the Acid Gas Burner.
C.
Adjust the process air flow rate to 50% of scale on the local indicator using the air flow control (HIC) on the local SRU panel. Reduce the fuel gas flow rate to 50% of scale on the local indicator using the main fuel gas flow control (HIC) on the local panel.
D.
Because of the procedure used for this initial firing, the Warmup Bypass Valves are already closed and the Tailgas Valve to the Thermal Oxidizer is already opened. Thus, the flowpath through the SRU is already set correctly for introducing acid gas.
E.
Switch the Acid Gas Firing selector switch on the local SRU control panel to "ENABLED".
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SULFUR BLOCK F.
Slowly increase the output from the amine acid gas flow control (HIC) on the local SRU control panel to begin opening the amine acid gas inlet valve until the acid gas flow rate is approximately 10% on the indicator on the local SRU control panel.
G.
As soon as the acid gas flow rate reaches 10%, use the main fuel gas flow control (HIC) to reduce the fuel gas flow rate from 50% to 40% on the local indicator.
H.
Continue to add amine acid gas in 10% increments and reduce the fuel gas in 10% increments until the fuel gas control valve is completely closed.
I.
Press the “FUEL GAS OFF” push-button on the local SRU control panel. The PLC performs the following actions to "double block and bleed" the main fuel gas: (1)
The main fuel gas automated block valves are closed.
(2)
The main fuel gas automated vent valve is opened.
(3)
The nitrogen purge valve for the main burner is opened.
(4)
The “FUEL GAS ON” light is extinguished.
Verify that the that the fuel gas valves have moved to their proper positions and that the main fuel gas burner ring is being purged with nitrogen as indicated by the associated rotometer. J.
Press the "PILOT OFF" push-button on the local SRU control panel. The PLC performs the following actions to block the pilot air and "double block and bleed" the pilot fuel gas:
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(1)
The aitmated block valve in the air supply to the pilot is closed.
(2)
The pilot fuel gas automated block valves are closed.
(3)
The pilot fuel gas automated vent valve is opened.
(4)
The automated nitrogen purge valve for the pilot burner is opened.
(5)
The "PILOT ON" light is extinguished.
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SULFUR BLOCK Verify that the air and fuel gas valves have moved to their proper positions and that the pilot burner is being purged with nitrogen as indicated by the associated rotameter. K.
Continue to slowly increase the output from the amine acid gas flow control (HIC) to 100% so that the amine acid gas inlet valve is fully open.
L.
If the amine acid gas flow rate (in percent) displayed on the local control panel is significantly different from the air flow rate (in percent) displayed on the local control panel, use the air flow control (HIC) on the local SRU panel to adjust the air flow until the percentages are about the same. This should put the air:acid gas ratio reasonably close to where it should be.
M.
Close the following manual block valves:
N.
(1)
The two manual block valve(s) in the main fuel gas line.
(2)
The manual block valve(s) in the fuel gas to the pilot.
(3)
The manual block valve(s) in the instrument air to the pilot.
Loosen the packing gland on the pilot and retract or extract the pilot assembly: (1)
(2)
Issued 30 August 2011
If the pilot is just to be retracted: (a)
Retract it until it reaches the limit of the retraction bar.
(b)
Tighten the packing gland on the pilot.
(c)
Verify that the pilot burner is still being purged with nitrogen as indicated by the associated rotameter.
If the pilot is to be completely extracted: (a)
Retract it until the retaining chain is taut.
(b)
Close the block valve to isolate the pilot from the furnace.
(c)
Close the block valve in the nitrogen purge to the pilot burner.
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SULFUR BLOCK (d)
Disconnect the chain and remove the pilot assembly and store it in a safe place. CAUTION: THE PILOT ASSEMBLY WILL BE VERY HOT. HANDLE IT CAREFULLY TO AVOID BURNS AND TO AVOID DAMAGING IT.
(3) O.
Verify that the pilot burner mounting nozzle is still being purged with nitrogen as indicated by the associated rotometer.
Place the air:acid gas ratio control loop in service as follows: (1)
Confirm that the air demand controller in the DCS is in "manual" and its output is set at 50%.
(2)
Confirm that the process air flow controller in the DCS is in "cascade".
(3)
Confirm that the output of the process air flow controller is tracking the output of the manual air control on the local SRU control panel.
(4)
Confirm that the setpoint of the process air flow controller is tracking its current reading.
(5)
Confirm that the "coarse" setting of the air:acid gas manual ratio set (HIC) is being back-calculated so that the remote setpoint it supplies to the process air flow controller matches the current "local" air flow setpoint on the controller.
(6)
Switch the process air hand switch (HS) from "local" to "remote".
The DCS process air flow controller now has control of the control valves on the Process Air Blower, so that the process air flow rate will be ratio-controlled automatically with the amine acid gas flow rate. The output from the manual ratio set (HIC) will remain fixed at its last value. P.
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Observe the temperatures in the catalyst beds and in the Reactor outlet lines. These temperatures should begin to rise as the Claus reaction is initiated. Watch the steam pressures and water levels in the boilers to confirm that the control systems are functioning Sulfur Recovery
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SULFUR BLOCK properly. Q.
If the Sulfur Drain Seals were not pre-filled with liquid sulfur to seal them prior to startup, the block valves in the rundown lines will all be closed at this time. After operating on acid gas for about 30 minutes, open the block valve on the first condenser pass drain line. Sufficient sulfur should have been produced by then to seal this drain seal. If the drain seal does not seal within 30 seconds, close the valve and try it again every 30 minutes or so until it seals.
R.
After the first drain seals, open the block valve to the second drain seal at approximately one hour intervals until it seals. Repeat this with the third and fourth drain seals.
WARNING
MAKE SURE EACH DRAIN SEAL HAS SEALED BEFORE LEAVING ITS BLOCK VALVE OPEN. IF THE BLOCK VALVE TO AN UNSEALED DRAIN SEAL REMAINS OPEN, PROCESS GAS CONTAINING POISONOUS H2S AND SO2 WILL ENTER THE SULFUR SURGE TANK AND BE RELEASED TO THE SURROUNDING AREA. S.
After operating for a few hours on acid gas, the process temperatures can be lowered somewhat from the levels established during startup. (1)
Confirm that the Waste Heat Boiler steam pressure controller is set at 48.5 kg/cm2(g) and is controlling.
(2)
The three reactor feed temperature controllers are in "manual" at this time. Confirm that their setpoints are tracking their current readings then switch the controllers to "automatic". Slowly reduce the temperature setpoints to their normal values.
(3)
Adjust the setpoint of the Sulfur Condenser steam pressure controller to 1.75 kg/cm2(g). This will cause the steam back-pressure control valve on the Sulfur Condenser to remain wide open under normal
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SULFUR BLOCK circumstances, allowing the steam pressure to remain as low as possible by "floating" on the LP steam header. Keeping the steam pressure as low as possible in the Sulfur Condenser allows it to remove the maximum amount of sulfur from the process streams and reduces the load on the downstream TGCU. Giving the Sulfur Condenser steam pressure controller a setpoint of 1.75 kg/cm2(g) will ensure that the water in the Sulfur Condenser shell stays safely above the freezing temperature of sulfur by causing the steam pressure control valve to maintain back-pressure in the shell of the Sulfur Condenser if the pressure in the steam header should drop below this value for any reason. T.
If the air demand analyzer is not in service and operating properly after the SRU has been on-stream for 24 hours, manually analyze a sample of the process gas leaving the fourth pass of the Sulfur Condenser to determine the H2S:SO2 ratio, using one of the laboratory procedures in Section 9.10 of this manual. As discussed earlier, maximum sulfur recovery is obtained when the H2S:SO2 ratio is 2:1. If the H2S:SO2 ratio is higher than 2:1, the SRU is running with less than optimum air (i.e., "air deficient"). Increase the setting on the air:acid gas manual ratio set (HIC) to raise the air:acid gas ratio and reduce the H2S:SO2 ratio in the process gas. If the H2S:SO2 ratio is lower than 2:1, the SRU is running with more than optimum air (i.e., "excess air"). Reduce the setting on the air:acid gas manual ratio set (HIC) to lower the air:acid gas ratio and increase the H2S:SO2 ratio in the process gas.
U.
If the air demand analyzer is in service, adjust the air:acid gas ratio as necessary with the air:acid gas manual ratio set (HIC) to bring the air demand displayed on the air demand controller "on-scale" (between -10.0% and +10.0%). If the air demand is high (0.0% to +10.0%), the air:acid gas ratio is too high (i.e., "excess air"). Reduce the setting on the air:acid gas manual ratio set (HIC) to lower the air:acid gas ratio and reduce the air demand. If the air demand is low (-10.0% to 0.0%), the air:acid gas ratio is too low (i.e., "air deficient"). Increase the setting on the air:acid gas
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SULFUR BLOCK manual ratio set (HIC) to raise the air:acid gas ratio and increase the air demand. Once the air demand is "on-scale", switch the air demand controller to "automatic" and adjust its setpoint to 0.0% air demand. the air demand controller will now adjust the ratio setting from the air:acid gas manual ratio set (HIC) via relays to keep a 2:1 H2S:SO2 ratio in the tailgas leaving the SRU. V.
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The sulfur plant is now on-stream, firing on amine acid gas. Before bringing in SWS gas or directing your attention away from the SRU, be sure that: (1)
All controllers are functioning properly.
(2)
Sulfur is draining freely from each rundown line.
(3)
All steam heating systems are in service and the steam traps are functioning properly.
(4)
The Warmup Bypass Valves are fully closed.
(5)
The Thermal Oxidizer is functioning properly.
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SULFUR BLOCK 9.8.3
SWS Gas Flow Once the SRU is operating stably on amine acid gas, the SWS gas stream can be introduced into the SRU. Do not attempt to bring in the SWS gas if the SRU is not running smoothly on amine acid gas, as this will make it that much harder to stabilize the unit. Instead, focus your attention on stabilizing the operation of the SRU first (usually by correcting a problem in the upstream Amine Regeneration Unit), and then use the procedure below to establish SWS gas flow into the SRU. Before commencing SWS gas flow, it will be necessary to raise and control the temperature in the front combustion zone of the Reactor Furnace to prepare it for ammonia destruction. A.
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Before beginning, confirm that the following conditions are all true: (1)
SWS gas flow on/off switch in the DCS is set to "on" so that this flow will be included in the air:acid gas ratio control system.
(2)
All vent and drain valves on the SWS Gas Knock-Out Drum, its piping, and the SWS Gas Knock-Out Drum Pump are closed and plugged.
(3)
Any blinds installed in the inlet SWS gas line have been removed.
(4)
The block valves are lined up to place a SWS Gas Knock-Out Drum Pump in service, the H-O-A selector switch on that pump is set to "AUTO", and the pump level control transmitter is in service.
B.
At this time, the bypass amine acid gas flow ratio controller in the DCS is in "manual" with its output set to 0%. As a result, the bypass acid gas control valve is closed, forcing all of the amine acid gas to flow to the Acid Gas Burner.
C.
Confirm that the Reactor Furnace front zone temperature controller is in "automatic".
D.
Confirm that the setpoint of the bypass acid gas flow ratio controller is tracking its current reading (which should be zero), then switch it to "automatic".
E.
Slowly raise the ratio setpoint on the bypass acid gas flow ratio controller to begin opening the bypass acid gas control valve and
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SULFUR BLOCK bypassing some of the amine acid gas to the side injection ports on the furnace. This should begin to raise the temperature in the front zone of the furnace. F.
Continue to raise the ratio setpoint on the bypass acid gas flow ratio controller until the temperature indicated on the front zone temperature controller is approximately 1200°C. NOTE:
The 1370°C temperature for ammonia destruction discussed in earlier sections is a calculated temperature. The temperature indicated by an optical pyrometer is usually 100-200°C lower than the calculated temperature for a given set of conditions, so a normal operating temperature of 1200°C is suggested for the front zone of the furnace. Operating experience will dictate the minimum indicated temperature at which SWS gas can be admitted to the furnace.
G.
It may become necessary for the bypass acid gas flow ratio controller to "pinch" flow control valve on the amine acid gas to the acid gas burner in order to obtain enough bypass acid gas flow through the bypass acid gas control valve. After the bypass acid gas flow ratio controller is controlling the bypass acid gas flow and the furnace temperature is up to about 1200°C, the furnace is ready to accept SWS gas.
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H.
Slowly increase the output from the SWS gas flow control (HIC) on the local SRU control panel to begin opening the SWS gas inlet valve using the flow indicator on the local SRU control panel to monitor the SWS gas flow rate.
I.
As SWS gas begins flowing to the Acid Gas Burner, the air:acid gas ratio control system will begin sending additional process air to the burner to combust the SWS gas. Increase the SWS gas flow slowly to allow time for the ratio control system to adjust to the increasing SWS gas flow.
J.
Continue to slowly increase the output from the SWS gas flow control (HIC) to 100% so that the SWS gas inlet valve is fully open.
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SULFUR BLOCK K.
Monitor the bypass acid gas flow ratio controller to verify that it maintains control of the bypass acid gas flow and that the front zone temperature in the Reactor Furnace remains about 1200°C.
L.
Observe the air demand controller and adjust the air:acid gas ratio with the air:acid gas manual ratio set (HIC) if necessary to help keep the air demand "on-scale". If the air demand is high (0.0% to +10.0%), reduce the output from the air:acid gas manual ratio set (HIC) to lower the ratio and reduce the air demand. If the air demand is low (-10.0% to 0.0%), increase the output from the air:acid gas manual ratio set (HIC) to raise the ratio and increase the air demand.
M.
N.
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If the optical pyrometer on the Reactor Furnace is giving reliable indication of the front zone temperature in the furnace the temperature cascade control can be placed in service as follows: (1)
Confirm that the remote ratio setpoint that the front zone temperature controller is supplying to the bypass ratio controller matches the current setting on the ratio controller.
(2)
Confirm that the front zone temperature controller is in "automatic" and its setpoint is tracking its current reading.
(3)
Switch the bypass acid gas flow ratio controller to "cascade" so that the temperature controller can now adjust the ratio setpoint on the ratio controller.
(4)
If necessary, slowly adjust the setpoint of the front zone temperature controller to its normal setpoint of 1200°C.
(5)
Verify that the bypass acid gas flow ratio controller is adjusting the bypass gas flow rate as needed to control the desired temperature setting on the front zone temperature controller.
The sulfur plant is now fully on-stream, firing on both amine acid gas and SWS gas. Before switching the SRU tailgas to the TGCU or directing your attention away from the SRU, be sure that: (1)
All controllers are functioning properly.
(2)
Sulfur is draining freely from each rundown line.
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SULFUR BLOCK
9.8.4
(3)
All steam heating systems are in service and the steam traps are functioning properly.
(4)
The Thermal Oxidizer is functioning properly.
Routing SRU Tailgas to the TGCU Before switching the SRU tailgas from the Thermal Oxidizer to the TGCU Tailgas Cleanup Unit, be sure all of the following conditions are true: (1)
The SRU is operating stably on amine acid gas, or on amine acid gas and SWS gas.
(2)
The air demand indicated on the air demand controller is +2.0% or lower.
If the air demand is higher than this, the SRU tailgas contains excessive amounts of SO2 and could cause overheating of the TGCU Reactor in the TGCU. (3)
The TGCU has been warmed up to operating temperature and is ready to accept SRU tailgas.
If any of these conditions are not true, do not attempt to bring SRU tailgas into the TGCU. In particular, do not attempt switching tailgas to the TGCU when the sulfur plant is upset. The result will be two upset units to deal with. Instead, focus your attention on stabilizing the operation of the SRU first (usually by correcting a problem in the upstream Amine Regeneration Unit and/or Sour Water Stripper Unit). Then use the operating procedures for the TGCU in Section 11 of these guidelines to switch the SRU tailgas from flowing to the Thermal Oxidizer to flowing into the TGCU. Once the sulfur plant tailgas is flowing to the TGCU, be sure of the following before directing your attention away from the SRU:
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(1)
The Tailgas Valve to the TTO and the TGCU Warmup/Bypass Valve are fully closed.
(2)
This is necessary to prevent leakage of SRU tailgas to the TTO that would cause high SO2 emissions and the resulting permit violation.
(3)
All controllers are functioning properly.
(4)
Sulfur is draining freely from each rundown line.
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SULFUR BLOCK
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(5)
All steam heating systems are in service and the steam traps are functioning properly.
(6)
The TGCU and the Thermal Oxidizer are functioning properly.
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SULFUR BLOCK 9.8.5
Normal Startup - Cold System The procedure for startup of an SRU after it has been shut down long enough to get cold (less than about 750°C in the Reactor Furnace) will be very similar to the procedure for the initial startup, Sections 9.8.1 through 9.8.4 of this manual. However, the steps to be performed are written in this section to serve as a "check list" that can be easily followed on subsequent startups. Refer to the previous sections for the reasons and details pertaining to the different steps performed.
NOTE
THIS PROCEDURE USES THE WARMUP BYPASS VALVES TO ROUTE THE FUEL GAS COMBUSTION PRODUCTS DIRECTLY TO THE THERMAL OXIDIZER WHILE WARMING UP THE SRU. (THIS PREVENTS OXYGEN-BEARING GASES FROM REACHING THE REACTOR BEDS AND CAUSING SULFUR FIRES IN THE CATALYST.) IT IS NORMAL TO PRODUCE A SMALL SO2 PLUME FROM THE THERMAL OXIDIZER WHEN USING THE WARMUP BYPASS LINE AS THE OXYGEN IN THE COMBUSTION GAS REACTS WITH THE SULFUR COATING THE WALLS OF THE PIPING AND EQUIPMENT TO FORM SO2. HOWEVER, IF A LARGE AMOUNT OF SO2 IS BEING RELEASED FROM THE STACK, THIS MAY BE AN INDICATION THAT SULFUR HAS ACCUMULATED INSIDE THE SRU FOR SOME REASON. TO PREVENT DAMAGE TO THE EQUIPMENT, SHUT DOWN THE SRU AND VERIFY THAT THE FIRST PASS OF THE SULFUR CONDENSER IS NOT FILLED WITH SULFUR BEFORE CONTINUING.
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SULFUR BLOCK Prior to commencing SRU startup:
9.8.5.1
(1)
Check for the completion of all maintenance work (connecting lines, removing blinds, etc.) if such work was performed.
(2)
If any of the flanged connections in the SRU were opened for maintenance or other purposes while the SRU was off-line, it is good practice to leak test the SRU before returning it to service. Refer to Section 9.7.3 of this manual for a suggested procedure to accomplish this.
(3)
Place all steam heating systems in service. Check all steam traps for proper operation, and use the vent valves to sweep non-condensibles out of the steam spaces.
(4)
Physically check all shutdown activating devices to ensure that they activate the SRU ESD system.
(5)
Check all devices activated by the SRU ESD system to ensure that they operate properly.
(6)
Confirm that both boilers (Waste Heat Boiler and Sulfur Condenser) are filled with water up to their normal liquid levels.
(7)
If the furnace temperature is less than 250°C, insert the startup thermocouple assembly furnished with the optical pyrometer by swinging the pyrometer out of the way, removing the viewport, and attaching the thermocouple adapter to the mounting plate.
Initial Preparations A.
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Check that all devices in the SRU ESD have been satisfied, except for the following: (1)
Neither blower running.
(2)
Flame failure.
B.
Confirm that the manual block valve in the SRU tailgas line is open.
C.
Confirm that the amine acid gas flow on/off switch is set to "on".
D.
Select local manual control for the control valves on the Process Air Blower by switching the process air hand switch (HS) in the DCS to "local".
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SULFUR BLOCK E.
Place the process air flow controller in "cascade".
F.
Place the air demand controller in "manual" and set its output to 50%.
G.
Confirm that the manual signal bias control for the blower to be used is set to 100%.
H.
Select local manual control for the fuel gas flow control valve by switching the main fuel gas hand switch (HS) in the DCS to "local".
I.
Place the fuel gas flow controller in "automatic".
J.
Confirm that the fuel gas flow on/off switch is set to "on".
K.
Place the Reactor Furnace front zone temperature controller in "automatic".
L.
Place the bypass acid gas flow controller in "manual" and set its output to 0%.
M.
Confirm that Acid Gas Firing switch on the local SRU control panel is set to "DISABLED".
N.
Confirm that Leak Test key switch on the local SRU control panel is set to "NORMAL".
O.
Confirm that Reactor Cool-Down key switch on the local SRU control panel is set to "NORMAL".
P.
Set the amine acid gas flow control (HIC) and the SWS gas flow control (HIC) on the local SRU control panel to 0% output. Visually confirm that the amine acid gas inlet valve and the SWS gas inlet valve are closed. If either of these valves is not closed, H2S will be routed directly to the Thermal Oxidizer when the Warmup Bypass Valves are opened. This could cause overheating of the Thermal Oxidizer.
Q.
Set the manual fuel gas control on the local SRU control panel to 0% output. Visually confirm that the main fuel gas valve and the two shutdown valves are closed.
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SULFUR BLOCK
9.8.5.2
R.
Set the air flow control (HIC) on the local SRU panel to 0% output.
S.
Verify that the acid gas control valve in the amine acid gas line to the burner is fully open.
T.
Verify that the bypass acid gas control valve in the bypass acid gas line is fully closed.
U.
Loosen the packing gland on the pilot mounting nozzle. If the pilot was extracted previously, insert the pilot assembly, connect its retaining chain, and open the block valve. Slide the pilot all the way in then tighten the packing gland. Open the block valve in the purge nitrogen to the pilot and confirm that the pilot and the pilot mounting nozzle are both being purged with nitrogen.
Igniting the Pilot Burner A.
Switch the Startup/Run selector switch on the local SRU control panel to "STARTUP". The PLC will open the two Warmup Bypass Valves and close the Tailgas Valve to the TTO and the Tailgas Valve to the TGCU. Verify that the "WARMUP OPEN" light on the panel is now illuminated and the "TTO OPEN" and "TGCU OPEN" lights on the panel are extinguished. NOTE:
Issued 30 August 2011
If a status light continues to flash, it means that the limit switches on the associated valve(s) never confirmed that the valve(s) moved to the proper position. If this occurs, the startup sequence will not be allowed to proceed until the problem is corrected and the valve(s) move to the proper position.
B.
Verify that the local start/stop controls for the Process Air Blowers have their selector switches turned to the "STOP" position.
C.
Verify that the suction, discharge, and blow-off valves on both blowers are all closed.
D.
Start a Process Air Blower:
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SULFUR BLOCK (1)
Press the local push-button to give a “permit to start” for the desired blower.
(2)
Start the blower using the local start/stop control station for that blower.
E.
Confirm that the air blower is running, then press the "ESD RESET" push-button on the local SRU control panel to reset the SRU ESD and extinguish the "RESET REQUIRED" light. This will illuminate the "PURGE REQUIRED" light.
F.
Verify that the "LIMITS SATISFIED" light is glowing steadily (not flashing) on the local SRU control panel. NOTE:
If the "LIMITS SATISFIED" light is flashing, this means that either a limit switch or a pressure transmitter is not satisfied. The limit switches on the amine acid gas, SWS gas, and fuel gas valves must all indicate that their respective valves are closed, and the two pressure transmitters on the main fuel gas must be satisfied. For safety reasons, the BMS will not allow the light-off sequence to proceed until all these conditions are satisfied. Once the problem with the valves, their limit switches, or the pressure transmitters has been corrected, the "LIMITS SATISFIED" light will stop flashing and glow steadily, and the light-off sequence can proceed.
G.
Issued 30 August 2011
Open the following manual block valves: (1)
The manual block valve(s) in the main fuel gas supply line.
(2)
The manual block valve(s) in the fuel gas supply line to the burner.
(3)
The manual block valve(s) in the fuel gas supply to the pilot.
(4)
The manual block valve(s) in the instrument air supply to the pilot.
(5)
The manual block valve(s) in the instrument air supply to the pilot.
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SULFUR BLOCK H.
Adjust the output of the air flow control (HIC) on the local SRU panel to open the blower control valves and allow a large air flow, 80% or more the flow indicator, to purge the furnace for 30 seconds and extinguish the "PURGE REQUIRED" light. The "PURGE COMPLETE" light will then be illuminated.
I.
Adjust the output of the air flow control (HIC) on the local SRU panel to reduce the air flow to 10-20%, extinguishing the "PURGE COMPLETE" light and illuminating the "PERMIT TO IGNITE" light. NOTE:
J.
Press the "IGNITION" push-button to initiate an ignition attempt.
K.
If neither flame scanner detects a flame after 15 seconds of sparking the ignitor, the ignition try is aborted, the SRU Burner Shutdown system is activated, and the PLC causes the sequence to return to Step G.
L.
When either flame scanner detects a flame from the pilot burner, the pilot air and fuel gas valves remain open, the "PILOT ON" light remains illuminated, and the PLC enables the "FUEL GAS ON" push-button and the "RUN" position on the Startup/Run selector switch.
M.
After the pilot is lit, use the air flow control (HIC) on the local SRU panel to increase the air flow rate to about 50% of scale, or as high a rate as can be maintained without blowing the pilot out.
N.
Open the vent valves on each of the two boilers to vent air from the steam sections.
O.
The heat input from the pilot will be sufficient during the early part of the refractory warmup schedule. If the temperature is rising too quickly, increase the air flow rate. If the temperature is rising too slowly, decrease the air flow rate. NOTE:
Issued 30 August 2011
Remember that the ignition safety timer will shut down the SRU if an ignition attempt is not made within 5 minutes of receiving the "PERMIT TO IGNITE".
The refractory warmup schedule for normal warmup, (supplied by the refractory vendor), should be used for normal startup with a cold system.
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SULFUR BLOCK 9.8.5.3
Igniting the Main Warmup Burner / Refractory Warmup When the firing rate needs to be increased to raise the furnace temperature, the main warmup burner should be placed in service. A.
Confirm that in the main fuel gas line is fully closed.
B.
Confirm that the manual block valve(s) in the main fuel gas line to the burner is open.
C.
If the air flow rate is not at 50% of scale, use the air flow control (HIC) on the local SRU panel to set the air flow at about 50% of scale.
D.
Press the "FUEL GAS ON" push-button on the local SRU control panel to open the main fuel gas block valves and illuminate the “FUEL GAS ON” light.
E.
Adjust the output of the main fuel gas flow control (HIC) on the local control panel to slowly open the control valve to commence fuel gas flow to the warmup burner ring. Adjust the fuel gas flow rate until a stable flame can be maintained.
F.
Adjust the fuel gas flow rate with the main fuel gas flow control (HIC) as necessary to cause the furnace temperature to follow the refractory warmup schedule for normal warmup.
G.
Frequently confirm that the proper water levels are maintained in the Waste Heat Boiler and the Sulfur Condenser. Confirm that the level control systems are functioning properly.
H.
As the steam pressure starts to build in the Waste Heat Boiler, put the Waste Heat Boiler Steam pressure controller in the DCS in "automatic" with a setpoint of 48.5 kg/cm2(g).
I.
Place the three temperature controllers for the Reactor feeds, in "manual" and set their outputs to 100%. This will fully open the valves in the condensate outlet lines from the reheat exchangers and ensure that the Reactor feeds are as hot as possible when the switch to acid gas firing is made.
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SULFUR BLOCK J.
As the steam pressure starts to build in the Sulfur Condenser, put the Sulfur Condenser steam pressure controller in the DCS in "automatic" with a setpoint of 4.2 kg/cm2(g).
K.
During the early part of warmup, monitor the furnace temperature using the startup thermocouple assembly and the hand-held digital display unit. The thermocouple will be used until the first "hold" point (about 250°C) in the warmup schedule is reached. Once the first "hold" point in the warmup schedule has been reached, the optical pyrometer can be placed in service. After the furnace temperature has stabilized, slide the thermocouple out until the "keepers" stop them, close the pyrometer block valve, then unscrew the adapter housing and store them in a safe place. CAUTION:
THE THERMOCOUPLES WILL BE VERY HOT. HANDLE THEM CAREFULLY TO AVOID BURNS AND TO AVOID DAMAGING THE THERMOCOUPLES.
Replace the viewport lens on the pyrometer mounting plate (with the o-ring in place) and put the pyrometer back in service so that the furnace temperature is indicated on the local indicator and the controller in the DCS. Confirm that the purge system for the pyrometer viewport lens is operating. L.
Confirm that all steam heating systems on the sulfur rundown lines, sulfur drain seals, sulfur collection header, sulfur pump, and valve jackets are in service. Check all steam traps for proper operation, and use the vent valves to sweep non-condensibles out of the steam spaces.
M.
As the steam pressures build in the boilers, the vent valves on the steam spaces may be closed.
At the conclusion of this procedure, the SRU is ready to process acid gas. However, the SRU can run indefinitely in this mode until the other systems are ready. Monitor the Reactor Furnace temperature on the furnace temperature controller and make adjustments to the fuel gas flow as needed to control this temperature around 1200°C.
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SULFUR BLOCK 9.8.5.4
Amine Acid Gas Flow At the end of the refractory warmup schedule, the SRU is firing on fuel gas (using the warmup bypass line to divert the combustion products to the Thermal Oxidizer) and is ready to accept acid gas. The switch to acid gas firing is accomplished by routing the combustion products through SRU, then rapidly swapping acid gas for fuel gas. A.
Issued 30 August 2011
Before commencing acid gas flow, confirm that the following conditions are all true: (1)
The steam pressure in the Waste Heat Boiler is 48.5 kg/cm2(g) or higher.
(2)
The steam pressure 4.2 kg/cm2(g) or higher.
(3)
The Thermal Oxidizer is ready to accept SRU tailgas.
(4)
All vent and drain valves on the Acid Gas Knock-Out Drum, its piping, and the Acid Gas Knock-Out Drum Pump are closed and plugged.
(5)
The block valves are lined up to place an Acid Gas Knock-Out Drum Pump in service, the H-O-A selector switch on that pump is set to "AUTO", and the pump level control transmitter is in service.
in
the
Sulfur
Condenser
is
B.
Confirm that the bypass acid gas flow ratio controller in the DCS is still in "manual" with its output set to 0%.
C.
Verify that the bypass acid gas control valve is fully closed.
D.
Verify that the acid gas control valve in the amine acid gas line to the Acid Gas Burner is fully open.
E.
Adjust the process air flow rate to 50% of scale on the local indicator using the air flow control (HIC) on the local SRU panel. Reduce the fuel gas flow rate to 50% of scale on the local indicator using the main fuel gas flow control (HIC) on the local panel.
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SULFUR BLOCK
WARNING
AS SOON AS THE TAILGAS VALVE IS OPENED IN THE NEXT STEP, OXYGEN-BEARING GASES WILL BEGIN FLOWING THROUGH THE CATALYST BEDS. IF THE CATALYST IS HOTTER THAN THE AUTO-IGNITION TEMPERATURE OF SULFUR ON CLAUS CATALYST (150°C), THE SULFUR CONTAINED IN THE CATALYST WILL BEGIN TO BURN. FOR THIS REASON, IT IS IMPORTANT THAT THE SWITCH FROM FIRING FUEL GAS TO FIRING ACID GAS BE MADE AS QUICKLY AS POSSIBLE. IF ANY DELAYS IN INTRODUCING ACID GAS ARE ENCOUNTERED, IMMEDIATELY SWITCH THE STARTUP/RUN SELECTOR SWITCH BACK TO "STARTUP" TO OPEN THE WARMUP BYPASS VALVES AND CLOSE THE TAILGAS VALVE SO THAT THE CATALYST BEDS DO NOT CONTINUE TO BURN. F.
Switch the Startup/Run selector switch on the local SRU control panel to "RUN" to route the combustion gases through the SRU. The PLC will open the Tailgas Valve to the Thermal Oxidizer then close the Warmup Bypass Valves. The "TTO OPEN" light will be illuminated, then the "WARMUP OPEN" light will be extinguished as the valves move to their new positions. NOTE:
If a valve status light continues to flash, it means that the limit switches on the associated valve(s) never confirmed that the valve(s) moved to the proper position. If this occurs, the startup sequence cannot proceed until the problem is corrected and the valve(s) move to the proper position. Should this occur, switch the Startup/Run selector switch back to "STARTUP" so that the catalyst beds do not continue to burn.
Issued 30 August 2011
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SULFUR BLOCK G.
Switch the Acid Gas Firing selector switch on the local SRU control panel to "ENABLED".
H.
Increase the output from the amine acid gas flow control (HIC) on the local SRU control panel to begin opening the amine acid gas inlet valve until the acid gas flow rate is approximately 10% on the local indicator.
I.
As soon as the acid gas flow rate reaches 10%, use the main fuel gas flow control (HIC) to reduce the fuel gas flow rate from 50% to 40% on the local indicator.
J.
Continue to add amine acid gas in 10% increments and reduce the fuel gas in 10% increments until the fuel gas control valve is completely closed.
K.
Press the “FUEL GAS OFF” push-button to "double block and bleed" the main fuel gas and the "PILOT OFF" push-button to "double block and bleed" the pilot fuel gas. Verify that the “fuel gas on” and the "PILOT ON" lights are both extinguished, and that the warmup burner and pilot burner are being purged with nitrogen.
L.
Continue to slowly increase the output from the amine acid gas flow control (HIC) to 100% so that the amine acid gas inlet valve is fully open.
M.
If the amine acid gas flow rate (in percent) displayed on the local control panel is significantly different from the air flow rate (in percent) displayed on the local control panel, use the air flow control (HIC) on the local SRU panel to adjust the air flow until the percentages are about the same.
N.
Close the following manual block valves:
O.
Issued 30 August 2011
(1)
The two manual block valve(s) in the main fuel gas line.
(2)
The manual block valve(s) in the fuel gas to the pilot.
(3)
The manual block valve(s) and manual block valve(s) in the instrument air to the pilot.
Loosen the packing gland on the pilot and retract or extract the pilot assembly:
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SULFUR BLOCK (1)
(2)
If the pilot is just to be retracted: (a)
Retract it until it reaches the limit of the retraction bar.
(b)
Tighten the packing gland on the pilot.
(c)
Verify that the pilot burner is still being purged with nitrogen.
If the pilot is to be completely extracted: (a)
Retract it until the retaining chain is taut.
(b)
Close the block valve to isolate the pilot from the furnace.
(c)
Close the block valve in the nitrogen purge to the pilot burner.
(d)
Disconnect the chain and remove the pilot assembly and store it in a safe place. CAUTION: THE PILOT ASSEMBLY WILL BE VERY HOT. HANDLE IT CAREFULLY TO AVOID BURNS AND TO AVOID DAMAGING IT.
(3) P.
Issued 30 August 2011
Verify that the pilot burner mounting nozzle is still being purged with nitrogen.
Place the air:acid gas ratio control loop in service as follows: (1)
Confirm that the air demand controller in the DCS is in "manual" and its output is set at 50%.
(2)
Confirm that the process air flow controller in the DCS is in "cascade", its output is tracking the output of the air flow control (HIC) on the local SRU control panel, and its setpoint is tracking its current reading.
(3)
Confirm that the "coarse" setting on the air:acid gas manual ratio set (HIC) is being back-calculated so that the remote setpoint it supplies to the air flow controller matches the current "local" setpoint on the controller.
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SULFUR BLOCK (4)
Q.
Switch the process air hand switch (HS) from "local" to "remote" to give the process air flow controller in the DCS control of the Process Air Blower, so that the process air flow rate will be ratio-controlled automatically. The output from the air:acid gas manual ratio set (HIC) will remain fixed at its last value.
Adjust the air:acid gas ratio as necessary with the air:acid gas manual ratio set (HIC) to bring the air demand displayed on the air demand controller "on-scale" (between -10.0% and +10.0%). If the air demand is high (0.0% to +10.0%), the air:acid gas ratio is too high (i.e., "excess air"). Reduce the setting on the air:acid gas manual ratio set (HIC) to lower the air:acid gas ratio and reduce the air demand. If the air demand is low (-10.0% to 0.0%), the air:acid gas ratio is too low (i.e., "air deficient"). Increase the setting on the air:acid gas manual ratio set (HIC) to raise the air:acid gas ratio and increase the air demand. Once the air demand is "on-scale", switch the air demand controller to "automatic" and adjust its setpoint to 0.0% air demand.
Issued 30 August 2011
R.
Observe the temperatures in the catalyst beds and in the Reactor outlet lines. These temperatures should begin to rise as the Claus reaction is initiated. Watch the steam pressures and water levels in the boilers to confirm that the control systems are functioning properly.
S.
After operating for a few hours on acid gas, the process temperatures can be lowered somewhat from the levels established during startup. (1)
Confirm that the Waste Heat Boiler steam pressure controller is set at 48.5 kg/cm2(g) and is controlling.
(2)
Confirm that the three temperature controllers for the Reactor feeds, are tracking their current readings then switch the controllers to "automatic". Slowly reduce the temperature setpoints to their normal values.
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SULFUR BLOCK (3)
T.
Issued 30 August 2011
Adjust the setpoint of the Sulfur Condenser steam pressure controller, the Sulfur Condenser steam pressure controller, to 1.75 kg/cm2(g).
The sulfur plant is now on-stream, firing on amine acid gas. Before bringing in SWS gas or directing your attention away from the SRU, be sure that: (1)
All controllers are functioning properly.
(2)
Sulfur is draining freely from each rundown line.
(3)
All steam heating systems are in service and the steam traps are functioning properly.
(4)
The Warmup Bypass Valves are fully closed.
(5)
The Thermal Oxidizer is functioning properly.
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SULFUR BLOCK 9.8.5.5
SWS Gas Flow Once the SRU is operating stably on amine acid gas, the SWS gas stream can be introduced into the SRU. Do not attempt to bring in the SWS gas if the SRU is not running smoothly on amine acid gas, as this will make it that much harder to stabilize the unit. Instead, focus your attention on stabilizing the operation of the SRU first (usually by correcting a problem in the upstream Amine Regeneration Units), and then use the procedure below to establish SWS gas flow into the SRU. A.
Check that all vent and drain valves on the SWS Gas Knock-Out Drum, its piping, and the SWS Gas Knock-Out Drum Pump are closed and plugged.
B.
Line up the block valves to place a SWS Gas Knock-Out Drum Pump in service, set the H-O-A selector switch on that pump to "AUTO", and verify that the pump level control transmitter is in service.
C.
Confirm that the SWS gas flow on/off switch in the DCS is set to "on".
D.
Confirm that the Reactor Furnace front zone temperature controller is in "automatic".
E.
Confirm that the setpoint of the bypass acid gas flow ratio controller is tracking the current reading (which should be zero), then switch it to "automatic".
F.
Slowly raise the ratio setpoint on the bypass acid gas flow ratio controller to begin opening the bypass acid gas control valve and bypassing some of the amine acid gas to the side injection ports on the furnace.
G.
Continue to raise the ratio setpoint on the bypass acid gas flow ratio controller until the front zone temperature indicated on the front zone temperature controller is approximately 1200°C. After the bypass acid gas flow ratio controller is controlling the bypass acid gas flow and the furnace temperature is up to about 1200°C, the furnace is ready to accept SWS gas.
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SULFUR BLOCK H.
Slowly increase the output from the SWS gas flow control (HIC) on the local SRU control panel to begin opening the SWS gas inlet valve.
I.
As SWS gas begins flowing to the Acid Gas Burner, the air:acid gas ratio control system will begin sending additional process air to the burner to combust the SWS gas. Increase the SWS gas flow slowly to allow time for the ratio control system to adjust to the increasing SWS gas flow.
J.
Continue to slowly increase the output from the SWS gas flow control (HIC) to 100% so that the SWS gas inlet valve is fully open.
K.
Monitor the bypass acid gas flow ratio controller to verify that it maintains control of the bypass acid gas flow and that the front zone temperature in the Reactor Furnace remains about 1200°C.
L.
Observe the air demand controller and adjust the air:acid gas ratio with the air:acid gas manual ratio set (HIC) if necessary to help keep the air demand "on-scale". If the air demand is high (0.0% to +10.0%), reduce the setting on the air:acid gas manual ratio set (HIC) to lower the ratio and reduce the air demand. If the air demand is low (-10.0% to 0.0%), increase the setting on the air:acid gas manual ratio set (HIC) to raise the ratio and increase the air demand.
M.
Issued 30 August 2011
If the optical pyrometeris giving reliable indication of the front zone temperature in the furnace, place the temperature cascade control in service as follows: (1)
Confirm that the remote ratio setpoint that the temperature controller is supplying to the bypass acid gas flow ratio controller matches the current setting on the ratio controller.
(2)
Confirm that the temperature controller is in "automatic" and its setpoint is tracking its current reading.
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SULFUR BLOCK
N.
9.8.5.6
(3)
Switch the bypass acid gas flow ratio controller to "cascade". If necessary, slowly adjust the setpoint of the temperature controller to its normal setpoint of 1200°C.
(4)
Verify that the controllers are adjusting the bypass gas flow rate as needed to control the desired temperature in the front zone of the Reactor Furnace.
The sulfur plant is now fully on-stream, firing on both amine acid gas and SWS gas. Before switching the SRU tailgas to the TGCU or directing your attention away from the SRU, be sure that: (1)
All controllers are functioning properly.
(2)
Sulfur is draining freely from each rundown line.
(3)
All steam heating systems are in service and functioning properly.
(4)
The Thermal Oxidizer is functioning properly.
Routing SRU Tailgas to the TGCU Before switching the SRU tailgas from the Thermal Oxidizer to the TGCU Tailgas Cleanup Unit, be sure all of the following conditions are true: (1)
The SRU is operating stably on amine acid gas, or on amine acid gas and SWS gas.
(2)
The air demand indicated on the air demand controller is +2.0% or lower.
(3)
The TGCU has been warmed up to operating temperature and is ready to accept SRU tailgas.
If any of these conditions are not true, do not attempt to bring SRU tailgas into the TGCU. In particular, do not attempt switching tailgas to the TGCU when the sulfur plant is upset. The result will be two upset units to deal with. Instead, focus your attention on stabilizing the operation of the SRU first (usually by correcting a problem in the upstream Amine Regeneration Unit and/or Sour Water Stripper Unit), and then use the operating procedures for the TGCU in the TGCU Section of these guidelines to switch the SRU tailgas from flowing to the Thermal Oxidizer to flowing into the TGCU.
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SULFUR BLOCK Once the sulfur plant tailgas is flowing to the TGCU, be sure of the following before directing your attention away from the SRU:
9.8.6
(1)
The Tailgas Valve to the Thermal Oxidizer and the TGCU Warmup/Bypass Valve are fully closed.
(2)
All controllers are functioning properly.
(3)
Sulfur is draining freely from each rundown line.
(4)
All steam heating systems are in service and the steam traps are functioning properly.
(5)
The TGCU and the Thermal Oxidizer are functioning properly.
Normal Startup - Hot System When an SRU shutdown occurs due to some minor malfunction which can be corrected quickly, it is desirable to restart the plant in a minimum amount of time. The following procedure should be followed to accomplish a rapid restart of the SRU when it is already hot (750°C or higher in the Reactor Furnace). Refer to the previous sections for the reasons and details pertaining to the different steps performed.
9.8.6.1
Initial Preparations A.
Issued 30 August 2011
Check that all SRU ESD devices have been satisfied, except for the following: (1)
Neither blower running.
(2)
Flame failure.
B.
Confirm that the amine acid gas flow on/off switch is set to "on".
C.
Select local manual control for the control valves on the Process Air Blower by switching the process air hand switch (HS) in the DCS to "local".
D.
Place the process air flow controller in "cascade".
E.
Place the air demand controller in "manual" and set its output to 50%.
F.
Confirm that the manual signal bias control for the blower to be used is set to 100%.
G.
Select local manual control for the fuel gas flow control valve by Sulfur Recovery
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SULFUR BLOCK switching the main fuel gas hand switch (HS) in the DCS to "local". H.
Place the fuel gas flow controller in "automatic".
I.
Confirm that the fuel gas flow on/off switch is set to "on".
J.
Place the Reactor Furnace front zone temperature controller in "automatic".
K.
Place the bypass acid gas flow controller in "manual" and set its output to 0%.
L.
Confirm that Acid Gas Firing switch on the local SRU control panel is set to "DISABLED".
M.
Confirm that Leak Test switch on the local SRU control panel is set to "NORMAL".
N.
Confirm that Reactor Cool-Down switch on the back of the local SRU control panel is set to "NORMAL".
O.
Set the amine acid gas flow control (HIC) and the SWS gas flow control (HIC) on the local SRU control panel to 0% output. Visually confirm that the amine acid gas inlet valve and the SWS gas inlet valve are closed.
P.
Set the manual fuel gas control on the local SRU control panel to 0% output. Visually confirm that the main fuel gas valve and the two shutdown valves are closed.
Issued 30 August 2011
Q.
Set the air flow control (HIC) on the local SRU panel to 0% output.
R.
Verify that the acid gas control valve in the amine acid gas line to the burner is fully open.
S.
Verify that the bypass acid gas control valve in the bypass acid gas line is fully closed.
T.
Loosen the packing gland on the pilot mounting nozzle. If the pilot was extracted previously, insert the pilot assembly, connect its retaining chain, and open the block valve. Slide the pilot all the way in then tighten the packing gland. Open the
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SULFUR BLOCK block valve in the purge nitrogen and confirm that the pilot burner and pilot mounting nozzle are both being purged with nitrogen. 9.8.6.2
Igniting the Pilot Burner A.
Switch the Startup/Run selector switch on the local SRU control panel to "STARTUP". The PLC will open the two Warmup Bypass Valves and close the Tailgas Valve to the TTO and the Tailgas Valve to the TGCU. Verify that the "WARMUP OPEN" light on the panel is now illuminated and the "TTO OPEN" and "TGCU OPEN" lights on the panel are extinguished. NOTE:
B.
Verify that the local start/stop controls for the Process Air Blowers have their selector switches turned to the "STOP" position.
C.
Verify that the suction, discharge, and blow-off valves on both blowers are all closed.
D.
Start a Process Air Blower:
E.
Issued 30 August 2011
If a status light continues to flash, it means that the limit switches on the associated valve(s) never confirmed that the valve(s) moved to the proper position. If this occurs, the startup sequence will not be allowed to proceed until the problem is corrected and the valve(s) move to the proper position.
(1)
Press the local push-button to give a “permit to start” for the desired blower.
(2)
Start the blower using the local start/stop control station for that blower.
Confirm that the air blower is running, then press the "ESD RESET" push-button on the local SRU control panel to reset the SRU ESD and extinguish the "RESET REQUIRED" light. This will illuminate the "PURGE REQUIRED" light.
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SULFUR BLOCK F.
Verify that the "LIMITS SATISFIED" light is glowing steadily (not flashing) on the local SRU control panel. NOTE:
If the "LIMITS SATISFIED" light is flashing, this means that either a limit switch or a pressure transmitter is not satisfied. The limit switches on the amine acid gas, SWS gas, and fuel gas valves must all indicate that their respective valves are closed, and the two pressure transmitters on the main fuel gas must be satisfied. For safety reasons, the BMS will not allow the light-off sequence to proceed until all these conditions are satisfied. Once the problem with the valves, their limit switches, or the pressure transmitters has been corrected, the "LIMITS SATISFIED" light will stop flashing and glow steadily, and the light-off sequence can proceed.
G.
Issued 30 August 2011
Open the following manual block valves: (1)
The manual block valve(s) in the main fuel gas supply line.
(2)
The manual block valve(s) in the fuel gas supply line to the burner.
(3)
The manual block valve(s) in the fuel gas supply to the pilot.
(4)
The manual block valve(s) in the instrument air supply to the pilot.
H.
Adjust the output of the air flow control (HIC) on the local SRU panel to open the blower control valves and allow a large air flow, 80% or more to purge the furnace for 30 seconds and extinguish the "PURGE REQUIRED" light. The "PURGE COMPLETE" light will then be illuminated.
I.
Adjust the output of the air flow control (HIC) on the local SRU panel to reduce the air flow to 10-20%, extinguishing the "PURGE COMPLETE" light and illuminating the "PERMIT TO IGNITE" light.
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SULFUR BLOCK NOTE:
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Remember that the ignition safety timer will shut down the SRU if an ignition attempt is not made within 5 minutes of receiving the "PERMIT TO IGNITE".
J.
Press the "IGNITION" push-button to initiate an ignition attempt.
K.
If neither flame scanner detects a flame after 15 seconds of sparking the ignitor, the ignition try is aborted, the SRU Burner Shutdown system is activated, and the PLC causes the sequence to return to Step H.
L.
When either flame scanner detects a flame from the pilot burner, the pilot air and fuel gas valves remain open, the "PILOT ON" light remains illuminated, and the PLC enables the "MAIN FUEL START" push-button and the "RUN" position on the Startup/Run selector switch.
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SULFUR BLOCK 9.8.6.3
Amine Acid Gas Flow Since the SRU is already hot, there is no need to place the main fuel gas and the warmup burner ring in service. The acid gas can be ignited with the pilot burner flame. All that is required is to route the combustion products through the SRU, then bring in the acid gas and shut off the pilot.
WARNING
AS SOON AS THE TAILGAS VALVE IS OPENED IN THE NEXT STEP, OXYGEN-BEARING GASES WILL BEGIN FLOWING THROUGH THE CATALYST BEDS. IF THE CATALYST IS HOTTER THAN THE AUTO-IGNITION TEMPERATURE OF SULFUR ON CLAUS CATALYST (150°C), THE SULFUR CONTAINED IN THE CATALYST WILL BEGIN TO BURN. FOR THIS REASON, IT IS IMPORTANT THAT ACID GAS FIRING COMMENCE AS QUICKLY AS POSSIBLE. IF ANY DELAYS IN INTRODUCING ACID GAS ARE ENCOUNTERED, IMMEDIATELY SWITCH THE STARTUP/RUN SELECTOR SWITCH BACK TO "STARTUP" TO OPEN THE WARMUP BYPASS VALVES AND CLOSE THE TAILGAS VALVE SO THAT THE CATALYST BEDS DO NOT CONTINUE TO BURN. A.
Switch the Startup/Run selector switch on the local SRU control panel to "RUN" to route the combustion gases through the SRU. The PLC will open the Tailgas Valve to the Thermal Oxidizer then close the Warmup Bypass Valves. The "TTO OPEN" light will be illuminated, then the "WARMUP OPEN" light will be extinguished as the valves move to their new positions. NOTE:
Issued 30 August 2011
If a valve status light continues to flash, it means that the limit switches on the associated valve(s) never confirmed that the valve(s) moved to the proper position. If this occurs, the startup sequence cannot
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SULFUR BLOCK proceed until the problem is corrected and the valve(s) move to the proper position. Should this occur, switch the Startup/Run selector switch back to "STARTUP" so that the catalyst beds do not continue to burn. B.
As soon as the "WARMUP OPEN" light is extinguished, switch the Acid Gas Firing selector switch on the local SRU control panel to "ENABLED".
C.
Immediately increase the output from the amine acid gas flow control (HIC) on the local SRU control panel to begin opening the amine acid gas inlet valve. Establish an amine acid gas flow rate of approximately 10% and observe if ignition of the acid gas is accomplished. If not, reduce the amine acid gas flow control (HIC) to 0% output to shut off the amine acid gas, open the manual block valve(s) in the main fuel gas supply to the burner, press the "FUEL GAS ON" push-button to open the main fuel gas valves, and use the main fuel gas flow control (HIC) to ignite the fuel gas warmup ring just long enough to ignite the acid gas burner. After establishing an acid gas flame, shut off the main fuel gas by pressing the “FUEL GAS OFF” push-button.
Issued 30 August 2011
D.
Increase the air flow on by 10% using the air flow control (HIC) on the local SRU panel, then increase the amine acid gas flow by 10%. Continue to make incremental increases in air and amine acid gas flow, keeping about a 1:1 ratio of air to amine acid gas (as measured by the percentages displayed on the local indicators), until the amine acid gas inlet valve is fully open.
E.
Press the "PILOT STOP" push-button to "double block and bleed" the pilot fuel gas. Verify that the “FUEL GAS ON” and the "PILOT ON" lights are both extinguished, and that the warmup burner and pilot burner are being purged with nitrogen.
F.
Close the following manual block valves: (1)
The two manual block valve(s) in the main fuel gas line.
(2)
The manual block valve(s) in the fuel gas to the pilot.
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SULFUR BLOCK (3) G.
The manual block valve(s) and manual block valve(s) in the instrument air to the pilot.
Loosen the packing gland on the pilot and retract or extract the pilot assembly: (1)
(2)
If the pilot is just to be retracted: (a)
Retract it until it reaches the limit of the retraction bar.
(b)
Tighten the packing gland on the pilot.
(c)
Verify that the pilot burner is still being purged with nitrogen.
If the pilot is to be completely extracted: (a)
Retract it until the retaining chain is taut.
(b)
Close the block valve to isolate the pilot from the furnace.
(c)
Close the block valve in the nitrogen purge to the pilot burner.
(d)
Disconnect the chain and remove the pilot assembly and store it in a safe place. CAUTION: THE PILOT ASSEMBLY WILL BE VERY HOT. HANDLE IT CAREFULLY TO AVOID BURNS AND TO AVOID DAMAGING IT.
(3) H.
Issued 30 August 2011
Verify that the pilot burner mounting nozzle is still being purged with nitrogen.
Place the air:acid gas ratio control loop in service as follows: (1)
Confirm that the air demand controller in the DCS is in "manual" and its output is set at 50%.
(2)
Confirm that the process air flow controller in the DCS is in "cascade", its output is tracking the output of the air flow control (HIC) on the local SRU panel and its setpoint is tracking its current reading.
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SULFUR BLOCK
I.
(3)
Confirm that the "coarse" setting on the air:acid gas manual ratio set (HIC) is being back-calculated so that the remote setpoint it supplies to the air flow controller matches the current "local" setpoint on the controller.
(4)
Switch the process air hand switch (HS) from "local" to "remote" to give the process air flow controller in the DCS control of the Process Air Blower, so that the process air flow rate will be ratio-controlled automatically. The output from the air:acid gas manual ratio set (HIC) will remain fixed at its last value.
Adjust the air:acid gas ratio as necessary with the air:acid gas manual ratio set (HIC) to bring the air demand displayed on the air demand controller "on-scale" (between -10.0% and +10.0%). If the air demand is high (0.0% to +10.0%), the air:acid gas ratio is too high (i.e., "excess air"). Reduce the setting on the air:acid gas manual ratio set (HIC) to lower the air:acid gas ratio and reduce the air demand. If the air demand is low (-10.0% to 0.0%), the air:acid gas ratio is too low (i.e., "air deficient"). Increase the setting on the air:acid gas manual ratio set (HIC) to raise the air:acid gas ratio and increase the air demand. Once the air demand is "on-scale", switch the air demand controller to "automatic" and adjust its setpoint to 0.0% air demand.
Issued 30 August 2011
J.
Observe the temperatures in the catalyst beds. The first bed may show a temporary increase in temperature due to the oxygen that was flowing through the bed, but its temperatures should quickly return to normal now that acid gas flow has been established.
K.
The sulfur plant is now on-stream, firing on amine acid gas. Before bringing in SWS gas or directing your attention away from the SRU, be sure that: (1)
All controllers are functioning properly.
(2)
Sulfur is draining freely from each rundown line.
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SULFUR BLOCK
9.8.6.4
(3)
All steam heating systems are in service and the steam traps are functioning properly.
(4)
The Warmup Bypass Valves are fully closed.
(5)
The Thermal Oxidizer is functioning properly.
SWS Gas Flow Once the SRU is operating stably on amine acid gas, the SWS gas stream can be introduced into the SRU. Do not attempt to bring in the SWS gas if the SRU is not running smoothly on amine acid gas, as this will make it that much harder to stabilize the unit. Instead, focus your attention on stabilizing the operation of the SRU first (usually by correcting a problem in the upstream Amine Regeneration Units), and then use the procedure below to establish SWS gas flow into the SRU. A.
Confirm that the SWS gas flow on/off switch in the DCS is set to "on".
B.
Confirm that the bypass acid gas flow ratio controller is in "manual" and that the front zone temperature controller is in "automatic".
C.
Confirm that the setpoint of the bypass acid gas flow ratio controller is tracking its current reading (which should be zero), then switch it to "automatic".
D.
Slowly raise the ratio setpoint on the bypass acid gas flow ratio controller to begin opening the bypass acid gas control valve and bypassing some of the amine acid gas to the side injection ports on the furnace.
E.
Continue to raise the ratio setpoint on the bypass acid gas flow ratio controller until the front zone temperature indicated on the front zone temperature controller is approximately 1200°C. After the bypass acid gas flow ratio controller is controlling the bypass acid gas flow and the furnace temperature is up to about 1200°C, the furnace is ready to accept SWS gas.
F.
Issued 30 August 2011
Slowly increase the output from the SWS gas flow control (HIC) on the local SRU control panel to begin opening the SWS gas inlet valve.
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SULFUR BLOCK G.
As SWS gas begins flowing to the Acid Gas Burner, the air:acid gas ratio control system will begin sending additional process air to the burner to combust the SWS gas. Increase the SWS gas flow slowly to allow time for the air flow control system to adjust to the increasing SWS gas flow.
H.
Continue to slowly increase the output from the SWS gas flow control (HIC) to 100% so that the SWS gas inlet valve is fully open.
I.
Monitor the bypass acid gas flow ratio controller to verify that it maintains control of the bypass acid gas flow and that the front zone temperature in the Reactor Furnace remains about 1200°C.
J.
Observe the air demand controller and adjust the air:acid gas ratio with the air:acid gas manual ratio set (HIC) if necessary to help keep the air demand "on-scale". If the air demand is high (0.0% to +10.0%), reduce the setting on the air:acid gas manual ratio set (HIC) to lower the ratio and reduce the air demand. If the air demand is low (-10.0% to 0.0%), increase the setting on the air:acid gas manual ratio set (HIC) to raise the ratio and increase the air demand.
K.
Issued 30 August 2011
If the optical pyrometer is giving reliable indication of the front zone temperature in the furnace, place the temperature cascade control in service as follows: (1)
Confirm that the remote ratio setpoint that the front zone temperature controller is supplying to the bypass acid gas flow ratio controller matches the current setting on the ratio controller.
(2)
Confirm that the front zone temperature controller is in "automatic" and its setpoint is tracking its current reading.
(3)
Switch the bypass acid gas flow ratio controller to "cascade". If necessary, slowly adjust the setpoint of the front zone temperature controller to its normal setpoint of 1200°C.
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SULFUR BLOCK (4)
L.
9.8.6.5
Verify that the controllers are adjusting the bypass gas flow rate as needed to control the desired temperature in the front zone of the Reactor Furnace.
The sulfur plant is now fully on-stream, firing on both amine acid gas and SWS gas. Before switching the SRU tailgas to the TGCU or directing your attention away from the SRU, be sure that: (1)
All controllers are functioning properly.
(2)
Sulfur is draining freely from each rundown line.
(3)
All steam heating systems are in service and the steam traps are functioning properly.
(4)
The Thermal Oxidizer is functioning properly.
Routing SRU Tailgas to the TGCU Before switching the SRU tailgas from the Thermal Oxidizer to the TGCU Tailgas Cleanup Unit, be sure all of the following conditions are true: (1)
The SRU is operating stably on amine acid gas, or on amine acid gas and SWS gas.
(2)
The air demand indicated on the air demand controller is +2.0% or lower.
(3)
The TGCU has been warmed up to operating temperature and is ready to accept SRU tailgas.
If any of these conditions are not true, do not attempt to bring SRU tailgas into the TGCU. In particular, do not attempt switching tailgas to the TGCU when the sulfur plant is upset. The result will be two upset units to deal with. Instead, focus your attention on stabilizing the operation of the SRU first (usually by correcting a problem in the upstream Amine Regeneration Unit and/or Sour Water Stripper Unit), and then use the operating procedures for the TGCU in the TGCU section of these guidelines to switch the SRU tailgas from flowing to the Thermal Oxidizer to flowing into the TGCU. Once the sulfur plant tailgas is flowing to the TGCU, be sure of the following before directing your attention away from the SRU:
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SULFUR BLOCK
9.8.7
(1)
The Tailgas Valve to the Thermal Oxidizer and the TGCU Warmup/Bypass Valve are fully closed.
(2)
All controllers are functioning properly.
(3)
Sulfur is draining freely from each rundown line.
(4)
All steam heating systems are in service and the steam traps are functioning properly.
(5)
The TGCU and the Thermal Oxidizer are functioning properly.
Firing Supplemental Fuel Gas As discussed in Section 9.6.11 of these guidelines, when a sulfur condenser is operated at lower and lower rates, it reaches a point where the bulk gas cooling rate caused by radiation and conduction heat transfer exceeds the dewpoint reduction rate caused by sulfur condensation on the tube walls. Instead of condensing along the walls of the tubes, sulfur begins to condense into tiny droplets out in the gas. Due to the low flow rates, there is not enough turbulence in the gas to make the droplets coalesce along the tube walls. The droplets come out of the tubes as a "fog" that cannot be removed in the downstream separator section, and are carried over into the reactor feed heaters Another one of the symptoms of low flow operating problems is a loss in temperature rise across the catalyst beds in the Reactor. This observation is not always an accurate indication that problems are occurring, however, because the process temperatures are influenced by other operating conditions, such as poor ratio control in the SRU as an example. Instead, it is simpler to use the process air flow rate to the SRU as the main process parameter to monitor. It turns out that the process air flow rate to the SRU is actually a very good indicator of the mass flow rate through the SRU, because the process air flow rate is a function of the amount of combustible compounds in the incoming feed streams. As a result, regardless of whether or not supplemental fuel gas is being fired in the SRU, the mass flow rate through the plant is about the same per unit of air flow. So, if action is taken to keep the process air flow rate high, sulfur "fog" formation should not be a problem. The action to take if the air flow drops below this point is to begin firing supplemental fuel gas. Since burning fuel gas in the Acid Gas Burner will require more process air to combust the fuel gas, the fuel
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SULFUR BLOCK gas flow rate can be adjusted to maintain a minimum process air flow (determined from experience). As discussed in previous sections, the air:acid gas ratio control system in the SRU is designed to automatically add the proper amount of air when burning supplemental fuel gas, so initiating supplemental firing is as simple as opening the control valve in the main fuel gas line to send fuel gas to the Acid Gas Burner. It is important, however, to increase or decrease the fuel gas flow rate slowly so that the control system has time to respond. The required fuel gas flow rate can be estimated from operating experience. Once the fuel gas flow has been set using the flow control in the DCS, observe the process air flow rate on the process air flow controller in the DCS and adjust the fuel gas flow rate as needed to keep the process air flow rate at the minimum flow rate. If the process air flow is too low, raise the setpoint on the fuel gas flow controller to increase the firing rate, which will increase the process air flow rate. If the process air flow rate is higher than the minimum, reduce the setpoint on the fuel gas flow controller to reduce the firing rate and reduce the process air flow. While firing supplemental fuel gas, observe the Reactor Furnace temperature closely on the temperature controllers in the DCS. As the supplemental firing rate is increased, the furnace temperature will begin to rise and the ratio setting on the bypass acid gas ratio controller may have to be adjusted. (If the temperature control cascade for the front zone temperature is in service, the front zone temperature controller should adjust the ratio setting automatically.) Do not allow the furnace temperature to exceed 1,500°C, however, as operation at temperatures above this may cause the refractory lining to fail. Do not increase the firing rate even if it means the process air flow drops below the minimum flow rate. The unit will just have to suffer the low-flow operating problems if the feed rate drops to this point, in order to avoid damaging the Reactor Furnace. The bypass acid gas flow ratio controller, will initially be able to maintain the desired furnace temperature by reducing the bypass gas flow rate to send more of the amine acid gas to the burner, which will lower the temperature in the front zone of the Reactor Furnace. In fact, if enough supplemental fuel gas is fired at the burner, all of the amine acid gas can be routed to the burner due to the increase in furnace temperature caused by the heat release from the fuel gas combustion. However, once the Issued 30 August 2011
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SULFUR BLOCK bypass acid gas flow ratio controller has routed all of the amine gas to the burner, it will no longer be able to control the front zone temperature, and this temperature may begin to rise. If so, reduce the supplemental fuel gas flow rate as needed to keep the furnace temperature below 1,500°C (preferably, below 1370°C). 9.8.7.1
Initiating Supplemental Firing Supplemental fuel gas firing is accomplished by relighting the warmup burner in the Acid Gas Burner. The procedure below assumes that the SRU is on-line and processing acid gas.
Issued 30 August 2011
A.
Select local manual control for the fuel gas flow control valve by switching the main fuel gas hand switch (HS) in the DCS to "local".
B.
Place the fuel gas flow controller in "automatic".
C.
If necessary, "toggle" the fuel gas flow on/off switch in the DCS to "ON" so that the fuel gas flow will be included in the air:acid gas ratio control system.
D.
Set the manual fuel gas control on the local SRU control panel to 0% output and visually confirm that the main fuel gas valve and the two shutdown valves are closed.
E.
Open the following manual block valves: (1)
The upstream manual block valve(s) in the main fuel gas supply line.
(2)
The downstream manual block valve(s) in the main fuel gas line to the burner.
F.
Press the "FUEL GAS ON" push-button on the local SRU control panel to open the main fuel gas block valves and illuminate the “FUEL GAS ON” light.
G.
Adjust the output of the main fuel gas flow control (HIC) on the local SRU control panel to slowly open the control valve and commence fuel gas flow to the warmup burner ring. Look through the viewports on the Acid Gas Burner and adjust the fuel gas flow rate until a stable flame can be maintained on the burner tips.
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SULFUR BLOCK H.
Observe the air flow on the process air flow controller and confirm that the air:acid gas ratio control system has added the air needed to combust the fuel gas.
I.
Switch the fuel gas flow rate to automatic control as follows:
J.
(1)
Confirm that the fuel gas flow controller in the DCS is in "automatic", its output is tracking the output of the main fuel gas flow control (HIC) on the local SRU control as indicated in the DCS, and its setpoint is tracking its current reading.
(2)
Switch the main fuel gas hand switch (HS) from "local" to "remote". The DCS controller now has control of the fuel gas control valve and will be controlling a fixed fuel gas flow rate, with its setpoint equal to the last reading
If the process air flow indicated on the process air flow controller is already at the minimum flow rate or higher, do not lower the fuel gas flow. Leave the fuel gas flow controller setpoint where it is, as this is the minimum fuel gas flow for a stable flame on the warmup burner ring at the current operating conditions. Lowering the fuel gas flow could create an unstable fuel gas flame and lead to operating problems. There is no harm in firing more supplemental fuel gas than is necessary as long as the furnace temperature does not exceed the maximum operating temperature of the refractory, 1,500°C. The only disadvantages are the higher fuel gas cost and a slight reduction in the sulfur recovery. (Since water is a product of the Claus reaction, the water vapor in the fuel gas combustion products tends to inhibit the Claus reaction to a degree.)
K.
Issued 30 August 2011
If the process air flow indicated on the process air flow controller is less than the minimum flow rate, slowly raise the setpoint on the fuel gas flow controller to increase the supplemental fuel gas firing rate. The air:acid gas ratio control system will in turn raise the setpoint of the process air flow controller and increase the air flow rate. Adjust the fuel gas flow rate as needed to maintain the air flow at the minimum flow rate or above on the process air flow controller.
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SULFUR BLOCK L.
Monitor the furnace temperature closely and make appropriate adjustments to the ratio setting on the bypass acid gas ratio controller. If the temperature control cascade for the front zone temperature is in service, the front zone temperature controller should adjust the ratio setting automatically. If necessary, lower the fuel gas flow rate to keep the furnace temperature at 1,500°C or below. Once the output from the bypass acid gas flow ratio controller reaches 0% and the bypass acid gas control valve is fully closed, the bypass gas ratio controller will no longer be able to control the furnace temperature.
M.
Monitor the air demand on the air demand controller closely and be prepared to adjust the air:acid gas ratio as necessary with the air:acid gas manual ratio set (HIC) to help the air demand controller keep the plant "on-ratio".
N.
If the warmup burner does not light or will not maintain a stable flame: (1)
Press the “FUEL GAS OFF” push button to block-in the main fuel gas.
(2)
Verify that the main fuel gas automated block valves have closed, the main fuel gas automated vent valve has opened, and the “FUEL GAS ON” light has been extinguished.
(3)
Close the manual block valve(s) in the main fuel gas supply line.
(4)
Close the downstream manual block valve(s) in the main fuel gas line to the burner.
The most likely reason for failure of the burner to light is physical damage to the burner (plugging of the tips with scale, carbon, sulfur, or corrosion products, melting of the tips, etc.). In such cases, the nitrogen purge flow to the warmup burner will usually be low or nonexistent. Supplemental fuel gas firing (as well as warmup of the SRU during a "cold" startup) will not be possible until the SRU is shut down so that the burner can be repaired.
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SULFUR BLOCK 9.8.7.2
Discontinuing Supplemental Firing When the acid gas feed rate increases again and supplemental fuel gas firing is no longer needed to keep the process air flow above the minimum rate, the supplemental firing can be discontinued as described below.
Issued 30 August 2011
A.
Place the fuel gas flow controller in "manual".
B.
Slowly reduce the output from the fuel gas flow controller to 0% to close the control valve in the main fuel gas line and reduce the fuel gas flow to zero. Lower the fuel gas flow rate slowly to allow the air:acid gas ratio control system to adjust the air flow properly.
C.
Press the “FUEL GAS OFF” push-button on the local SRU control panel to "double block and bleed" the main fuel gas.
D.
Verify that the main fuel gas block valves have closed, the “FUEL GAS ON” light has been extinguished, and the warmup burner is being purged with nitrogen.
E.
Close the two manual block valve(s) in the main fuel gas line.
F.
"Toggle" the fuel gas flow on/off switch in the DCS to "OFF" so that the fuel gas flow rate will no longer be included in the air:acid gas ratio control system (in case the meter does not read exactly zero when there is no flow).
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SULFUR BLOCK
9.9
Shutdown Procedures The procedures to be used in performing a planned shutdown of a sulfur plant will vary depending on the extent and type of work to be performed in and around that SRU during the downtime period. If there are no plans for opening the SRU such that air would be allowed entry to the catalyst beds in the Reactor, few special procedures are required in performing the shutdown. In general, unless there is a suspected problem in the Reactor or the catalyst is to be replaced, there is no benefit to be gained from opening up the Reactor vessel. If the Reactor vessel does not need to be opened (or exposed to significant air entry during some other maintenance procedure), there is no need to cool the catalyst beds. This greatly simplifies and shortens the shutdown procedure. Section 9.9.1 that follows is an example of such a procedure. Also, Section 9.9.1.K (1) briefly addresses keeping a sulfur plant on hot stand-by to minimize corrosion due to water condensation in the boiler and exchanger tubes. Since each SRU has a warmup bypass line to the Thermal Oxidizer, they can be kept on hot stand-by indefinitely by firing on fuel gas and venting the combustion products to the Thermal Oxidizer. This allows maintaining the furnace refractory and heat exchanger surfaces at their normal operating temperatures, ready to accept acid gas, without exposing the catalyst beds to overheating, carbon deposition, or sulfation damage. (Refer to the description of cold catalyst bed startup in these guidelines.) If the catalyst is to be replaced, if the Reactor must be entered, or if maintenance on some other portion of the plant will allow a significant amount of air to enter the Reactor vessel, then more extensive and lengthy procedures must be followed to accomplish a satisfactory shutdown and minimize the time required for performance of the desired maintenance work. Section 9.9.2 that follows is an example of a procedure for this circumstance. One special circumstance that may exist during a shutdown is to have tube leaks in either the Waste Heat Boiler or the Sulfur Condenser. This special case is discussed in Section 9.9.3. Section 9.9.4 is a discussion of emergency shutdown situations. A guide to troubleshooting the causes of unplanned shutdowns is presented to assist in quickly identifying and correcting the problem so the SRU(s) can be put back on-line in a minimum amount of time.
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SULFUR BLOCK Each SRU is affected directly and indirectly by shutdowns and outages that occur in other systems. The more important aspects of the effects these other systems can have on the SRUs are discussed in Section 9.9.5. Typical shutdown procedures are outlined and discussed in the sections that follow for the more common cases. Your existing company procedures and common sense operational judgment should be used to modify these procedures as needed to serve the purpose of any given planned shutdown situation.
9.9.1
Planned Shutdown - No Reactor Entry When there are no plans to open up the Reactor, there is no need to cool the catalyst beds during the shutdown procedure. Even when entry to other parts of an SRU is planned, this can normally be accomplished without exposing the catalyst beds to significant amounts of air by using slip-blinds to isolate the Reactor prior to purging, etc. Under these circumstances, the shutdown procedure given in this section may be used as a guide. All of the equipment and process piping in each SRU is designed to be free-draining so that there should be very little accumulation of liquid sulfur within the unit during normal operation. For this reason, there is usually no need to perform a "sulfur strip" when shutting down an SRU, as there is generally very little residual sulfur contained in the catalyst beds and separation chambers when the sulfur plant is shut down. Experience has shown that plugging of the piping or equipment with solid sulfur during the subsequent restart is normally not a problem. If, however, there is reason to believe that there has been significant accumulation of sulfur within the unit, the "sulfur strip" procedure described in Section 9.9.2 can be performed at the conclusion of this procedure. It is generally preferable to shut down the SRU in a controlled fashion to minimize the impact on the other process units. If time does not allow performing a controlled shutdown, however, the unit can be shut down by simply activating the SRU ESD system (using either the local push-button or the DCS "toggle" switch). This will automatically block the feeds into the SRU (amine acid gas, SWS gas, fuel gas, and combustion air). To shut the SRU down in a controlled fashion, follow the procedure below. A.
Issued 30 August 2011
If both SRUs are to be shut-down, the Tailgas Cleanup Unit should be shut down first using one of the procedures in these guidelines.
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SULFUR BLOCK However if one SRU remains on-line, the TGCU can remain online as well. B.
Discontinue SWS gas flow to the SRU by slowly reducing the output from the manual control hand controller on the local SRU control panel to begin closing the SWS gas shutdown valve. Allow time for the air flow controller to reduce the air flow to the SRU accordingly.
C.
Continue to reduce the output from the manual controller to 0% until the SWS gas inlet valve is completely closed. The pressure control system(s) on the Sour Water Stripper(s) should begin to divert the SWS gas flow to the flare as the feed rate to the SRU is reduced.
D.
Begin to "back out" the amine acid gas flow to the SRU by slowly reducing the output from the manual control hand controller on the local SRU control panel to begin closing the amine acid gas shutdown valve. Allow time for the air flow controller to reduce the air flow to the SRU accordingly.
E.
Observe the amine acid gas flow rate the flow indicator on the local SRU control panel and continue reducing the output on the manual controller until the flow rate drops to 20-30%. The pressure control system on the stripper in the ARU should begin to divert the amine acid gas flow to the flare as the feed rate to the SRU is reduced.
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F.
Once the amine acid gas flow rate is down to 20-30%, the SRU can be shut down with minimal impact on the other process units. The simplest way to do so is to activate the SRU ESD system, using either the push-button in the DCS or the push-button on the local SRU control panel.
G.
Visually confirm that: (1)
The amine acid gas shutdown valve is closed.
(2)
The SWS gas shutdown valve is closed.
(3)
The fuel gas to the Acid Gas Burner is blocked-in and bled.
(4)
The Process air Blower is shut down and the suction, blow-off, and discharge valves are closed.
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SULFUR BLOCK (5) H.
All steam heating services are still functioning and the steam traps are operating properly.
If the TGCU was shut down in Step A, the Tailgas Valve to the TTO should have been opened and the Tailgas Valve to the TGCU should have been closed automatically. Visually confirm the positions of these valves. If this is not the case, proceed as follows: (1)
Switch the Startup/Run selector switch on the local SRU control panel to "STARTUP". The PLC will open the two Warmup Bypass Valves and close the Tailgas Valve to the TGCU. Verify that the "WARMUP OPEN" light on the panel is now illuminated and the "TGCU OPEN" light is extinguished.
(2)
Switch the Startup/Run selector switch back to "RUN". The PLC will open the Tailgas Valve to the TTO, then close the Warmup Bypass Valves. Verify that the "TTO OPEN" light on the panel is illuminated, and that the "WARMUP OPEN" and "TGCU OPEN" lights are extinguished.
I.
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If the other SRU and the TGCU are to remain online, isolate the off-line SRU from the TGCU and the Thermal Oxidizer: (6)
Switch the Startup/Run selector switch on the local SRU control panel to "STARTUP".
(7)
The PLC will open the two Warmup Bypass Valves and close the Tailgas Valve to the TGCU or the Tailgas Valve to the TTO. Verify that the "WARMUP OPEN" light on the panel is now illuminated and the "TTO OPEN" and "TGCU OPEN" lights on the panel are extinguished.
(8)
Turn the Leak Test key switch on the local SRU control panel to "TEST".
(9)
The PLC will close the two Warmup Bypass Valves and start the nitrogen purge between the valves. Verify that the "WARMUP OPEN" light on the panel is now extinguished, and that nitrogen is flowing into the piping by observing the FI.
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SULFUR BLOCK (10) If desired, close the manual block valve in the SRU tailgas line. J.
All temperatures in the sulfur plant should be monitored to confirm that no air leaks into the system (due to "drafting" from the Thermal Oxidizer, for instance) and causes sulfur fires in the catalyst beds. If possible, establish a small flow of inert gas into the SRU inlet to purge the SRU to the Thermal Oxidizer using the nitrogen connection on the air line to the Acid Gas Burner.
WARNING
STEPS MUST BE TAKEN TO ENSURE THAT THE SRU IS NOT COMPLETELY BLOCKED-IN. FOR INSTANCE, IT IS POSSIBLE TO BLOCK-IN THE SRU BY CLOSING THE BLOCK VALVES IN THE WARMUP BYPASS LINE AND IN THE TAILGAS LINES TO THE THERMAL OXIDIZER AND THE TGCU. BEFORE DOING SO, ANOTHER OPENING FROM THE SRU TO THE ATMOSPHERE MUST BE CREATED SO THAT THE SRU CANNOT BE OVER-PRESSURED. K.
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If the SRU will be down for an extended period, special precautions should be taken to prevent the boiler and exchanger tubes from cooling to the point where water can condense inside them. Most of the corrosion that occurs in sulfur plants is due to the acidic water that can form if the plant is allowed to get cold. (1)
The Waste Heat Boiler, the reheat exchangers and the Sulfur Condenser can be kept hot by firing the warmup burner in the Acid Gas Burner with fuel gas, using the Warmup Bypass Valves to divert the combustion gases to the Thermal Oxidizer. Use the procedures in these guidelines to fire the SRU in hot standby mode on fuel gas.
(2)
If this is not possible, allow the two boilers to cool enough to Then reduce the steam pressure to about 1 kg/cm2(g). de-pressure the boilers and drain the water from them. Use a temporary "jumper" to supply LP steam to the Waste Heat
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SULFUR BLOCK Boiler, open the sulfur condenser pressure control valve to "back" LP steam into Sulfur Condenser, and drain the condensate from them occasionally. (Make sure the valves are open in the condensate outlet lines from the reactor feed heaters.) This will keep the tubes in the boilers and reheat exchangers safely above the water condensation temperature (100-110°C).
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SULFUR BLOCK 9.9.2
Planned Shutdown for Reactor Entry It is always best, but not absolutely necessary, to reduce the amount of residual sulfur contained in the catalyst beds and separation chambers to a minimum before opening the sulfur plant equipment for maintenance or catalyst change-out. This minimizes the purging and cleaning required prior to vessel entry. This "sulfur strip" can be accomplished most effectively by raising temperatures throughout the plant and routing inert gas through the plant. In this procedure, where complete cooling of the plant and air purging are required, the time-controlling step will be the period of time required to cool the catalyst beds below 150°C. Also, attention should be given to the cooling of the Reactor Furnace refractory; it should be limited to 100-150°C per hour. The catalyst beds must be cooled to 150°C or below before air flow can be established to purge the plant and cool it rapidly from that temperature. If the catalyst beds are not cooled to this level before beginning the air purge, sulfur fires can occur in the beds, the sulfur separators and mist eliminators, and the other parts of the plant where elemental sulfur is present.
9.9.2.1
Cooling Gas for the Catalyst Beds There will always be enough sulfur in a used catalyst bed to burn and generate sufficient heat to damage equipment if enough air is routed to the bed to supply the oxygen required for combustion. Therefore, gases which contain essentially no oxygen must be routed through the catalyst beds until the outlet temperature from each bed is below 150°C. Otherwise, the plant would have to be blocked-in for days to obtain the necessary ambient heat loss cooling of the catalyst beds. The following gases can be considered for catalyst bed cooling: A.
Inert gases such as nitrogen, carbon dioxide, or a mixture of nitrogen and carbon dioxide like that produced by a combustion-type inert gas generator. We recommend cooling the SRU with LP nitrogen from the from the hard-piped nitrogen connection on the Process Air line to the burner. However, if sufficient nitrogen is not available from the nitrogen header in the plant or some other source, inert combustion gases may be generated by firing the warmup fuel gas burner inside the Acid Gas Burner near stoichiometric
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SULFUR BLOCK air:gas ratio (little or no excess air), or slightly below stoichiometric. There are a few disadvantages with this technique:
B.
(1)
Careful control of the air:gas ratio is required to keep it near stoichiometric. Too much air will allow free oxygen to reach the catalyst beds, causing sulfur fires. Too little air can cause the warmup burner to produce soot. However, the only real damage the soot will cause is to settle out on the first catalyst bed. If the catalyst is being replaced, this will be of no consequence.
(2)
The flame temperature when burning fuel gas with stoichiometric air is generally in excess of 1600°C. Steam or nitrogen (or some other inert gas) will probably have to be added to the Reactor Furnace to keep the furnace temperature below 1500°C as measured on the pyrometers so that there is no damage to the refractory.
Steam is a good catalyst bed cooling gas. The only negative factor is that pure steam may damage the activity of some sulfur plant catalysts. If the catalyst is being replaced, then steam is a good choice. If the catalyst is not being replaced, the catalyst manufacturer should be contacted to determine the extent of damage, if any, that would result from cooling the catalyst with steam to the 150°C temperature level. It is likely that little catalyst damage will occur unless the temperature is allowed to fall below about 110°C where water could condense. If steam is to be used for cooling, it may be necessary to take steps to maintain at least 0.7 kg/cm2(g) steam pressure on the shell sides of the Waste Heat Boiler and the Sulfur Condenser in order to prevent water condensation in the plant. Temperatures should be monitored closely and steam pressures controlled if necessary. If these two boilers cool enough to reduce the steam pressure to about 1 kg/cm2(g), de-pressure the boilers and drain the water from them. Use a temporary "jumper" to supply LP steam to the Waste Heat Boiler , open the sulfur condenser pressure control valve to "back" LP steam into Sulfur Condenser, and drain the condensate from them occasionally. (Make sure the valves are open in the condensate outlet lines from the reactor feed
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SULFUR BLOCK heaters.) This will keep the tubes in the boilers and reheat exchangers safely above the water condensation temperature (100-110°C). 9.9.2.2
"Sulfur Strip" Procedure Using Inert Gas Before cooling down the catalyst beds, the amount of residual sulfur in the SRU should be reduced as much as possible by performing a "sulfur strip" on the plant. This can be accomplished by flowing hot inert gas through the catalyst beds to vaporize any residual sulfur, which is subsequently condensed and removed in the downstream passes of the Sulfur Condenser. The preferred source of inert gas is nitrogen from the plant header. If nitrogen (or some other type of inert gas from an external source) is available in sufficient quantity, follow the procedure given in this section to use nitrogen or inert gas as the stripping media. If nitrogen or inert gas is not available in sufficient quantity, follow the procedure given in this section using either steam or inert gas generated with the Acid Gas Burner as the stripping media.
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A.
Follow the procedure given in the preceding Section 9.9.1 to "back out" the SWS gas and amine acid gas feeds to the SRU and shut it down.
B.
Visually confirm that: (1)
The amine acid gas shutdown valve is closed.
(2)
The SWS gas shutdown valve is closed.
(3)
The fuel gas to the Acid Gas Burner is blocked-in and bled.
(4)
The Process air Blower is shut down and the suction, blow-off, and discharge valves are closed.
(5)
The Tailgas Valve to the TGCU is closed.
(6)
The Tailgas Valve to the TTO is open.
(7)
The manual block valve in the SRU tailgas line is open.
(8)
All steam heating services are still functioning and the steam traps are operating properly.
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SULFUR BLOCK C.
D.
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Begin the flow of inert gas through the plant. (1)
If using nitrogen from the plant header, the nitrogen can be introduced through the hard-piped connection on the process air line near the Acid Gas Burner.
(2)
If using inert gas from another source, it can be introduced through the bleed valve on the hard-piped LP nitrogen connection near the Acid Gas Burner.
(3)
If using the warmup burner in the Acid Gas Burner to generate inert gas, take care to keep the Reactor Furnace temperature below 1500°C on the pyrometers. Admit nitrogen or LP steam (using the hard-piped LP nitrogen connection on the process air line near the burner) to the furnace as necessary to moderate the furnace temperature. Use an oxygen analyzer to measure the oxygen content of the combustion gas flowing to the first catalyst bed in the Reactor, and adjust the air:gas ratio as necessary to keep the oxygen concentration between 0.5% and 2.0%. If steam is being used to moderate the furnace temperature, make sure that there is no liquid in the steam supply before introducing it into the furnace to avoid an explosion from water entering the hot furnace.
Adjust the temperatures throughout the plant by making changes as follows: (1)
Place the steam pressure controller on the Waste Heat Boiler in "manual" and adjust its output to 100% to fully open the steam valve. This will allow steam from the HP steam header to "back" into the boiler (if using nitrogen or inert gas).
(2)
Place the temperature controllers for the Reactor feeds in "manual" and set their outputs to 100% to fully open the valves in the condensate outlet lines from the exchangers and supply maximum heating to each catalyst bed.
(3)
Lower the steam pressure in the Sulfur Condenser if possible by adjusting the setpoint of the pressure controller to 1 kg/cm2(g). This will condense as much sulfur as possible as it is "stripped" from the three catalyst
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SULFUR BLOCK beds. (It should be noted that the back-pressure from the LP steam header will probably not allow operating the Sulfur Condenser any lower than about 3.5 kg/cm2(g).) The hot inert gas flowing through the Reactor should vaporize most of the residual sulfur contained in the catalyst beds so that it can be condensed and removed in the downstream condensing passes of the Sulfur Condenser. E.
Continue to purge the sulfur plant with this inert gas stream until sulfur is no longer running from any of the Sulfur Drain Seal Assemblies. Once sulfur stops running from all of the Sulfur Drain Seal Assemblies, cool-down of the catalyst beds can commence using the procedure given in Section 9.9.2.3 that follows.
9.9.2.3
Cool-down Procedure Once the "sulfur strip" procedure is complete, cool-down of the catalyst beds can begin. The cool-down gas will normally be the same inert gas that was used for the "sulfur strip" operation. However, if inert gas is being generated using the warmup burner in the Acid Gas Burner as described in Section 9.9.2.2, it may be desirable to switch to a once-through flow of inert gas (nitrogen, for example) instead to cool the catalyst beds. A.
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Begin reducing the steam pressures in the Waste Heat Boiler and the Sulfur Condenser to 0.7-1.0 kg/cm2(g) by placing their steam pressure controllers in "manual" and adjusting the outputs to 0% to close the valves, then venting the boiler shells to atmosphere. This steam pressure will keep the tubes in the boilers safely above the water condensation temperature (100-110°C). (1)
If dry inert gas (nitrogen) is being used for the cooling gas, the steam pressures in both boilers can be allowed to fall to 0 kg/cm2(g), since there is no risk of water condensation in the tubes.
(2)
If the warmup burner in the Acid Gas Burner is being used to generate the inert gas, it may not be possible to reduce the Waste Heat Boiler steam pressure to
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SULFUR BLOCK 0.7-1.0 kg/cm2(g), since the combustion products will provide considerable heat to the boiler. B.
Confirm that the temperature controllers for the Reactor feeds, are in "manual" and set their outputs to 0% to fully close the valves in the condensate outlet lines from the exchangers and supply minimum heating to the catalyst beds.
C.
Monitor the water levels in the Waste Heat Boiler and the Sulfur Condenser and confirm that the level controls continue to function properly to maintain normal levels in the boilers throughout the cool-down procedure.
D.
Continue to route inert gas through the catalyst beds, with maximum cooling in the Sulfur Condenser and minimum heating in the reheat exchangers, until the outlet temperatures from all catalyst beds are below 150°C. If using the warmup burner in the Acid Gas Burner to generate inert gas, it may not be possible to cool the first catalyst bed below 150°C. After extinguishing the burner, one of the following intermediate steps may be necessary to cool this catalyst bed below 150°C:
E.
(1)
Route nitrogen, steam, or some other inert gas through the reactor.
(2)
Allow the reactor to cool by ambient heat loss.
When all catalyst beds are below 150°C, stop the flow of cooling gas. Switch the Startup/Run selector switch on the local SRU control panel to "STARTUP". The PLC will open the two Warmup Bypass Valves and close the Tailgas Valve to the TTO Unit. Verify that the "WARMUP OPEN" light on the panel is now illuminated and the "TTO OPEN" light is extinguished.
F.
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Start a Process Air Blower: (1)
Switch blower hand swtich in the DCS to "local".
(2)
Set air blower flow controller (HIC) on the local SRU control panel to 0% output.
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SULFUR BLOCK (3)
Press the local push-button to give a "permit to start" for the desired blower.
(4)
Start the blower using the local start/stop control station for that blower.
The next step would normally be to press the "ESD RESET" push-button. Do not press it, however. G.
Turn the Reactor Cool-Down switch on the local SRU control panel to "COOL-DOWN".
H.
Switch the Startup/Run selector switch back to "RUN". The PLC will open the Tailgas Valve to the TTO, then close the Warmup Bypass Valves. Verify that the "TTO OPEN" light on the panel is illuminated, and that the "WARMUP OPEN" and "TGCU OPEN" lights are extinguished.
I.
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Increase the output from the local air flow controller (HIC) to begin a rapid air purge of the entire sulfur plant.
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SULFUR BLOCK
CAUTION WATCH THE TEMPERATURES IN EACH CATALYST BED AND OUTLET LINE VERY CLOSELY AFTER STARTING THE AIR PURGE, UNTIL ALL ARE WELL BELOW 120°C. SULFUR FIRES CAN IGNITE IN THE PLANT AFTER STARTING THE AIR PURGE EVEN THOUGH ALL THE TEMPERATURE INDICATORS REGISTERED 150°C OR LESS. IT IS POSSIBLE, FOR INSTANCE, TO HAVE LOCALIZED "HOT" SPOTS IN A CATALYST BED THAT CAN START A SULFUR FIRE. THE AIR PURGE SHOULD BE STOPPED IMMEDIATELY UPON OBSERVING A SIGNIFICANT TEMPERATURE RISE IN ANY TEMPERATURE INSIDE THE PLANT. THE INERT GAS FLOW SHOULD THEN BE RE-ESTABLISHED UNTIL ALL AREAS ARE COOLED BACK TO THE DESIRED 150°C LEVEL, BEFORE REATTEMPTING THE AIR PURGE. J.
Continue the rapid air purge of the entire sulfur plant until all temperatures are approximately equal to the discharge air temperature from the blower.
K.
Isolate the plant from all potential contaminating gases (acid gas, fuel gas, etc.), using slip-blinds or by disconnecting the piping, before stopping the air purge.
L.
Once the plant is isolated from the feed gases, discontinue the air purge by shutting down the Process Air Blower.
M.
Turn the Reactor Cool-Down switch on the local SRU control panel back to "NORMAL".
N.
Isolate the SRU from the TGCU and the Thermal Oxidizer: (1)
Switch the Startup/Run selector switch on the local SRU control panel to "STARTUP". The PLC will open the two Warmup Bypass Valves and close the Tailgas Valve to the TTO. Verify that the
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SULFUR BLOCK "WARMUP OPEN" light on the panel is now illuminated and the "TTO OPEN" and "TGCU OPEN" lights on the panel are extinguished. (2)
Turn the Leak Test key switch on the local SRU control panel to "TEST". The PLC will close the two Warmup Bypass Valves and start the nitrogen purge between the valves. Verify that the "WARMUP OPEN" light on the panel is now extinguished, and that nitrogen is flowing into the piping by observing the FI.
(3) O.
P.
If desired, close the manual block valve in the SRU tailgas line.
Visually confirm that: (1)
The SRU is isolated from the amine acid gas source, the SWS gas source, the fuel gas header, the instrument air header, the nitrogen header, the TGCU, and the Thermal Oxidizer.
(2)
The Process Air Blowers are shut down and their suction, blow-off, and discharge valves are closed.
(3)
All steam heating services are still functioning and the steam traps are operating properly. If possible, the LP steam and condensate system should remain in service, with selected branches taken out of service as required for maintenance.
The plant can now be opened for entry. Refer to the "General Safety" section of these procedures for important considerations when performing maintenance work on this plant.
WARNING
THE OVER-PRESSURE PROTECTION FOR THE SRU IS THE SULFUR DRAIN SEALS, A2-ME1530A-D(A2-ME1540A-D), WHICH WILL RELEASE THE GAS INSIDE THE SRU IF THE
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SULFUR BLOCK PRESSURE EVER EXCEEDS 0.88 KG/CM2(G). HOWEVER, IF THE BLOCK VALVES IN THE RUNDOWN LINES TO THE SULFUR DRAIN SEALS ARE CLOSED WHILE THE SRU IS SHUT DOWN, STEPS MUST BE TAKEN TO ENSURE THAT THE SRU IS NOT COMPLETELY BLOCKED-IN BY CREATING ANOTHER OPENING FROM THE SRU TO THE ATMOSPHERE SO THAT THE SRU CANNOT BE OVER-PRESSURED. Q.
If the SRU will be down for an extended period, special precautions should be taken to prevent the boiler and exchanger tubes from cooling to the point where water can condense inside them. Most of the corrosion that occurs in sulfur plants is due to the acidic water that can form if the plant is allowed to get cold. The Waste Heat Boiler, reheat exchangers and the Sulfur Condenser can be kept hot using LP steam. De-pressure the boilers and drain the water from them. Use a temporary "jumper" to supply LP steam to the Waste Heat Boiler, open the sulfur condenser pressure control valve to "back" LP steam into Sulfur Condenser, and drain the condensate from them occasionally. (Make sure the valves are open in the condensate outlet lines from the reactor feed heaters.) This will keep all the tubes safely above the water condensation temperature (100-110°C).
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SULFUR BLOCK 9.9.3
Shutting Down When Boiler Tubes Are Leaking One special circumstance that merits discussion is shutting down the SRU when there are tube leaks in the Waste Heat Boiler or Sulfur Condenser. While the plant is running, minor tube leaks usually cause little damage because the hot process gas vaporizes the boiler feed water before it has a chance to form acid and cause rapid corrosion. When the SRU is shut down, however, several problems can develop: 1.
Liquid water may accumulate in the equipment or piping and form a variety of acids (sulfurous, polythionic, etc.) that will rapidly corrode the steel.
2.
Liquid water may reach the refractory linings in the equipment and damage the linings.
3.
Water and/or steam may reach the catalyst in the Reactor and weaken or damage it.
4.
If there is a large tube leak in the Waste Heat Boiler, water may back-flow into the hot Reactor Furnace and rapidly vaporize, possibly violently enough to damage its refractory lining or create high pressure in the SRU.
If a boiler tube leak is suspected, a shutdown procedure similar to the following may be appropriate:
Issued 30 August 2011
A.
Shut down the SRU using the procedures given in Section 9.9.1.
B.
Commence a flow of nitrogen as soon as the Acid Gas Burner is shut down to purge any steam from tube leaks to the Thermal Oxidizer.
C.
De-pressure the boiler having the suspected tube leak, taking care to reduce the pressure slowly enough to avoid over-stressing the boiler.
D.
Maintain a visible water level in the boiler. Water must remain in the boiler until it is de-pressured to prevent overheating damage to the tubes.
E.
Once the boiler is fully de-pressured, drain the water from the boiler to prevent any further leakage into the process side of the equipment.
F.
The SRU is now ready to be isolated and made safe for entry.
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SULFUR BLOCK 9.9.4
Emergency Shutdown The SRU ESD system can be initiated by any of the actuating devices outlined in these guidelines, or by a power failure. The operator must determine and correct the condition causing the shutdown before the sulfur plant can be restarted. The problems outlined below should be investigated first by the operator in his troubleshooting procedure. If the malfunction causing the emergency shutdown can be determined and corrected in a short period of time, the SRU can be put back on-line using the rapid restart procedure outlined in these guidelines.
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S/D Actuation Device
Possible Causes
Acid Gas Knock-Out Drum High-High Level
1. Excessive liquids being received by the Knock-Out Drum. 2. Malfunction of level control system. 3. Level warning transmitters on the Knock-Out Drum are plugged or inoperable. 4. Knock-Out Drum Pump malfunction. 5. Pump suction or discharge line plugged, strainer plugged, or block valve closed. 6. Malfunction of the stripper reflux pumps in the upstream system.
Process Air Blower Not Running
1. Equipment damage has caused the blower to quit running. 2. A failure in the starter contacts is causing a false indication that the blower is not running.
Reactor Furnace High-High Pressure
1. Warmup bypass valve or tailgas block valve not open. 2. A sulfur condenser separator chamber is filled with molten sulfur due to plugging of a sulfur rundown line or a drain seal. 3. Steam pressure is too low in the Sulfur Condenser, causing tubes to be plugged with solid sulfur. 4. Soot or carbon buildup in a catalyst bed or a sulfur condenser mist eliminator is restricting flow. 5. Malfunction of the air pressure sensing system.
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SULFUR BLOCK
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S/D Actuation Device
Possible Causes
Acid Gas Burner Flame Failure
1. Failure of a component in the flame sensor circuit. 2. Condensation of sulfur or water vapor on the lens of the flame scanner. 3. Low acid gas (or fuel gas) flow. 4. Low process air flow due to: a. Malfunction of the blower suction valve or the flow control system. b. Blower discharge valve is not fully open. c. Blower blow-off valve is open excessively. d. Blower shutdown due to mechanical problems with the blower, the motor, or the switchgear. e. High pressure drop due to plugging or blockage downstream.
Waste Heat Boiler Low-Low Level
1. Loss of make-up water supply pressure. 2. Make-up water line plugged, or manual block valve closed or pinched. 3. Malfunction of the level control system. 4. Manual blowdown valve left open.
Reactor 1st Bed Outlet High-High Temperature
1. Malfunction of the air:acid gas ratio control system, allowing excess air to enter the system. 2. Malfunction of the control system has caused less than 1/3 of the acid gas to be routed to the burner, allowing free oxygen to reach the catalyst bed. 3. Low H2S concentration in the inlet acid gas is causing incomplete combustion in the Reactor Furnace, allowing free oxygen to reach the catalyst bed. 4. Damaged acid gas burner tip causing incomplete mixing and combustion of air and acid gas, allowing free oxygen to reach the catalyst bed. 5. Malfunction of the control system has caused a high reactor inlet temperature.
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SULFUR BLOCK
9.9.5
S/D Actuation Device
Possible Causes
Sulfur Condenser Low-Low Level
1. Loss of make-up water supply pressure. 2. Make-up water line plugged, or manual block valve closed or pinched. 3. Malfunction of the level control system. 4. Manual blowdown valve left open.
Neither Warmup Bypass Valve Closed Interlock
1. Neither warmup bypass valve is fully closed. 2. Malfunction of a limit switch is causing a false indication that a valve is not closed.
Effects of Shutdowns and Outages in Other Systems The Sulfur Recovery system is directly or indirectly affected by shutdowns and/or outages in five other systems in the plant. These effects are described below.
9.9.5.1
ATU / ARU Outages Acid gas flow from the ARU can be interrupted for a variety of reasons. For instance, the gas flow to the absorber in the ATU in the plant can be blocked manually or automatically, the solvent flow from the flash tank to the stripper can be interrupted, etc. When these events occur, the acid gas flow will not cease immediately due to the residence time in the solvent distribution piping, the flash tank, and the stripper. If processing in the affected ARU is restarted within the time frame of this system residence time, the amine acid gas flow to the SRU will probably dip, but should not stop completely. If the interruption in the ARU is long enough, though, the amine acid gas flow can fall far enough to cause the acid gas flame in the SRU to become unstable, at which point the SRU ESD system will be activated by "flame failure". If this happens, the SRU can be restarted on fuel gas and run in hot stand-by using the Warmup Bypass Valves, then brought back on-line once amine acid gas flow resumes. If the SRU is currently processing SWS gas, it is possible that the acid gas flame may remain stable enough for continued operation on just SWS gas. If the SRU is processing only SWS gas, note the cautions in these guidelines regarding this mode of operation.
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SULFUR BLOCK 9.9.5.2
Sour Water Stripper Outages SWS gas flow from the Sour Water Stripper can also be interrupted for a variety of reasons. However, since the loss of SWS gas flow to the SRU generally has minimal impact, outages in this system are usually of little consequence.
9.9.5.3
TGCU ESD System When the TGCU ESD system is activated, its warmup/bypass valve opens immediately to divert the tailgas from the upstream SRUs to the Thermal Oxidizer. At the same time, the PLC opens the Tailgas Valve to the TTO proves the valve open, then closes the Tailgas Valve to the TGCU. Once this switch is complete, the SRU tailgas stream is blocked off from the TGCU and flows directly to the Thermal Oxidizer. When the TGCU warmup/bypass valve first opens, the pressure drop through the TGCU will no longer be imposing back-pressure on the SRUs. Depending on the magnitude of this change in back-pressure (which is mainly determined by the unit throughput), there may be a temporary "bobble" in the feed and air flow rates to the SRUs. Although this will probably cause brief deviations from the proper air:acid gas ratio in the SRUs, the "bobble" should not be large enough to cause a "flame failure" shutdown in the SRU. If so, the SRU will remain on-line with its tailgas flowing to its Thermal Oxidizer, so that there is no need to restart the SRUs. Once the TGCU has been restarted, the SRU tailgas streams can be reintroduced into the TGCU to resume processing with as little interruption as possible.
9.9.5.4
Thermal Oxidizer ESD System A TTO ESD has no direct effect on the upstream SRUs, as the flow of SRU tailgas and/or TGCU effluent to the Thermal Oxidizer will not be interrupted. However, when the TTO ESD shuts down the Thermal Oxidizer Burner, the sulfur compounds in the Thermal Oxidizer feed gas will no longer be oxidized to sulfur dioxide. This means that hydrogen sulfide will be vented to the atmosphere from the top of its Thermal Oxidizer Vent Stack. Under normal circumstances, this is not a cause for concern because the TGCU is on-line processing the SRU tailgas. Since the H2S content of the
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SULFUR BLOCK TGCU effluent is low and the stack is tall, dangerous ground level concentrations of H2S should not develop. However, if the SRU is running directly to the TTO while operating off-ratio on the "air deficient" side (negative air demand), high concentrations of H2S could be vented from the stack when the TTO is shut down. For this reason, pay very close attention to the air demand controller and the air:acid gas ratio control system in the SRU when the TTO is off-line, and be prepared to shut down the SRU if it is not operating properly. In particular, note the warnings in the TTO Sections of these guidelines regarding high temperature in the Thermal Oxidizer if the SRU tailgas contains excessive amounts of H2S. Also, note that the operating permit for this plant may not allow venting un-incinerated gases for extended periods. Review the permit before operating in this mode for a lengthy period. If the H2S concentration in the TTO feed gas is high (above 3.0%), do not attempt to restart the Thermal Oxidizer. Instead, direct your attention to the amine or SWS unit(s) upstream of the SRUs that are probably causing the problem and bring the SRUs back on-ratio, so that the H2S concentration in the Thermal Oxidizer feed gas is reduced to an acceptable level and restart of the Thermal Oxidizer can proceed smoothly. Failure to correct the upstream problem(s) first will likely lead to the TTO shutting down again, requiring another restart of the TTO. If the H2S concentration is high enough, there is also a possibility of causing an explosion in the Thermal Oxidizer. 9.9.5.5
Steam System Outage There are two impacts on the SRU if the complex steam system is shut down. One of these will only create problems if the steam supply to the SRUs is unavailable for a long period of time. The heating steam for the sulfur vapor switching valves, the sulfur rundown lines, the Sulfur Surge Tanks and the Sulfur Storage Tank will be lost, leading to solid sulfur freezing in these locations. The more immediate impact on the SRU will be the loss of LP steam to the stripper reboiler in the upstream Amine Regeneration Unit if the steam outage lasts long enough. As the heat input to the reboiler
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SULFUR BLOCK declines, stripping of the acid gas from the solvent will decline and the amine acid gas flow rate to the SRU will gradually diminish. If the amine acid gas flow falls far enough to cause the acid gas flame to become unstable, the SRU ESD system will be activated by "flame failure" as described previously in the discussion about Amine Regeneration Unit outages.
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SULFUR BLOCK
9.10 Analytical Procedures This section contains analytical procedures for determining: 1.
The H2S concentration in the inlet amine acid gas using Tutweiler analysis (Sections 9.10.1, 9.10.2, 9.10.6, and 9.10.7).
2.
The H2S and SO2 concentrations in the SRU tailgas using Tutweiler analysis (Sections 9.10.1 and 9.10.3 through 9.10.7).
3.
The H2S and SO2 concentrations in the SRU tailgas using gas detector tubes (Section 9.10.8).
9.10.1
Procedure for Sampling and Titrating with a Tutweiler Apparatus The procedure given below is specifically written for a 100 ml Tutweiler apparatus, commonly used when analyzing streams with high H2S concentrations (amine acid gas, for instance). The same procedure can be used with the 500 ml Tutweiler apparatus, commonly used for analyzing dilute streams (SRU tailgas, for instance), by substituting a reference to the 500 ml apparatus for all the references to the 100 ml apparatus. With this in mind, the few differences in the procedure have been noted by enclosing specific directions for the 500 ml apparatus in parenthesis. 1.
Using a 100 ml (500 ml) Tutweiler apparatus, fill the 10 ml titrating burette on top of the Tutweiler apparatus with 0.1 N iodine solution to some level below 10 ml. Carefully read and record this reading.
2.
Fill a leveling bottle with fresh starch solution.
3.
Attach a short piece of rubber tubing to the process sample valve.
4.
Attach the leveling bottle filled with starch solution to the lower stopcock of the Tutweiler burette.
5.
Use the starch solution to purge the Tutweiler burette: Raise the leveling bottle, open the lower stopcock, open the upper stopcock to the inlet tube connection and completely fill the burette. Close the upper stopcock when a few drops of the starch solution flow out of the inlet tube connection. Close the lower stopcock.
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SULFUR BLOCK 6.
Purge the rubber tubing by venting acid gas (tailgas) to the atmosphere a few seconds. Pinch the rubber tubing closed at the end, close the gas sample valve, and slip the end of the rubber tubing onto the inlet tube connection of the Tutweiler burette's upper stopcock.
7.
Crack the gas sample valve open and draw gas into the burette by lowering the leveling bottle and opening the stopcocks. When the liquid level is several milliliters below the 100-ml mark (500-ml mark), close the lower stopcock, upper stopcock, and gas sample valve.
8.
Remove the sample gas rubber tubing from the Tutweiler burette.
9.
Open the lower stopcock and bring the starch solution to the 100-ml mark (500-ml mark) by raising the leveling bottle; then close the lower stopcock. Open the upper stopcock long enough to equalize the pressure inside the burette with the atmosphere, then close the top stopcock. There is now exactly 100 ml (500 ml) of gas at atmospheric pressure and ambient temperature in the Tutweiler burette.
10. Open the lower stopcock and lower the leveling bottle. Lower the level of the starch solution in the burette to the 110-ml mark (550-ml mark) to pull a partial vacuum. Close the lower stopcock. 11. Place a tubing clamp on the rubber hose to the leveling bottle and remove the hose from the Tutweiler burette lower stopcock. 12. Carefully crack the stopcock on the iodine burette and allow a small amount of iodine solution to be sucked into the large burette. Close the stopcock. NOTE:
Experience will soon allow the operator to know approximately how much iodine will be needed. It is good procedure to admit 75% of this "estimate" the first time.
13. Shake the burette vigorously, carefully holding the glass cap in place on top of the iodine burette with one finger. As soon as all traces of blue are gone, repeat the addition of iodine solution, adding smaller and smaller amounts as the "anticipated" volume is approached. NOTE:
Issued 30 August 2011
For best accuracy, the entire titration procedure explained above should be done smoothly and quickly without
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SULFUR BLOCK interruption or delays. A yellow or red color may develop during the titration, but it is of no significance. 14. Continue the titration until the starch solution turns a definite blue color and holds the color without fading during shaking for approximately one minute. Carefully read the final iodine burette level. 15. Record the temperature of the air around the sampling point.
9.10.2
H2S Concentration in Acid Gas by the Tutweiler Method The inlet amine acid gas can be sampled from the sample connection on the outlet of the Acid Gas Knock-Out Drum. 1.
Using a 100 ml Tutweiler apparatus, sample and titrate the acid gas feed to the SRU as outlined in Section 9.10.1.
2.
Chemical reaction involved: H2S + I2
2 HI + S
The hydrogen sulfide (H2S) is converted to small particles of elemental sulfur by the iodine during the shaking. Good shaking is required to get good contact between the hydrogen sulfide in the gas and the iodine in the liquid. When all of the hydrogen sulfide is converted, the excess iodine causes the characteristic blue color in the presence of starch. This is a universal test for starch. (Iodine causes a blue color when it contacts starchy foods, such as potato for example.) 3.
Calculation of Mole (or Volume) percent H2S (dry basis): ml Iodine Normality of 273 T 760 Mole % H2S (11.85) 289 P - V.P. Solution Used Iodine Solution
Where
T P
= =
sample temperature, °C atmospheric pressure at particular location, mm Hg
V.P
=
vapor pressure of water at sample temperature, mm Hg
The Normality of the standard iodine solution will be 0.1 N. The last three factors (which correct the actual acid gas content to compensate for expansion due to temperature, pressure, and water content) can be combined and calculated as a function of temperature only. This has been done for the 100-ml gas sample
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SULFUR BLOCK and is included as the Tutweiler Factor Chart in this section (Chart 1). Therefore, the equation above is simplified to: Factor from ml Iodine Normality of Mole % H2S Solution Used Iodine Solution Tutweiler Factor Chart
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16.0
SULFUR BLOCK
15.5
Chart 1
15.0
Tutweiler Factor vs. Air Temperature
Tutweiler Factor
9.0
9.5
10.0
10.5
11.0
11.5
12.0
12.5
13.0
13.5
14.0
14.5
Sample Volume: 100 ml Baro. Pressure: 1.033 kg/cm2(a)
-30
-20
-10
0
10
20
30
40
50
Air Temperature, °C Issued 30 August 2011
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SULFUR BLOCK 9.10.3
H2S and SO2 Concentration in Tailgas by the Tutweiler Method The sulfur plant tailgas can be sampled from the sample valve on the outlet line from the fourth pass of the Sulfur Condenser. 1.
Using a 500 ml Tutweiler apparatus, sample and titrate the SRU tailgas as outlined in Section 9.10.1.
2.
Chemical reactions involved: H2S + I2
S + 2 HI
SO2 + I2 + 2 H2O
H2SO4 + 2 HI
The hydrogen sulfide (H2S) and sulfur dioxide (SO2) are converted by the iodine during the shaking. When both gases are completely converted, the slightest excess of free iodine causes the characteristic blue color with the starch solution. Although the relative amount of each gas cannot be determined from the Tutweiler titration alone, only sulfur dioxide is converted to sulfuric acid (H2SO4). Therefore, a further step can be used to determine the amount of sulfuric acid formed in order to calculate the amount of sulfur dioxide originally present in the gas sample. NOTE:
Sulfur dioxide and hydrogen sulfide react in the presence of water to form sulfur: 2 H2S + SO2
3 S + 2 H2O
This side reaction (the Claus reaction) causes the iodine titration to give a low answer. This can be minimized by rapid titration.
Issued 30 August 2011
3.
Carefully drain the blue starch solution into a clean 250 ml Erlenmeyer flask. Rinse the inside of the Tutweiler burette with distilled water and add this washing water to the flask with the blue starch solution.
4.
Using an eyedropper, add one drop of 0.1 N sodium thiosulfate (Na2S2O3) and swirl the flask. This drop should use up the excess iodine and the starch solution should lose its blue color. If more than one drop is required, too much iodine was added.
5.
Add five drops of methyl purple indicator to the flask and swirl gently.
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SULFUR BLOCK 6.
Titrate carefully to a definite green end point with 0.1 N sodium hydroxide (NaOH).
7.
Chemical reactions in this titration:
8.
H2SO4 + 2 NaOH
2 H2O + Na2SO4
HI + NaOH
H2O + NaI
Calculations: a.
For a 500-ml gas sample, Mole (or Vol) percent H2S + SO2 (dry basis): Mole % (H2S SO2)
Where
ml Iodine Normality of 273 T 760 Iodine Solution (2.369) Solution Used 289 P - V.P.
T P
= =
sample temperature, °C atmospheric pressure at particular location, mm Hg
V.P
=
vapor pressure of water at sample temperature, mm Hg
The Normality of the standard iodine solution will be 0.1 N. The last three factors (which correct the actual gas content to compensate for expansion due to temperature, pressure, and water content) can be combined and calculated as a function of temperature only. This has been done for the 500-ml gas sample and is included as the Tutweiler Factor Chart in this section (Chart 2). Therefore, the equation above is simplified to: Mole % Factor from ml Iodine Normality of (H2S SO2) Solution Used Iodine Solution Tutweiler Factor Chart
b.
Mole (or Volume) percent SO2 (dry basis): ml NaOH Normality of Mole % Used NaOH Solution Mole % SO2 1 H S SO ml Iodine Normality of 2 2 Used Iodine Solution
c.
Mole (or Volume) percent H2S (dry basis): Mole % H2S = Mole % ( H2S + SO2 ) – Mole % SO2
d. Issued 30 August 2011
Molar (or Volume) Ratio of H2S to SO2 in tailgas: Sulfur Recovery
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SULFUR BLOCK H2S : SO2 Ratio
Mole % H2S Mole % SO2
Calculate each quantity as shown above and divide to obtain the H2S:SO2 ratio, or consult the Process Gas Analysis Table or the Process Gas Analysis Operating Chart that follows the Tutweiler Factor Chart.
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3.2
SULFUR BLOCK
3.1
Chart 2
3.0
Tutweiler Factor vs. Air Temperature
Tutweiler Factor
1.8
1.9
2.0
2.1
2.2
2.3
2.4
2.5
2.6
2.7
2.8
2.9
Sample Volume: 500 ml Baro. Pressure: 1.033 kg/cm2(a)
-30
-20
-10
0
10
20
30
40
50
Air Temperature, °C Issued 30 August 2011
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SULFUR BLOCK 9.10.4
Tailgas Analysis Table After completion of the Tutweiler iodine and sodium hydroxide titrations (see Section 1 on the preceding pages) the Molar (or Volume) ratio of hydrogen sulfide to sulfur dioxide in the SRU tailgas can be read directly from this table. If the readings fall off the table, divide (or multiply) both titration volumes by the same number in order to get within the range of the table. Note, however, that the iodine and sodium hydroxide solutions must be of the same Normality for the tabulated values to be correct. Examples: If 1.3 ml of 0.1 N iodine is used and 1.8 ml of 0.1 N sodium hydroxide is used, the molar ratio of H2S:SO2 = 1.60. If 3.0 ml I2 and 4.6 ml NaOH are used (these are off the table), divide by 2 to get 1.5 ml I2 and 2.3 ml NaOH, for a molar ratio of H2S:SO2 = 0.88. If 0.8 ml I2 and 1.1 ml NaOH are used, multiply by 2 to get 1.6 ml I2 and 2.2 ml NaOH, for a molar ratio of H2S:SO2 = 1.67. The values in the table below are the ratio of H2S:SO2 for the quantities of iodine and sodium hydroxide used in the titrations. NOTE:
This table is valid only when the Normalities of the iodine and sodium hydroxide solutions are the same.
ml I2
0.9 1.0 1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9 2.0
ml of NaOH 1.0
1.1
1.2
1.3
1.4
1.5
1.6
1.7
1.8
1.9
2.0
8.00 * * * * * * * * * * *
3.50 9.00 * * * * * * * * * *
2.00 4.00 10.00 * * * * * * * * *
1.25 2.33 4.50 11.00 * * * * * * * *
0.80 1.50 2.67 5.00 12.00 * * * * * * *
0.50 1.00 1.75 3.00 5.50 13.00 * * * * * *
0.28 0.67 1.20 2.00 3.33 6.00 14.00 * * * * *
0.12 0.43 0.84 1.40 2.25 3.67 6.50 15.00 * * * *
0.00 0.25 0.58 1.01 1.60 2.50 4.00 7.00 16.00 * * *
* 0.11 0.38 0.73 1.18 1.80 2.75 4.33 7.50 17.00 * *
* 0.00 0.51 0.88 1.35 2.00 3.00 4.67 8.00 18.00 *
* Erroneous Test
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SULFUR BLOCK ml I2
ml of NaOH 2.0
1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9 2.0 2.1 2.2 2.3 2.4 2.5 2.6
2.1
2.2
2.3
2.4
2.5
2.6
2.7
2.8
2.9
3.0
3.1
0.51 0.33 0.20 0.09 0.00 * * * * 0.88 0.63 0.44 0.30 0.18 0.08 0.00 * * 1.35 1.00 0.75 0.56 0.40 0.27 0.17 0.08 0.00 2.00 1.50 1.14 0.88 0.67 0.50 0.36 0.25 0.15 3.00 2.20 1.67 1.29 1.00 0.78 0.60 0.45 0.33 4.67 3.25 2.40 1.83 1.43 1.13 0.89 0.70 0.55 8.00 5.00 3.50 2.60 2.00 1.57 1.25 1.00 0.80 18.00 8.50 5.33 3.75 2.80 2.17 1.71 1.38 1.11 * 19.00 9.00 5.67 4.00 3.00 2.33 1.86 1.50 * * 20.00 9.50 6.00 4.25 3.20 2.50 2.00 * * * 21.00 10.00 6.33 4.50 3.40 2.67 * * * * 22.00 10.50 6.67 4.75 3.60 * * * * * 23.00 11.00 7.00 5.00 * * * * * * 24.00 11.50 7.33 * * * * * * * 25.00 12.00
* * * 0.07 0.23 0.42 0.64 0.90 1.22 1.63 2.14 2.83 3.80 5.33 7.67
* * * 0.00 0.14 0.31 0.50 0.73 1.00 1.33 1.75 2.29 3.00 5.25 5.50
* * * * 0.07 0.21 0.38 0.58 0.82 1.10 1.44 1.88 2.43 4.00 4.20
* Erroneous Test
9.10.5
Tailgas Analysis Operating Chart The titration volumes can also be used with the following Tailgas Analysis Operating Chart for a quick check to see how close to optimum ratio the sulfur plant is currently running.
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SULFUR BLOCK 6.0
Chart 3
5.5
Tailgas Analysis Operating Chart
5.0
H2S:SO2 = 2.3
(Both solutions must be the same normality) H2S:SO2 = 1.7
4.5
4.0
ml of Iodine Solution
DEFICIENT AIR
3.5
EXCESS AIR
3.0
2.5
2.0
1.5
1.0
0.5
0.0 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5.5 6.0 6.5 7.0 7.5 8.0 8.5
ml of Sodium Hydroxide Solution Issued 30 August 2011
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SULFUR BLOCK 9.10.6
Essential Apparatus for Tutweiler Analysis 1.
Tutweiler apparatus, complete, two 100 milliliter size and one 500 milliliter size.
2.
Burette clamps, single, two.
3.
Graduated cylinders, 100 milliliter and 50 milliliter, one each.
4.
Automatic burettes with Teflon stopcocks, 50 milliliter, two.
5.
Erlenmeyer flasks, 250 milliliter, four.
6.
Ring stands, two.
7.
Avery labels, approximately 7/8" x 1¼", one package.
8.
Thermometers, 0°C - 400°C and -30°C - 120°C ranges, three each.
9.
Volumetric flasks with glass stoppers, 1000 milliliter, two.
10. Volumetric flask with glass stopper, 2000 milliliter, one. 11. Dropper bottles, PE (polyethylene), 4 ounce (approx. 125 ml), two. 12. Rubber tubing, ¼" I.D. 13. Tubing clamps, six. 14. Tube fittings, ¼" pipe to ¼" rubber tubing, six. 15. Wash bottle, PE, 1 liter, one. 16. Reagent bottles, plain narrow mouth, with flat head stopper, Pyrex, 1 liter capacity, three. 17. Amber bottles with Bakline screw caps, 5 pint capacity (approx. 2.5 liters), two. 18. Aspirator bottle, 125 milliliter capacity, two.
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SULFUR BLOCK 9.10.7
9.10.8
Materials for Tutweiler Analysis 1.
Acculutes, sodium thiosulfate, 0.1 normal, two.
2.
Acculutes, sodium hydroxide, 0.1 normal, four.
3.
Acculutes, iodine, 0.1 normal, six.
4.
Methyl purple indicator in dropper bottle, 4 ounce (approx. 125 ml), one.
5.
Starch solution, stabilized, 1 quart (approx. 1 liter), one.
6.
Distilled water, 5 gallon, (approx. 20 liters), one.
7.
Stopcock grease, silicone, one tube.
H2S and SO2 Conc. in Tailgas Using Gas Detector Tubes As an alternative to the traditional wet-chemistry methods described in the preceding Section 1 for determining the concentrations of H2S and SO2 in the sulfur plant tailgas, gas detector tubes can be used to quickly and easily make this determination. Although the discussion that follows specifically addresses using gas detector tubes manufactured by Drägerwerk AG of West Germany, there may be suitable detector tubes available from other manufacturers. Dräger tubes can be purchased from most safety equipment supply companies. The following Dräger tubes are needed for this procedure:
9.10.8.1
H2S 0.2%
Dräger Cat. No. CH 281 01
(H2S + SO2) 0.2%
Dräger Cat. No. CH 282 01
Operating Principles Dräger tubes and other gas detector tubes measure gas concentrations by using a sample pump to draw a specific volume of the gas to be sampled into a glass tube containing a suitable reagent. The gaseous compound of interest chemically reacts with the reagent to produce a color change. The length of the "stain" line is a direct function of the concentration of the compound in the sample gas. Some detector tubes are calibrated with measured lines to allow reading the concentration directly on the tube. Others, such as the two listed above, have reference marks on the tube that can be multiplied by a factor to compute the concentration.
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SULFUR BLOCK Dräger tubes are designed to be used with a Dräger Model 31 gas detector pump. This is a hand-operated bellows pump that will draw a 100 cc sample volume for each pump stroke. Some tubes are designed for a single sample stroke, while others may use 5, 10, or even 20 strokes. In some cases, a tube may be used for measuring different concentration ranges by using a different number of strokes. a.
Dräger Cat. No. CH 281 01, H2S 0.2% This tube will measure H2S concentrations in the range of 0.2% to 7% when one sample stroke is used. If desired, the range can be reduced to 0.02% to 0.7% by using 10 sample strokes. Each tube contains a substrate of a pale blue copper compound. When exposed to H2S, the copper compound is converted to black copper sulfide. The length of the black stain, marked in cm on the tube, is multiplied by a factor stamped on the box to give the H2S concentration in percent. This copper sulfide reaction is not affected by any of the other compounds normally found in sulfur plant tailgas. SO2 in the tailgas may turn the indicating layer somewhat yellow (due to precipitation of elemental sulfur), but does not affect the H2S measurement.
b.
Dräger Cat. No. CH 282 01, (H2S + SO2) 0.2% This tube will measure the combined concentration of H2S and SO2 in the range of 0.2% to 7% if one sample stroke is used. If desired, the range can be reduced to 0.02% to 0.7% by using 10 sample strokes. Each tube contains a substrate of brown iodine. When exposed to H2S and/or SO2, the iodine reacts to form hydroiodic acid (a gas) and the brown color disappears. Since H2S reacts with iodine to form elemental sulfur, the brown will become pale yellow. The length of the yellow stain, marked in cm on the tube, is multiplied by a factor stamped on the box to give the H2S+SO2 concentration in percent.
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SULFUR BLOCK 9.10.8.2
Sampling the Tailgas The sulfur plant tailgas can be sampled from the sample valve on the outlet line from the fourth pass of the Sulfur Condenser.
Issued 30 August 2011
a.
Before beginning, check the Dräger pump for leaks by inserting an unopened tube into the pump and stroking the pump. Confirm that the bellows does not re-expand. If it does, either the pump or its seal around the tube is leaking, and the test results will not be accurate.
b.
Attach a short piece of rubber tubing to the process sample valve.
c.
Break off the tips at each end of an H2S Dräger tube and insert it into the sample pump (with the arrow on the side of the tube pointing toward the pump).
d.
Purge the rubber tubing by venting tailgas to the atmosphere for a few seconds. Pinch the rubber tubing closed at the end, close the gas sample valve, slip the end of the rubber tubing onto the end of the Dräger tube, and reopen the sample valve.
e.
Stroke the sample pump one time (be sure to compress the bellows until reaching the stops) and allow the pump to draw the gas sample into the detector tube. The sample stroke is complete when the metal chain on the bellows is taut.
f.
Close the sample valve, remove the rubber tubing from the end of the Dräger tube, and use the pump to draw two strokes of fresh air through the detector tube to complete the reactions.
g.
Read the length of the black stain using the cm marks on the tube and record the reading.
h.
Break off the tips at each end of an H2S+SO2 Dräger tube and insert it into the sample pump (with the arrow on the side of the tube pointing toward the pump).
i.
Repeat steps d through f.
j.
Read the length of the yellow stain using the cm marks on the tube and record the reading.
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SULFUR BLOCK k.
9.10.8.3
Check that the sample valve is closed, then remove the rubber tubing.
Calculations a.
Mole (or Volume) percent H2S (wet basis): Stain Factor 1013 Mole % H2S Length, cm on Box Baro. Pres., mbar
The last factor corrects the measurement for pressure effects when samples are taken at elevations above sea level. Note that the average barometric pressure at the complex is 14.7 PSIA = 1013 mbar. b.
Mole (or Volume) percent H2S+SO2 (wet basis): Stain Factor 1013 Mole % ( H2S SO2 ) Length, cm on Box Baro. Pres., mbar
c.
Mole (or Volume) percent SO2 (wet basis): Mole % SO2 = Mole % ( H2S + SO2 ) – Mole % H2S
d.
Molar (or Volume) Ratio of H2S to SO2 in the tailgas: H2S : SO2 Ratio
9.10.8.4
Mole % H2S Mole % SO2
Example Suppose, for example, that the following measurements are taken: Stain Length
Issued 30 August 2011
Factor on Box
H2S Tube
1.5 cm
0.44
H2S+SO2 Tube
2.1 cm
0.51
a.
Mole % H2S
1013 = (1.5 cm) (0.44) 1013
= 0.66%
b.
Mole % (H2S +SO2)
1013 = (2.1 cm) (0.51) 1013
= 1.07%
c.
Mole % SO2
= 1.07% - 0.66%
= 0.41%
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SULFUR BLOCK d.
H2S : SO2 Ratio
=
0.66% 0.41%
= 1.61
This indicates that the H2S:SO2 ratio is a little low (less than 2.0), so the air:acid gas ratio is on the high side. The output from the air demand hand control should be lowered slightly, and the measurements repeated after the SRU reaches a steady state again. If the H2S:SO2 ratio had been high (greater than 2.0), that would have meant that the air:acid gas ratio was on the low side. In that case, the output from thr air demand hand control would need to be raised slightly to increase the air flow and bring the H2S:SO2 ratio down.
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SULFUR BLOCK
9.11 Adjusting StackMatch® Ignitor/Pilots The pilots for the burners are StackMatch® DRAM (Dual Range Air Mixed) ignitor/pilot assemblies. The ignitor inside each pilot burner is a flame front generator (FFG). It works by taking part of the air and fuel gas mixture that is flowing to the primary pilot, igniting the mixture with a high-energy plasma spark, and allowing the flame "front" to travel down a flame delivery tube to the primary pilot tip, lighting the primary pilot. The small primary flame then ignites the much larger secondary pilot flame. Flame front generator ignitors are preferred for burners in sour service because the electrical parts are not exposed to the corrosive process atmosphere, giving the ignitor better long-term reliability. In order for a flame front generator to work properly, two conditions must be satisfied. First, the air:gas mixture must be within the flammability limits (neither too lean nor too rich). Second, the flowing velocity of the mixture must be higher than the flame speed so that the "fireball" will travel to the pilot. The ignitor has orifices to regulate the air and fuel gas, sized by the manufacturer to provide the proper quantities of air and fuel gas when both streams are at the manufacturer’s specified pressure as indicated on the pressure gauges for both air and fuel gas supplied on the pilot assembly. In theory, adjusting the pilot air and fuel gas regulators to the manufacturer’s specified pressure should be all that is needed to make the ignitor work. In practice, a certain amount of adjustment of the pressures is sometimes required before the ignitor works reliably, especially if the fuel gas composition is variable. However, once the proper pressures are determined, the ignitor can usually be made to work easily by making sure that the regulators are set to these pressures before attempting to ignite the pilot. If the pilot does not light with the regulators set at the design pressures, trial-and-error can be used to determine the proper regulator pressures. One technique that has worked well is described below. It requires two operators: one to adjust the regulators, one to control the ignition cycle and observe the pilot. 1.
Adjust the pilot air regulator to the manufacturer’s specified pressure.
2.
Unscrew the adjustment screw on the pilot fuel gas regulator so that the pilot fuel gas is at minimum pressure.
3.
Follow the procedures given in these guidelines to start the air blower and reset the shutdown system.
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SULFUR BLOCK 4.
The first operator raises the air flow (using the hand indicator controller) to satisfy the "PURGE REQUIRED" light, lowers the air flow to get the "PERMIT TO IGNITE", then pushes the "IGNITION" push-button to begin an ignition attempt.
5.
Once the ignition cycle starts, the second operator begins gradually increasing the pilot fuel gas pressure from the pressure control valve (observing the pressure on the local pressure gauge) while the first operator observes the operation of the pilot through one of the viewports on the burner.
6.
As the pilot fuel gas pressure increases, a flame will be observed on the pilot. When the flame is observed, the second operator should stop increasing the pilot fuel gas pressure.
7.
If the pilot does not ignite, repeat the sequence beginning at Step 4, starting with the pilot fuel gas regulator set where it was at the end of the previous ignition attempt, or a little lower.
8.
If repeated attempts at adjusting the fuel gas pressure are unsuccessful, changing the pilot air pressure regulator setting may be required. Try adjusting the air pressure 0.05-0.10 bar one way or the other.
9.
Once a flame is observed on the pilot, the pilot fuel gas pressure can then be adjusted to produce a good stoichiometric pilot flame. While the first operator continues to observe the pilot flame through the burner viewport, the second operator can raise or lower the pilot fuel gas pressure slightly until the pilot flame is dark blue:
10.
Issued 30 August 2011
a.
If the flame is yellow, the air:natural mixture is too "rich". Lower the fuel gas pressure with the pressure control valve to reduce the amount of fuel gas flowing to the pilot.
b.
If the flame is light blue, the air:natural mixture is too "lean". Raise the fuel gas pressure with the pressure control valve to increase the amount of fuel gas flowing to the pilot.
Once the pilot has ignited, make note of the pilot air and fuel gas pressures for future reference. The pilot regulators should be adjusted to these settings prior to subsequent startups.
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SULFUR BLOCK
Table of Contents 10.
SULFUR DEGASSING, STORAGE & LOADING .................................................. 10-3
10.1 PURPOSE OF SYSTEM ..................................................................................... 10-3 10.2 SAFETY ............................................................................................................... 10-4 10.3 PROCESS DESCRIPTION.................................................................................. 10-5 10.4 EQUIPMENT DESCRIPTION .............................................................................. 10-7 10.4.1 Sulfur Degassing Reactor, A2-DC1550 ........................................................ 10-7 10.4.2 Sulfur Storage Tank, A2-FB1550 ................................................................. 10-7 10.4.3 Sulfur Feed Pump, A2-GA1532A/B (A2-GA1542A/B) .................................. 10-8 10.4.4 Sulfur Loading Pump, A2-GA1550A/B ......................................................... 10-8 10.4.5 Degassing Air Blower, A2-GB1550A/B ......................................................... 10-9 10.4.6 Bed Support and Limiter for Sulfur Degassing Reactor, A2-DC1551 ........... 10-9 10.4.7 Degassed Sulfur Drain Seal Assembly, A2-ME1550.................................... 10-9 10.5 INSTRUMENTATION AND CONTROL SYSTEMS ........................................... 10-11 10.5.1 Sulfur Feed Rate Control ............................................................................ 10-11 10.5.2 Degassing Air Flow..................................................................................... 10-12 10.5.3 Sulfur Degassing Unit Startup Interlock ...................................................... 10-13 10.5.4 Snuffing Steam ........................................................................................... 10-13 10.5.5 Sulfur Loading ............................................................................................ 10-14 10.5.6 Sulfur Loading Pump Local Stop Switches................................................. 10-17 10.5.7 Sulfur Degassing Shutdown System .......................................................... 10-18 10.5.8 Sulfur Loading ESD System ....................................................................... 10-21 10.6 PROCESS PRINCIPLES AND OPERATING TECHNIQUES ........................... 10-23 10.6.1 Equipment Damage .................................................................................... 10-23 10.6.2 Degassing Air Blower Operation ................................................................ 10-26 10.6.3 Sulfur Solidification ..................................................................................... 10-29 10.6.4 Sulfur Pumping ........................................................................................... 10-29 10.7 PRECOMMISSIONING PROCEDURES ........................................................... 10-31 10.7.1 Preliminary Check-out ................................................................................ 10-31 10.7.2 Commissioning the Heating and Ventilation Systems ................................ 10-32 10.7.3 Purging the Sulfur Degassing Reactor ....................................................... 10-37 10.8 STARTUP PROCEDURES................................................................................ 10-40 10.8.1 Initial Startup of the Sulfur Degassing Unit ................................................. 10-40 10.8.2 Normal Startup of the Sulfur Degassing System ........................................ 10-46 10.8.3 Initial Sulfur Loading Operation .................................................................. 10-51 10.8.4 Normal Sulfur Loading Operation ............................................................... 10-53 10.9 SHUTDOWN PROCEDURES ........................................................................... 10-54 10.9.1 Planned Shutdown - No Reactor Entry....................................................... 10-54
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SULFUR BLOCK 10.9.2 10.9.3
Planned Shutdown for Reactor Entry ......................................................... 10-55 Shutdown for Tank Entry ............................................................................ 10-57
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SULFUR BLOCK
10. SULFUR DEGASSING, STORAGE & LOADING 10.1 Purpose of System The purpose of the Sulfur Degassing Unit (SDU) is to reduce the H2S content of the molten sulfur product to 10 PPMW or less, then transport the sulfur to the Sulfur Storage Tank.
The raw sulfur product from the sulfur plant contains
approximately 200-300 PPMW of hydrogen sulfide, which is typically reduced to 50-100 PPMW after one or more days of storage by natural "weathering". Since this natural weathering is not enough to meet the 10 PPMW specification for the sulfur product, the SDU provides additional degassing that will ensure that the H2S content is sufficiently low before the sulfur is transferred to the storage tank. The purpose of the Sulfur Storage & Loading system is to collect the degassed sulfur, hold it in a molten state, and then load it into trucks as a product for sale.
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SULFUR BLOCK
10.2 Safety
WARNING
ALL PIPING AND VESSELS INCLUDED IN THESE SYSTEMS CONTAIN MOLTEN SULFUR, WHICH IS A BURN HAZARD FOR PERSONNEL. CLOSE ATTENTION SHOULD BE PAID TO THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES REGARDING THE HAZARDS POSED BY MOLTEN SULFUR. IN ADDITION, ALL PIPING AND VESSELS INCLUDED IN THIS UNIT EITHER CONTAIN OR HAVE THE POTENTIAL FOR CONTAINING HAZARDOUS GASES THAT MAY CAUSE SERIOUS INJURY OR DEATH.
THE TWO GASES THAT ARE MOST COMMON
AND HAZARDOUS IN A TOXIC WAY ARE HYDROGEN SULFIDE AND SULFUR DIOXIDE.
CLOSE ATTENTION SHOULD BE PAID TO THE
"GENERAL SAFETY" SECTION OF THESE GUIDELINES AS TO THE NATURE AND ABILITY OF THESE GASES TO CONTAMINATE OTHER ELEMENTS IN THIS UNIT. AN EMPLOYEE'S KNOWLEDGE OF THE HAZARDOUS CHEMICALS AND COMPOUNDS WITH WHICH HE WILL BE WORKING IS ONE OF THE MOST BASIC PREREQUISITES FOR HIS OWN SAFETY, THE SAFETY OF
OTHERS,
AND
THE
PROTECTION
OF
EQUIPMENT.
ALL
EMPLOYEES SHOULD REVIEW THE "GENERAL SAFETY" SECTION OCCASIONALLY TO REFRESH THEIR MEMORIES. NEW EMPLOYEES SHOULD STUDY IT UNTIL THE INFORMATION IS THOROUGHLY UNDERSTOOD. PEOPLE WHO HAVE NOT BEEN PROPERLY TRAINED SHOULD NOT BE ALLOWED TO OPERATE OR WORK IN AND AROUND THIS PLANT.
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SULFUR BLOCK
10.3 Process Description The Systems Diagram, Material Balance and Process Flow Diagram, Dwg. Nos. 507000-7000-01, and 507000-7000-07 through -08, are contained in the "Process Flow Diagrams" Section of the Basic Engineering Package. Please refer to these drawings to follow this description of the process. The liquid sulfur produced in the condensers of a Claus sulfur plant is in contact with process gas containing hydrogen sulfide at elevated temperature and pressure. As a result, the fresh sulfur product from Claus plants contains a significant amount of hydrogen sulfide. Some of the hydrogen sulfide in the sulfur is dissolved H2S gas, but the majority of it is hydrogen polysulfide (H2SX) formed in the condensers by the following reaction: (1)
H2S + (x-1) S
H2SX
While the liquid sulfur is stored in the Sulfur Surge Tank, a considerable portion of the polysulfide will break down into H2S and be released into the ventilation air circulated through the vapor space of the tank. This natural "weathering" process typically reduces the H2S content of the molten sulfur to 50-100 PPMW after one or more days of storage. However, since the natural decomposition of H2SX in the liquid sulfur is a slow and generally incomplete process, additional means of degassing the sulfur must be employed to ensure that the H2S content of the sulfur product does not exceed 10 PPMW. The sulfur degassing technology licensed by BP Amoco Corporation is used to reduce the H2S content of the freshly produced sulfur (approximately 200-300 PPMW) to less than 10 PPMW.
The Sulfur Feed Pumps,
A2-GA1532A/B and A2-GA1542A/B pump the fresh liquid sulfur from the Sulfur Surge Tanks, A2-FB1530 and A2-FB1540 to the Sulfur Degassing Reactor, A2-DC1550. Compressed air from the Degassing Air Blower, A2-GB1550A/B is supplied to a sparger in the bottom of the reactor, so that the air and sulfur flow co-currently upward through a catalyst bed.
The catalyst promotes
decomposition of the polysulfide into H2S and sulfur, so that the air can strip the H2S from the sulfur and remove it from the reactor. Since reaction (1) is an equilibrium reaction, removal of the H2S by the air stream shifts the equilibrium toward the left side of the equation, allowing almost complete decomposition of
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SULFUR BLOCK the polysulfide. The degassed sulfur, containing less that 10 PPMW hydrogen sulfide, gravity-drains from the top of the reactor into the Sulfur Storage Tank, A2-FB1550, through the Degassed Sulfur Drain Seal Assembly, A2-ME1550. The drain seal has a "U" tube that uses static head from a column of liquid sulfur to serve as a seal and prevent the degassing air from escaping. The drain seal is steam jacketed to prevent sulfur from freezing and has a view hatch to allow verifying that the rundown line is flowing. The spent degassing air (containing H2S and traces of elemental sulfur vapor) leaves the top of the Sulfur Degassing Reactor and is routed to the TTO for incineration. The Sulfur Storage Tank is sized to hold about two week of production from the two SRUs, or about 500 MT when completely full. The tank is constructed of carbon steel and is equipped with internal steam coils and a ventilation system. The steam-jacketed Sulfur Loading Pump, A2-GA1550A/B, mounted beside the tank is used to load molten sulfur into trucks at two loading spots.
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SULFUR BLOCK
10.4 Equipment Description 10.4.1
Sulfur Degassing Reactor, A2-DC1550 The Sulfur Degassing Reactor contains a catalyst bed to promote the decomposition of the polysulfide into H2S and sulfur, so that the air from the Degassing Air Blowers can strip the H2S from the sulfur and remove it from the reactor. Sulfur enters the bottom of this vertical vessel and mixes with air entering through a sparger so that the air and sulfur flow co-currently upward through the catalyst bed.
The degassed sulfur
gravity-drains from the top of the vessel through the Degassed Sulfur Drain Seal Assembly and into the Sulfur Tank. The degassing air flows through a mist eliminator as it leaves the top of the reactor and is then routed to the Tailgas Thermal Oxidation system. Since the normal liquid level for molten sulfur in this reactor is at the top of the weir on the draw pan above the catalyst bed, the bottom head and shell of the vessel are steam-jacketed. The inlet and outlet sulfur, inlet air, outlet gas, and clean-out nozzles are also steam-jacketed.
10.4.2
Sulfur Storage Tank, A2-FB1550 The Sulfur Storage Tank is an above-ground vertical cylindrical tank. It has serpentine steam coils in the bottom and circumferential steam coils on the sides to keep the sulfur molten, each with its own steam supply and trap. Should a steam coil develop a leak, it can be shut off while the others keep the sulfur hot. It has a level transmitter to indicate the sulfur level, with a high level alarm to alert the operators of a high level. There is a snuffing steam line entering the top of the tank in case of fire. The primary ventilation system for the Sulfur Storage Tank is a natural-draft ventilation system.
Ambient air enters through the four
breather vents placed around the top of the tank and sweeps through the tank. This air circulation dilutes the H2S that may "weathers off" from the liquid sulfur so that the concentration remains below the lower explosive limit. The air circulation also prevents accumulation of water in the tank that could cause rapid corrosion. The vapors are vented from the vessel
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SULFUR BLOCK through a 3 m tall heated vent stack, mounted on top of the tank. The steam-jacketing on the vent stack heats the air in the stack, providing the natural-draft driving force that draws ambient air into the tank to sweep the vapor space.
WARNING
IT IS VERY IMPORTANT TO KEEP HEAT (STEAM) ON THE VENT STACK TO MAINTAIN THE NATURAL DRAFT. IN ADDITION, THE STEAM SPACE IN THE VENT STACK JACKET MUST VENTED PERIODICALLY
TO
PREVENT
NON-CONDENSIBLES
FROM
ACCUMULATING AND "BLANKING OFF" THE STEAM HEATING SURFACES. A VENT LINE IS PROVIDED EXPRESSLY FOR THIS PURPOSE.
10.4.3
Sulfur Feed Pump, A2-GA1532A/B (A2-GA1542A/B) These special steam-jacketed sump-type pumps are used to transfer the molten sulfur product from the Sulfur Surge Tanks to the Sulfur Degassing Reactor. This type of pump is unique in that it uses the molten sulfur to lubricate its bearings.
For this reason, the pumps should never be
operated dry.
10.4.4
Sulfur Loading Pump, A2-GA1550A/B These pumps are horizontal centrifugal pumps. They are steam-jacketed to keep the sulfur in the molten state and send it to the loading stations for sulfur trucks. Start and stop push-buttons are located at the loadings station for ease of loading. Stop switches are also located at the pumps for emergency use.
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SULFUR BLOCK 10.4.5
Degassing Air Blower, A2-GB1550A/B These single-stage rotary lobe blowers provide the degassing air required to strip the H2S from the sulfur in the Sulfur Degassing Reactor. The blowers are connected to the discharge piping through flexible connectors to allow the necessary freedom for the expansion and movement that occurs during normal operation.
10.4.6
Bed Support and Limiter for Sulfur Degassing Reactor, A2-DC1551 A bed support and a bed limiter fabricated from grid-type 304 S.S. screen are used to hold the catalyst bed in the Sulfur Degassing Reactor. The screens are fabricated in sections that fit through the vessel manways. One side of each screen section is equipped with flashing where it fits next to its neighbor, so that the screen sections can expand and contract without creating gaps where the catalyst could leak through. Both the bed support and the bed limiter are designed to have about a 12 mm gap next to the vessel shell to allow for differential thermal expansion between the bed support and the vessel.
Ceramic rope
packing is used to fill this gap so that catalyst cannot leak between the bed support and the vessel shell.
10.4.7
Degassed Sulfur Drain Seal Assembly, A2-ME1550 One of Ortloff's proprietary Sulfur Drain Seal Assemblies is used for the Degassed Sulfur Drain Seal Assembly. It is designed to drain liquid sulfur from the Sulfur Degassing Reactor. The seal is built as a "U-type" trap that uses liquid sulfur to seal and prevent process gases from flowing to the Sulfur Tank along with the liquid sulfur product. The drain seal is sized to provide a seal leg which should not blow out at the maximum operating pressure of the Sulfur Degassing Reactor. The seal is fully steam-jacketed and designed to be installed in the top of the Sulfur Tank.
The seal has a hinged inspection hatch to allow
observation and sampling of the flow from the Sulfur Degassing Reactor. The liquid sulfur from the inspection basin flows down to the bottom of the
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SULFUR BLOCK Sulfur Tank through a drain pipe to prevent free-fall of the liquid sulfur, which could cause static electricity to build up. The drain seal is mostly carbon steel, except for the inspection hatch which is aluminum. The drain seal has a removable blind flange to allow "rodding" its rundown line, and a removable blind flange to allow "rodding" its dip leg. Before removing either flange, close the plug valve in the rundown line to prevent the escape of process gas to the surroundings when the plug is cleared. When the rodding operation is complete and the flange(s) are back in place, remember to reopen the plug valve.
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SULFUR BLOCK
10.5 Instrumentation and Control Systems 10.5.1
Sulfur Feed Rate Control A reasonably steady sulfur feed rate to the Sulfur Degassing Reactor will help the Sulfur Degassing Unit operate smoothly.
At the same time,
however, the feed rate to the reactor must match the sulfur production rate into the Sulfur Surge Tanks from the SRUs reasonably closely, or else the Surge Tanks will eventually run dry. A level/flow cascade control loop is used to satisfy these requirements. Traditional level measuring devices do not function reliably in molten sulfur service. For this reason, a "bubbler"-type level transmitter is most often used in this service.
A steam-jacketed pipe (a bubbler tube) is
mounted through the top of the Sulfur Surge Tank and extended nearly to the bottom of the tank. A small flow of instrument air is introduced into the inner pipe, so that air slowly bubbles from the bottom of the pipe up through the sulfur. The pressure inside the bubbler tube depends on the static head imposed by the liquid sulfur in the tank, which is a linear function of the liquid level.
The DCS can then convert this pressure
measurement into the corresponding liquid sulfur level in the tank. This type of level measuring device is used for A2-LT15450 and A2-LT15449. Traditional flow measuring devices also do not function reliably in molten sulfur service. For this reason, a "Coriolis"-type mass flow meter is used to measure the liquid sulfur as it is pumped from the Sulfur Surge Tanks into the Sulfur Degassing Reactor by the Sulfur Feed Pumps. The flow meter, A2-FT15450, is located downstream of the take-off for the spill-back line so that the sulfur feed rate from SRU 1 into the reactor can be adjusted by varying the amount of sulfur spilling back into the tank. The level in the tank is controlled by A2-LIC15450, which supplies a cascade setpoint to the sulfur feed rate controller, A2-FIC15450. If the level is rising in the tank, the feed rate from SRU1 to the Sulfur Degassing Reactor will be slowly increased by raising the setpoint of A2-FIC15450. If the level is falling, the setpoint will be lowered to slowly reduce the feed rate. In this manner, the level in the Sulfur Surge Tank can be maintained
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SULFUR BLOCK at the desired value while avoiding sudden changes in the feed rate to the Sulfur Degassing Reactor.
10.5.2
Degassing Air Flow A constant ratio of degassing air flow to sulfur flow is not necessary for the Sulfur Degassing Unit to operate smoothly. It is only necessary that the air:sulfur flow ratio be maintained above a minimum value (45 Nm3/MT) to ensure adequate stripping of the sulfur. The air flow rate to the Sulfur Degassing Reactor is not controlled, but instead is simply dictated by the capacity of the Degassing Air Blower. The design flow rate of one of these blowers is high enough to maintain the air:sulfur flow ratio above the minimum even at the design sulfur production rate. There are two reasons for using a fixed degassing air flow rate rather than controlling the air:sulfur flow ratio.
The first reason is that the spent
degassing air from the Sulfur Degassing Reactor is routed to the Thermal Oxidizer as a part of its feed. Keeping the degassing air flow rate at a constant value makes it easier to maintain good temperature control in the TTO. The second reason is that variations in the air flow rate can cause fluctuations in the sulfur feed rate to the Sulfur Degassing Reactor. The pumping rate of the Sulfur Feed Pumps depends on the discharge pressure from the pumps, which is in turn a function of the static head imposed on the pump discharge. This static head has two components: the static head of the liquid sulfur in the discharge piping going to the Sulfur Degassing Reactor, and the static head of the sulfur/air mixture in the Sulfur Degassing Reactor. While the first static head is essentially constant because the density of liquid sulfur is relatively constant, the second static head depends on the density of the sulfur/air mixture in the reactor. Small changes in the degassing air flow rate cause very large changes in the density of the sulfur/air mixture, which then cause very large changes in the pump discharge pressure.
Field experience has
shown that the sulfur flow rate remains much steadier when the degassing air flow rate is held at a fixed value. If the degassing air flow rate ever drops too low (as signaled by the low Issued 30 August 2011
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SULFUR BLOCK flow alarm on A2-FI15702) and the low flow condition cannot be corrected in a reasonable length of time, the SDU should be shut down until the air flow problem has been corrected.
10.5.3
Sulfur Degassing Unit Startup Interlock The purpose of this interlock is to ensure the Sulfur Degassing Unit equipment is placed in operation in a safe manner. This interlock includes several permissives which must be satisfied in the correct order, or the pumps and blowers will not start. The logic flowchart for the SDU "start" permissives is contained in the Instrumentation and Controls Diagrams section of the Basic Engineering Package. These permissives are (in order): (1)
Start a Sulfur Feed Pump.
(1)
Allow the pump to fill the Sulfur Degassing Reactor to satisfy its low-low level shutdown.
(2)
Start a Degassing Air Blower and press its "reset" push-button to open its discharge valve.
Failure to satisfy a permissive will prevent proceeding any further in the startup sequence.
This prevents creating conditions in the Sulfur
Degassing Reactor that could lead to problems (fires, etc.)
10.5.4
Snuffing Steam There are snuffing steam lines entering the top of each Sulfur Surge Tank to flood the vapor space with LP steam in case a fire develops inside a tank. The snuffing steam supply valves are operated by either a remote switch in the DCS or a local switch that is located at least 50 feet from the tank. Opening this valve for a few minutes will fill the vapor space of the tank with steam and displace all of the air, quickly extinguishing the fire. There is a snuffing steam line entering the top of the Sulfur Storage Tank to flood the tank vapor space with LP steam in case a fire develops inside the tank. The snuffing steam supply valve is operated by either a remote switch in the DCS or a local switch that is located at least 50 feet from the tank. Opening this valve for a few minutes will fill the vapor space of the
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SULFUR BLOCK tank with steam and displace all of the air, quickly extinguishing the fire. The logic for the snuffing steam valves is contained in the Instrumentation and Controls Diagrams section of the Basic Engineering Package. They can be opened by "toggling" the switch in the DCS to "on" or by pressing the local push-button. The valve can be closed later by "toggling" the switch in the DCS to "off" or by pressing the local push-button again.
10.5.5
Sulfur Loading The Sulfur Loading system is designed to load molten sulfur from the Sulfur Storage Tank into sulfur trucks, or both simultaneously.
The
loading operations are controlled by a programmable logic controller (PLC) housed in a local control panel located inside the loading building in the sulfur loading area. Status indicator lights are mounted on the front of this panel to allow monitoring operation of the system and to assist with troubleshooting. The logic for sulfur loading operations is shown on the Logic Flow Diagrams contained in the Instrumentation and Controls Diagrams section of the Basic Engineering Package. Note that only one Sulfur Loading Pump at a time is used for loading, regardless of whether one or both loading spots are being used. Selector switch A2-HS15716 is used to select which Sulfur Loading Pump is active. 10.5.5.1
Starting Sulfur Loading The sequence of events when beginning sulfur loading can be summarized as follows. (1)
The truck driver spots his truck and connects the grounding cable.
(2)
The truck driver presses the "START" push-button on the applicable start/stop station. The associated status light at that loading spot begins flashing and a timer for that loading spot is started.
(3)
The discharge valve on the Sulfur Loading Vent Ejector (A2-EE1550A or A2-EE1550B) at that loading spot is opened
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SULFUR BLOCK and proven open. (4)
The motive steam valve on the Sulfur Loading Vent Ejector at that loading spot is opened and proven open.
(5)
The sulfur loading valve at that loading spot is opened and proven open.
(6)
A Sulfur Loading Pump (A2-GA1550A or A2-GA1550B) is started, a timer for that pump is started, and the associated status light for that pump on the local loading control panel begins flashing. If the other loading spot is not currently active, the "lead" pump is started. If the other loading spot is active, the "lag" pump is started. When selector switch A2-HS15716 is set to "NORMAL", the "A" and "B" pumps will alternate in the "lead" position after each loading operation. If A2-HS15716 is set to either "A" or "B", only that pump is to be started even when both loading spots are active.
(7)
When its motor starter contacts show that the pump is running, the discharge valve for that pump is opened and proven open.
(8)
If the pump discharge valve is proven open before the timer on that pump times out, the pump status light stops flashing and remains steadily illuminated. If the timer times out before the pump discharge valve is proven open, the pump is stopped, its discharge valve is closed, its status light is extinguished, and the corresponding "pump start failure" alarm is activated. If it was the "lead" pump that failed to start, then an attempt is made to start the "lag" pump beginning at step (6). If the timer for the "lag" pump times out before its discharge valve is proven open, the "lag" pump is stopped, its discharge valve is closed, its status light is extinguished, the corresponding "pump start failure" alarm is activated, and the "PUMP START FAILURE" status
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SULFUR BLOCK light on the local loading control panel is illuminated. The Sulfur Loading ESD is also activated to stop both pumps and close all of the valves (pump discharge, sulfur loading, motive steam, and ejector discharge). (9)
If one of the pumps is successfully started before the timer on that loading spot times out, the status light for that loading spot stops flashing and remains steadily illuminated, and sulfur will begin flowing into the truck.
10.5.5.2
Stopping Sulfur Loading The sequence of events when ending sulfur loading can be summarized as follows. (1)
The truck driver presses the "STOP" push-button on the applicable start/stop station. The associated status light at the loading spot begins flashing.
(2)
If the other loading spot is not currently active, stopping of the "lead" pump is initiated.
If the other loading spot is active,
stopping of the "lag" pump is initiated. The applicable pump status light on the local loading control panel begins flashing. (3)
The applicable pump (A2-GA1550A or A2-GA1550B) is stopped.
(4)
The applicable discharge valve is closed and proven closed.
(5)
When its motor starter contacts show that the pump is stopped and the limit switches show the pump discharge valve is closed, the pump status light on the local loading control panel is extinguished.
(6)
The sulfur loading valve at that loading spot is closed and proven closed.
(7)
The motive steam valve on the Sulfur Loading Vent Ejector at that loading spot is closed and proven closed.
(8)
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The discharge valve on the Sulfur Loading Vent Ejector at that
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SULFUR BLOCK loading spot is closed and proven closed. (9)
10.5.6
The status light for that loading spot is extinguished.
Sulfur Loading Pump Local Stop Switches Section 10.5.5 describes how the pump start and stop push-buttons located at the truck loading stations are used to transfer sulfur from the Sulfur Storage Tank to the loading spots. Local pump "stop" switches are located at each pump for maintenance or emergency use. Setting one of these switches to the "STOP" position will remove the power from the corresponding pump motor to prevent that pump from running.
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SULFUR BLOCK 10.5.7
Sulfur Degassing Shutdown System The purpose of the Sulfur Degassing Unit Emergency Shutdown system (SDU ESD) is to shut off the sulfur and degassing air flow to the Sulfur Degassing Reactor, A2-DC1550, when serious problems occur.
The
Cause and Effect Diagram, contained in the Instrumentation and Controls Diagrams section of the Basic Engineering Package, describes the SDU ESD system in block format. For reference, the causes and effects of the ESD system shown on this diagram are explained below. 10.5.7.1
Causes Any one of the devices listed below will activate the SDU ESD:
a.
No Sulfur Feed Pump Running, A2-GA1542A&B starter contacts
A2-GA1532A&B
and
If no Sulfur Feed Pump is running, the loss of sulfur flow with continued degassing air flow could cause a fire in the Sulfur Degassing Reactor.
The motor starter contacts are used to
determine whether a pump is running, and activate the SDU ESD if neither is running. a.
Sulfur Degassing A2-TT15703A/B/C
Reactor
High-High
Temperature,
There is always a potential for a fire in the Sulfur Degassing Reactor since sulfur is flammable at elevated temperatures (generally above 237°C) and it is in contact with air. The heat from a sulfur fire would damage the equipment if allowed to continue burning. If this device detects a high temperature from a fire or a runaway reaction, it will activate the SDU ESD to shut off the sulfur and degassing air flows before equipment damage occurs. The setpoint for these devices is 205°C. b.
No Degassing Air Blower Running, A2-GB1550A and A2-GB1550B starter contacts If there is no Degassing Air Blower running, the Sulfur Degassing system is not operating properly and requires operator attention. The motor starter contacts are used to determine whether a blower is
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SULFUR BLOCK running, and activate the SDU ESD if neither of the blowers is running. c.
Sulfur Degassing Reactor High-High Level, A2-LT15704A A high-high level in the Sulfur Degassing Reactor could allow liquid sulfur to begin to carry-over into the Thermal Oxidizer. This device activates the SDU ESD to shut off the pumps and blowers should this occur. The shutdown setpoint for this device is 5,300 mm above the bottom seam of the reactor vessel.
d.
Sulfur Degassing Reactor Low-Low Level, A2-LT15704B A low-low level in the Sulfur Degassing Reactor indicates the Sulfur Degassing system is not operating properly and requires operator attention. This device activates the SDU ESD to shut off the pumps and blowers should this occur. The shutdown setpoint for this device is 3,850 mm above the bottom seam of the reactor vessel.
10.5.7.2
Effects A Sulfur Degassing Shutdown, activated by any one of the devices listed above, has the following effects on the Sulfur Degassing Unit:
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a.
Shuts down the Sulfur Feed Pump, A2-GA1532A/B and A2-GA1542A/B, to stop the flow of sulfur into the Sulfur Degassing Reactor.
b.
Shuts down the Degassing Air Blower, A2-GB1550A/B, to stop the flow of air into the Sulfur Degassing Reactor.
c.
Closes the Sulfur Feed Pump discharge valves to prevent draining all of the sulfur out of the Sulfur Degassing Reactor.
d.
Closes the Degassing Air Blower discharge valves, A2-NV15701A and A2-NV15701B, to prevent back-flow and possible venting of any hazardous gases to the atmosphere.
e.
Places each sulfur feed controller in "manual" and sets its output to 0% to close the control valve in each spill-back line and prevent draining all of the sulfur out of the Sulfur Degassing Reactor. (The normal control action would close these valves when the associated pump stops and the sulfur quits flowing, but it may not do so quickly enough to prevent much of the
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SULFUR BLOCK sulfur from draining out of the reactor.) 10.5.7.3
Non-ESD Shutdowns and Alarms a.
Sulfur Surge Tank Low-Low Level, A2-LT15449 and A2-LT649 Each Sulfur Feed Pump is based on a unique design that uses the molten sulfur to lubricate the shaft bearings. It requires a minimum submergence above the impeller to ensure steady flow so that the bearings remain lubricated; otherwise, the pump could be damaged.
This transmitter will activate the
SDU ESD to shut down the pump if the level in the raw production section of the Sulfur Tank gets too low. It is set to actuate if the liquid level drops to 450 mm above the tank floor, however this value should be confirmed once a specific pump has been selected.
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SULFUR BLOCK 10.5.8
Sulfur Loading ESD System The purpose of the Sulfur Loading Emergency Shutdown (ESD) system is to stop all the sulfur loading equipment when serious problems occur. The Cause and Effect Diagrams, contained in the Instrumentation and Controls Diagrams section of the Basic Engineering Package, describes the Sulfur Loading ESD system in block format. For reference, the causes and effects of the ESD system shown on this diagram are explained below.
10.5.8.1
Causes Any one of the causes listed below will activate the Sulfur Loading ESD system: a.
Manual Shutdown Switches, A2-HS15727 and A2-HS15728 An operator can activate the Sulfur Loading ESD system using either of two manual shutdown switches:
b.
(1)
A2-HS15727 is a NORMAL / ESD selector switch mounted in the truck loading area.
(2)
A2-HS15728 is a NORMAL / ESD selector switch mounted on the local loading control panel.
Sulfur Storage Tank Low-Low Level, A2-LT711A The Sulfur Loading Pump (A2-GA1550A/B) could be damaged if the pump loses suction because the level in the Sulfur Storage Tank drops too low. These devices will protect the pump by stopping it before this can occur.
The shutdown
setpoint is 600 mm above the bottom of the tank. c.
Both Sulfur Loading Pumps Fail to Start, PLC logic If neither the "lead" nor the "lag" Sulfur Loading Pump starts, the Sulfur Loading ESD system is activated to shut down the system and direct operator attention to the loading system.
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SULFUR BLOCK 10.5.8.2
Effects A Sulfur Loading Shutdown, activated by any one of the devices listed above, has the following effects on the Sulfur Loading system:
10.5.8.3
a.
Shuts down the Sulfur Loading Pump (A2-GA1550A&B) to stop the flow of sulfur to the loading arms.
b.
Closes the Sulfur Loading Pump discharge valves.
c.
Closes the sulfur loading valves to stop the flow of sulfur from the loading arms.
d.
Once the sulfur loading valves are closed, closes the motive steam valves on the Sulfur Loading Vent Ejector (A2-EE1550A&B).
e.
Once the motive steam valves are closed, closes the discharge valves on the Sulfur Loading Vent Ejector.
Non-ESD Shutdowns In addition to the devices listed in Section 10.5.8.1 that activate the Sulfur Loading ESD system, there is one additional interlock of significance that shuts down individual pieces of equipment. a.
Loading Spot Ground Disconnected, A2-CS15721A&B If continuity is lost for the ground connection at a loading spot, that loading spot is shut down, and the applicable Sulfur Loading Pump is stopped.
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SULFUR BLOCK
10.6 Process Principles and Operating Techniques The more important considerations involved in startup, operation, shutdown, maintenance, and emergency procedures of the Sulfur Degassing and Sulfur Storage & Loading systems are discussed in the remaining sections of this portion of the operating guidelines. The operator should also be thoroughly acquainted with the equipment and the "Process Description" section in these guidelines before attempting to operate the plant in accordance with the operating techniques that follow. If the function of each portion of the plant equipment is understood, the sequence of steps outlined in the "procedures" sections will be more easily understood.
In addition, the following general
discussion of principles and techniques will clarify the reasons for some of the procedures.
10.6.1
Equipment Damage After the initial startup, the Sulfur Degassing Unit will contain some sulfur throughout the system. Even when sulfur is drained out of the Sulfur Degassing Reactor, the interior of the vessel will still be coated with residual sulfur.
Elemental sulfur and/or iron sulfide in the Sulfur
Degassing Reactor may ignite if the Degassing Air Blower continues to run during periods when either both Sulfur Feed Pumps are shut off or the reactor is not full of liquid sulfur. The heat from the fire can damage the reactor and its outlet lines if allowed to continue burning. For this reason, it is important that the degassing air not be introduced into the Sulfur Degassing Reactor until it has been filled up to its normal operating level with molten sulfur. This will ensure that if any iron sulfide ever develops on the walls of the reactor, it will be immersed in the liquid sulfur so that air cannot contact the walls directly and cause spontaneous auto-ignition of the iron sulfide. The walls of the reactor above the normal liquid level are always exposed to an oxygen-rich atmosphere, so iron sulfide should not form above the air-liquid interface level in the reactor. Note that the interior of the Sulfur Degassing Reactor is lined with a baked phenolic coating to prevent iron sulfide from forming, but over time the lining may deteriorate and expose some of the carbon steel.
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SULFUR BLOCK When air first begins flowing through the Sulfur Degassing Reactor when it is full of raw (not partially degassed) sulfur, it is possible for the H2S concentration in the degassing air leaving the reactor to be above the lower explosive limit for a short period of time if the air flow rate is too low. For this reason, it is important to raise the air flow to its normal value quickly when first starting air flow to the Sulfur Degassing Reactor with it full of raw sulfur.
WARNING
NEVER START A DEGASSING AIR BLOWER UNLESS EACH OF THE FOLLOWING IS TRUE: 1. THE SULFUR DEGASSING REACTOR IS FILLED WITH LIQUID SULFUR UP TO ITS NORMAL OPERATING LEVEL AND SULFUR IS RUNNING OUT OF THE SULFUR DRAIN SEAL. 2. A SULFUR FEED PUMP IS RUNNING AND THE SULFUR FLOW METER DOWNSTREAM OF THE RUNNING PUMP INDICATES SULFUR IS FLOWING. 3. THE UPSTREAM SRU(S) IS OPERATING SMOOTHLY IF IT(THEY) IS ON-LINE. 4. THE THERMAL OXIDIZER IS ON-LINE AND OPERATING SMOOTHLY.
FAILURE TO OBSERVE THESE PRECAUTIONS COULD CAUSE A FIRE
AND/OR
EXPLOSION
IN
THE
SULFUR
DEGASSING
REACTOR.
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SULFUR BLOCK
CAUTION
NEVER "HYDROBLAST" THE STEEL SURFACES IN THE SULFUR DEGASSING EQUIPMENT. NOT ONLY DOES THIS REMOVE THE PROTECTIVE SULFIDE FILM THAT FORMS ON CARBON STEEL AND PREVENTS CORROSION, THE WATER WILL REACT WITH THE SULFUR COMPOUNDS PRESENT IN THE EQUIPMENT TO FORM A VARIETY OF ACIDS (SULFUROUS, POLYTHIONIC, ETC.) THAT WILL RAPIDLY CORRODE THE STEEL. After the initial startup, the Sulfur Storage & Loading system will also contain sulfur throughout the system. Even when the sulfur is pumped out of the Sulfur Storage Tank, the interior of the tank will still be coated with residual sulfur. Elemental sulfur and/or iron sulfide in the Sulfur Storage Tank may ignite when ventilating the tank with air prior to maintenance operations. The heat from the fire can damage the tank if allowed to continue burning, so use the snuffing steam to extinguish the fire should this occur. The walls of the tank above the liquid level are exposed to an oxygen-rich atmosphere (due to the ventilation system sweeping air through the vapor space of the tank), so little iron sulfide should form above the highest air-liquid interface level in the tank. The middle region of the tank walls should not have much iron sulfide, either, since the oxygen in the sweep air will oxidize the iron sulfide as soon as the level is pumped back down. However, the "heel" region of the tank may build up a considerable quantity of iron sulfide, so auto-ignition of this iron sulfide is always a potential problem when preparing the tank for maintenance.
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SULFUR BLOCK 10.6.2
Degassing Air Blower Operation The Degassing Air Blowers, A2-GB1550A/B, are conventional rotary-lobe positive displacement air compressors.
Although these air blowers
operate much like conventional air compressors, the blowers do require some special attention during startup or when bringing an off-line blower into service. These cases are discussed in the sections below. 10.6.2.1
Starting a Degassing Air Blower There are a couple of issues that merit discussion regarding starting a Degassing Air Blower.
First, like any positive displacement
compressor or pump, these blowers must not be started up against a blocked discharge to avoid physically damaging the blower. Instead, the blow-off valve in the blower discharge line should always be fully opened before starting a blower. This allows the blower to start in an unloaded condition, minimizing the stress on the blower and motor, and prevents any possibility of over-pressuring the blower casing or discharge piping. The second issue is related to the manner in which the Sulfur Degassing Reactor must be brought on-line. The Sulfur Degassing Reactor must be filled with liquid sulfur up to the normal operating level (the top of the side weir on its draw pan) before degassing air is introduced into the reactor. As the sulfur is filling the reactor, it will "back" into the degassing air feed line (since there is no air flow at this point) as the liquid "seeks its own level". Once the reactor has been filled with sulfur, there will be liquid sulfur in the degassing air line up to about the same elevation as the sulfur in the reactor. This section of piping is steam-jacketed so freezing of the sulfur is not a concern. What is a concern, however, is what happens when the discharge valve on the Degassing Air Blower first opens. Before the valve opens, the pressure in the vapor space of the Sulfur Degassing Reactor should be at nearly atmospheric pressure, since the spent degassing air is routed to the Thermal Oxidizer.
The
degassing air line will also be at low pressure because the discharge
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SULFUR BLOCK valve on the Degassing Air Blower will still be closed at this point, even though the blower may be running. But when a Degassing Air Blower is started and it's "reset" push-button is pressed, the PLC will open the discharge valve on the blower. If there is back-pressure on the Sulfur Degassing Reactor from the TTO when the discharge valve opens, the pressure inside the Sulfur Degassing Reactor will force liquid sulfur from the reactor up into the degassing air line. If the back-pressure is high enough, liquid sulfur could overflow the "loop seal" in the degassing air line, allowing sulfur to back down the line to the Degassing Air Blower. This can be prevented by "pinching" the blow-off valve on the Degassing Air Blower discharge line before pressing the "reset" push-button to allow the pressure in the line to build up before the valve opens. Then the pressure in the degassing air line will keep the sulfur from overflowing the loop seal.
The procedure for
commencing degassing air flow described later in these guidelines includes the following steps:
10.6.2.2
(1)
Fully open the blow-off valve on the blower.
(2)
Start the blower and let it come up to speed.
(3)
Slowly "pinch" the blow-off valve until the discharge pressure increases to 0.07-0.15 kg/cm2(g).
(4)
Press the "reset" push-button to open the blower discharge valve.
(5)
Slowly close the blow-off valve the rest of the way to establish air flow into the Sulfur Degassing Reactor.
"Swapping" Degassing Air Blowers During Operation While the Sulfur Degassing Unit is running, it is sometimes necessary to "swap" air blowers to bring the off-line blower on-line so that the other blower can be shut down.
This can usually be
accomplished with only a slight "bobble" to the SDU by starting and stopping the blowers in the proper sequence. The procedure given below is one technique that should make swapping blowers relatively
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SULFUR BLOCK simple and avoid any problems. A.
On the on-line blower: (1)
B.
Confirm that the valve in its blow-off line is fully closed.
On the off-line blower: (1)
Confirm that its discharge valve is closed.
(2)
Fully open its blow-off valve.
C.
Start the off-line blower using its local start/stop control station.
D.
After the off-line blower comes up to speed, press its "reset" push-button to open its discharge valve. Since its blow-off valve is still wide open at this point, the blower will not be able to develop enough discharge pressure to open the check valve in its discharge line.
E.
Slowly "pinch" the blow-off valve on the off-line blower until its discharge pressure rises enough to open its check valve and begin sending some of its air to the Sulfur Degassing Reactor.
F.
Slowly open the blow-off valve on the on-line blower to begin venting some of its air to atmosphere.
G.
Continue to close the blow-off valve on the off-line blower and open the blow-off valve on the on-line blower. Observe the degassing air flow rate on the local indicator on the degassing air flow transmitter and proceed slowly enough to keep the degassing air flow rate stable.
H.
Once the blow-off valve is fully closed on the one blower and fully open on the other blower, the off-line blower is now the on-line blower and vice versa. Use the local start/stop control on what is now the off-line blower to stop that blower and close its discharge valve, then close its blow-off valve.
I.
The blower swap is now complete. Before leaving the area, visually confirm that: (1)
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The off-line blower is stopped.
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SULFUR BLOCK
10.6.3
(2)
The discharge and blow-off valves on the off-line blower are closed.
(3)
The on-line blower is running smoothly.
(4)
The Sulfur Degassing Unit has returned to steady operation.
Sulfur Solidification Sulfur melts at 119°C [246°F]. All surfaces in these systems must be maintained above this temperature while the system contains sulfur to avoid plugging the piping or damaging rotating equipment due to formation of solid sulfur. For this reason, there are steam coils along the bottom inside of the Sulfur Surge Tanks, and along the walls and bottom inside the Sulfur Storage Tank. The Sulfur Feed Pumps and Sulfur Loading Pump are steam-jacketed. All of the piping and valves in liquid sulfur service are steam-jacketed, as are the ventilation systems on the Sulfur Surge Tanks and Sulfur Storage Tank. The steam traps serving these heating systems should be checked regularly to verify proper operation. The simplest method to do this is to verify that sulfur will melt on the steam trap inlet; if the condensate there is hot enough to melt sulfur, then the steam in the jackets will be hot enough, too. It is also important to periodically sweep the non-condensibles out of the jackets and coils by giving their vent valves a good "blow". This will prevent the accumulation of non-condensibles that could create localized "cold" spots where sulfur can freeze.
10.6.4
Sulfur Pumping Pure sulfur undergoes a phase change at about 158°C [317°F] that causes a tremendous increase in its viscosity. Although dissolved H2S reduces the magnitude of the increase, and sulfur produced in Claus SRUs always contains some H2S, this temperature region must be avoided to prevent problems in handling the molten sulfur.
This is
particularly important for the sulfur in the Sulfur Storage Tank, since degassing significantly reduces the H2S content of the sulfur. Accordingly, the temperature inside the Sulfur Storage Tank and the
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SULFUR BLOCK Sulfur Loading Pump should be kept below 158°C [317°F] to avoid overloading the pump due to high liquid viscosity. Note that the tank is equipped with a local temperature indicator to allow easy monitoring of this temperature.
Maintaining the steam coil pressure in the tank at
2
5.0 kg/cm (g) or less should ensure that the sulfur does not get too hot. Note that the sulfur experiences a small temperature rise inside the Sulfur Loading Pump due to the pumping energy, so it may be necessary to maintain the tank temperature slightly lower than 158°C [317°F] so that the pumped sulfur does not get too hot.
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SULFUR BLOCK
10.7 Precommissioning Procedures Prior to the initial startup, there are a number of precommissioning activities that are necessary to ensure that the newly constructed plant is ready to be placed in service. The activities outlined below should serve as a guide, but there may be others required as a part of your normal plant procedures.
10.7.1
Preliminary Check-out A.
Check all equipment to ensure that it is properly installed. This will probably require consulting Manufacturer's literature as well as construction drawings.
B.
Check and lubricate all equipment, in accordance with the Manufacturer's recommendations.
C.
Check the rotation of the Degassing Air Blower and Sulfur Feed Pumps: (1)
Operate each Degassing Air Blower for a short period (20 seconds or less) with its discharge valve closed and its blow-off valves open.
(2)
The Sulfur Feed Pumps depend on molten sulfur to lubricate their bearings, and should not be operated dry. Remove the coupling between each pump and its motor while checking the rotation of the motor.
D.
Check the rotation of the Sulfur Loading Pump by "bumping" each pump.
E.
Check all piping and equipment to be sure that all blinds have been removed and that no valves are vented to atmosphere.
F.
Place the Instrument Air System in service to all instruments and check the action of controllers and control valves.
G.
Place the instrument air in service to the bubbler-type level transmitters on the two Sulfur Surge Tanks and the Sulfur Storage Tank.
H.
Once the heating systems have been placed in service (see Section 10.7.2), manually "stroke" each steam-jacketed liquid sulfur valve and confirm that each valve still moves freely.
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SULFUR BLOCK 10.7.2
Commissioning the Heating and Ventilation Systems The heating and ventilation systems for the two Sulfur Surge Tanks and the Sulfur Storage Tank, the heating system for the Sulfur Degassing Reactor, and the heating systems for the other system components can be placed in service at any time prior to the beginning of sulfur degassing. It is advantageous to place them in service prior to startup of an SRU so that any problems can be corrected without impacting the schedule for commissioning the Sulfur Degassing system. To place the heating and ventilation systems in service, proceed as follows: A.
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Commission the steam supply to the Sulfur Storage Tank, A2-FB1550, and place its ventilation system in service as follows: (1)
Confirm that the steam supply valves to the steam coils in the Sulfur Storage Tank are all closed, and that the steam trap stations on each of the coils are all blocked-in.
(2)
Establish steam flow into each of the coils by opening the steam supply valves to each coil.
(3)
Open the upstream block valve of the steam trap on each coil and use the bleeder on each trap to vent air (and any liquids or debris) from each coil. Close the bleeder on each trap once hot condensate begins flowing through the trap.
(4)
Open the test valve on each trap and confirm that each trap is operating properly. Then close the test valve and open the downstream block valve on each trap to place the traps in service to the condensate header.
(5)
Repeat Steps 1 through 4 to commission the heating system on the air sweep vent stack. Open the vent valves on the steam jackets long enough to vent the air from the jackets. In particular, use the vent line on the air sweep vent stack to vent the air from its steam jacket.
(6)
Make sure that the breather vents at each quadrant of the top of the Sulfur Storage Tank are unobstructed and that the air
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SULFUR BLOCK sweep vent stack has begun to draft air into the tank through the breather vents. (7)
Confirm that the block valve in the snuffing steam supply line for the Sulfur Storage Tank is closed, and that the steam trap station for the steam jackets on the snuffing steam shutdown valve and the tank nozzle is blocked-in.
(8)
Open the block valve in the snuffing steam supply line, then open the upstream block valve of the steam trap and use its bleeder to vent air (and any liquids or debris) from the piping and jackets. Close the bleeder on the trap once hot condensate begins flowing through the trap.
(9)
Open the test valve on the trap and confirm that the trap is operating properly. Then close the test valve and open the downstream block valve to place the trap in service to the condensate header.
(10) Press the local push-button to open the automated snuffing steam valve. Leave the valve open long enough to confirm that steam is blowing into the tank, then press the push-button again to close the valve. Visually confirm that the valve has closed and that steam has stopped flowing into the tank. (11) Confirm that the steam supply valves to the jacketed suction and discharge piping on the Sulfur Loading Pump are all closed, and that the steam trap stations on each pump's steam jacket and the steam-jacketed piping are all blocked in. (12) Open all of the vent valves on the steam-jacketed piping. (13) Establish steam flow into the jacketed piping and the steam jackets on each pump by opening the steam supply valves. (14) Allow air (and any liquids or debris) to purge from the vent valves. Close each vent valve as it begins to blow steam. (15) Open the upstream block valve of each steam trap on the jacketed piping and the steam jackets on each pump, and use the bleeder on each trap to drain water (and any other liquids) from the pump and piping. Close the bleeder on each trap once hot condensate begins flowing through the trap.
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SULFUR BLOCK (16) Open the test valve on each trap and confirm that each trap is operating properly. Then close the test valve and open the downstream block valve on each trap to place the traps in service to the condensate header. B.
Issued 30 August 2011
Commission the steam supply to the Train 1 Sulfur Surge Tank, A2-FB1530 and place its ventilation system in service as follows: (1)
Confirm that the steam supply valves to the steam coils in the Sulfur Surge Tank are all closed, and that the steam trap stations on each of the coils are all blocked-in.
(2)
Establish steam flow into each of the coils by opening the steam supply valves to each coil.
(3)
Open the upstream block valve of the steam trap on each coil and use the bleeder on each trap to vent air (and any liquids or debris) from each coil. Close the bleeder on each trap once hot condensate begins flowing through the trap.
(4)
Open the test valve on each trap and confirm that each trap is operating properly. Then close the test valve and open the downstream block valve on each trap to place the traps in service to the condensate header.
(5)
Repeat Steps 1 through 4 to commission the heating systems on the air sweep vent stack the Sulfur Surge Tank Vent Ejector, the ejector suction line, and the ejector discharge line. Open all of the vent valves on the steam jackets long enough to vent the air from the jackets. In particular, use the vent line on the air sweep vent stack to vent the air from its steam jacket.
(6)
Make sure that the breather vents at the top of the Sulfur Surge Tank are unobstructed and that the air sweep vent stack has begun to draft air into the tank through the breather vents.
(7)
Confirm that the ejector discharge valve is closed and the ejector suction valve is open. Confirm that the motive steam supply to the ejector is blocked-in. The ejector cannot be placed in service until a TTO is operating.
(8)
Confirm that the block valves in both of the snuffing steam supply lines for the Sulfur Surge Tank are closed, and that the
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SULFUR BLOCK steam trap stations for the steam jackets on both snuffing steam shut-down valves and the tank nozzles are blocked-in. (9)
For each snuffing steam supply line, open the block valve in the supply line, then open the upstream block valve of the steam trap and use its bleeder to vent air (and any liquids or debris) from the piping and jackets. Close the bleeder on the trap once hot condensate begins flowing through the trap.
(10) Open the test valve on each trap and confirm that the traps are operating properly. Then close the test valves and open the downstream block valves to place the traps in service to the condensate header. (11) For each snuffing steam supply line, press the local push-button to open the automated snuffing steam valve. Leave the valve open long enough to confirm that steam is blowing into the tank, then press the push-button again to close the valve. Visually confirm that the valve has closed and that steam has stopped flowing into the tank. C.
Commission the steam supply to the Train 2 Sulfur Surge Tank, A2-FB1540 and place its ventilation system in service in the same manner.
D.
Confirm that the steam supply valve(s) to the jacketed discharge piping on the Train 1 Sulfur Feed Pump, A2-GA1532A/B, are all closed, and that the steam trap stations on each pump are all blocked in.
E.
Open all of the vent valves on the jacketed discharge piping.
F.
Establish steam flow into the jacketed pipe and the pumps by opening the steam supply valve(s).
G.
Allow air (and any liquids) to purge from the vent valves. Close each vent valve as it begins to blow steam.
H.
Open the upstream block valve of the steam trap on each pump and use the bleeder on each trap to drain water (and any other liquids) from each pump. Close the bleeder on each trap once hot condensate begins flowing through the trap.
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SULFUR BLOCK I.
Open the test valve on each trap and confirm that each trap is operating properly. Then close the test valve and open the downstream block valve on each trap to place the traps in service to the LP Condensate header.
J.
Repeat Steps D through I to commission the heating systems on each of the following jacketed equipment items and piping systems. Open all of the vent valves on the steam jackets long enough to vent the air from the jackets, and work from top to bottom to use the steam pressure to empty any liquids from the heating systems. (1)
The Train 1 sulfur spill-back line, and control valve.
(2)
The Train 2 Sulfur Feed Pump, A2-GA1542A/B.
(3)
The Train 2 sulfur spill-back line, and control valve.
(4)
The bubbler tubes for all of the level transmitters in the two Sulfur Surge Tanks and the Sulfur Storage Tank.
(5)
The sulfur drain line, from the Sulfur Degassing Reactor, the strainer, and the associated Degassed Sulfur Drain Seal Assembly, A2-ME1550.
(6)
The jacket on the Sulfur Degassing Reactor, A2-DC1550.
(7)
The degassing air line feeding the Sulfur Degassing Reactor.
(8)
The spent degassing air line from the Sulfur Degassing Reactor.
Confirm that all steam traps are functioning properly before directing your attention away from these heating systems.
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SULFUR BLOCK 10.7.3
Purging the Sulfur Degassing Reactor During normal operation of the Sulfur Degassing Reactor, the spent degassing air from the overhead of the vessel is routed to the Thermal Oxidizer to incinerate the traces of H2S in the air. Before operating the system, the Sulfur Degassing Reactor must be purged to ensure that there are no combustible substances in the vessel that could cause problems in the TTO. This is accomplished by using nitrogen to purge the vessel and its associated piping.
WARNING
UNTIL THE SULFUR DEGASSING REACTOR HAS BEEN PURGED, THERE MAY BE FLAMMABLE GAS MIXTURES PRESENT IN THE VESSEL AND ITS PIPING.
ENSURE THAT ALL IGNITION
SOURCES, INTERNAL AND EXTERNAL TO THE VESSEL, HAVE BEEN REMOVED BEFORE PROCEEDING. A.
Place the Train 1 sulfur feed rate controller in the DCS in "manual" and set its output to 0%.
B.
Verify that the control valve in the associated Train 1 sulfur spill-back line is fully closed.
C.
Place Train 2 sulfur feed rate controller in the DCS in "manual" and set its output to 0%.
D.
Verify that the control valve in the Train 2 sulfur spill-back line is fully closed.
E.
Verify that the discharge valves on the Sulfur Feed Pumps for both SRU trains are closed.
F.
Close the block valve in the spent degassing air line.
G.
Open the block valve upstream of the strainer in the rundown line to the Degassed Sulfur Drain Seal Assembly.
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SULFUR BLOCK H.
Confirm that the steam-out valve on the degassing air line is closed and remove its blind flange.
I.
Use a temporary hose to connect nitrogen to the steam-out valve then open the valve to commence the flow of nitrogen into the Sulfur Degassing Reactor and out the open path through the Degassed Sulfur Drain Seal Assembly.
J.
Allow the nitrogen to continue flowing long enough to reduce the oxygen concentration in the vessel and piping to less than 1%. Use a portable oxygen analyzer to determine the oxygen concentration.
K.
When the oxygen concentration is below 1%, set the output of the Train 1 sulfur feed rate controller to 100%
L.
Verify that the control valve in the Train 1 spill-back line is fully open.
M.
"Force" the PLC to open the Train 1 Sulfur Feed Pump (A2-GA1532A/B) discharge valves.
N.
Close the block valve in the rundown line to the Degassed Sulfur Drain Seal Assembly.
O.
Allow the nitrogen to continue flowing long enough to reduce the oxygen concentration in the piping to less than 1%. Use a portable oxygen analyzer to determine the oxygen concentration.
P.
When the oxygen concentration is below 1%, open the block valve in the spent degassing air line to the Thermal Oxidizer.
Q.
Close the following valves: (1)
Adjust the output of the Train 1 sulfur feed rate controller in the DCS to 0% to close the spill-back valve.
(2)
Remove the "forces" from the PLC and confirm that the automated discharge block valves on the Train 1 Sulfur Feed Pumps close.
R.
Set the output of the Train 2 sulfur feed rate controller to 100%
S.
Verify that the control valve in the Train 2 spill-back line is fully open.
T.
"Force" the PLC to open the Train 2 Sulfur Feed Pump (A2-GA1542A/B) discharge valves.
Issued 30 August 2011
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SULFUR BLOCK U.
Close the block valve in the spent degassing air line to the Thermal Oxidizer.
V.
Allow the nitrogen to continue flowing long enough to reduce the oxygen concentration in the piping to less than 1%. Use a portable oxygen analyzer to determine the oxygen concentration.
W.
When the oxygen concentration is below 1%, open the block valve in the spent degassing air line to the Thermal Oxidizer.
X.
Close the following valves: (1)
Adjust the output of the Train 2 sulfur feed rate controller in the DCS to 0% to close the spill-back valve.
(2)
Remove the "forces" from the PLC and confirm that the automated discharge block valves on the Train 2 Sulfur Feed Pumps close.
Y.
Allow the nitrogen to continue flowing long enough to reduce the oxygen concentration in the piping to less than 1%. Use a portable oxygen analyzer to determine the oxygen concentration.
Z.
Close the steam-out valve where the nitrogen "jumper" is connected to stop the flow of nitrogen, and disconnect the nitrogen hose. Replace the blind flange on the steam-out valve.
AA. Open the block valve in the rundown line to the Degassed Sulfur Drain Seal Assembly. BB. Close the block valve in the spent degassing air line to the Thermal Oxidizer. The Sulfur Degassing System is now ready for service. Once an SRU has been started up and there has been sufficient sulfur production into a Sulfur Surge Tank to commence operation of a Sulfur Feed Pump, sulfur degassing can begin.
Issued 30 August 2011
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
10.8 Startup Procedures This section describes the procedures for the initial startup of the Sulfur Degassing Unit, subsequent startups of the Sulfur Degassing Unit, and operation of the Sulfur Loading system.
10.8.1
Initial Startup of the Sulfur Degassing Unit During the initial startup, the Sulfur Degassing Reactor is filled with liquid sulfur to seal the Degassed Sulfur Drain Seal Assembly in the degassed sulfur outlet line. Subsequent startups will probably not require this step. Once this has been accomplished, the system can be placed into operation. The following steps are based on placing the Train 1 Sulfur Feed Pump in service first. The same procedures can be used for the Train 2 Sulfur Feed Pump.
10.8.1.1
Filling the Sulfur Drain Seal in the Sulfur Outlet Line
CAUTION
THE SHAFT BEARINGS ON THE SULFUR FEED PUMPS ARE LUBRICATED BY SOME OF THE LIQUID SULFUR BEING PUMPED. TO ENSURE AN ADEQUATE SUPPLY OF SULFUR FOR
THE
BEARINGS,
THE
PUMP
MANUFACTURER
TYPICALLY RECOMMENDS MAINTAINING A MINIMUM OF 450 mm OF SULFUR LEVEL ABOVE THE PUMP SUCTION WHEN OPERATING ONE OF THESE PUMPS. CHECK THE SULFUR LEVEL IN THE SULFUR SURGE TANK(S) BEFORE STARTING UP THE SULFUR DEGASSING UNIT. DO NOT PROCEED UNTIL THE LEVEL MEASURES AT LEAST 450 MM ABOVE THE BOTTOM OF THE TANK(S).
Issued 30 August 2011
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SULFUR BLOCK
Issued 30 August 2011
A.
Place the Train 1 sulfur feed rate controller in the DCS in "manual" and set its output to 0%.
B.
Verify that the control valve in the Train 1 spill-back line is closed.
C.
Verify that the block valve in the Sulfur Degassing Reactor overhead line is closed.
D.
Verify that the block valve in the sulfur rundown line, is open.
E.
Verify that the shutdown valves in the discharge lines from the Train 1 Sulfur Feed Pumps are closed.
F.
Start a Sulfur Feed Pump, A2-GA1532A or A2-GA1532B, using its local start/stop control push-button and verify that its discharge valve is open.
G.
The Train 1 sulfur flow meter should begin to indicate that sulfur is flowing into the Sulfur Degassing Reactor.
H.
It will take the Sulfur Feed Pump about 3-5 hours to fill the Sulfur Degassing Reactor up to the top of the weir on the side of its draw pan so that sulfur begins to flow out the degassed sulfur outlet nozzle. Once it does so, it will take a few more minutes for sulfur to fill the Degassed Sulfur Drain Seal Assembly, A2-ME1550, and begin flowing into the Sulfur Storage Tank. Open the view hatch on the Sulfur Drain Seal and confirm that sulfur is now flowing into the tank.
I.
Open the block valve in the Sulfur Degassing Reactor overhead line and lock it open.
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SULFUR BLOCK 10.8.1.2
Placing the Sulfur Degassing Reactor in Operation At this point, liquid sulfur is flowing through the Sulfur Degassing Reactor at the full pumping rate. The sulfur feed rate can now be adjusted to maintain a relatively constant level in the Sulfur Surge Tank, and degassing air flow can be established to bring the system on-line.
WARNING
NEVER START A DEGASSING BLOWER UNLESS EACH OF THE FOLLOWING IS TRUE: 1.
THE SULFUR DEGASSING REACTOR IS FILLED WITH LIQUID SULFUR UP TO ITS NORMAL OPERATING LEVEL AND SULFUR IS RUNNING OUT OF THE SULFUR DRAIN SEAL.
2.
A SULFUR FEED PUMP IS RUNNING AND THE ASSOCIATED SULFUR FLOW METER INDICATES SULFUR IS FLOWING.
3.
THE UPSTREAM SRU(S) IS OPERATING SMOOTHLY IF IT(THEY) IS ON-LINE.
4.
THE THERMAL OXIDIZER IS ON-LINE AND OPERATING SMOOTHLY.
FAILURE TO OBSERVE THESE PRECAUTIONS COULD CAUSE A FIRE AND/OR EXPLOSION IN THE SULFUR DEGASSING REACTOR. A.
Issued 30 August 2011
Confirm that the setpoint of the Train 1 sulfur feed rate flow controller is tracking its current reading, then switch it to "automatic" (not "cascade"). Slowly adjust the setpoint as
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SULFUR BLOCK necessary so that the spill-back valve opens to regulate the sulfur feed rate to roughly the same value as the current sulfur production rate. Note:
1 metric ton per day = 42 kg/H
B.
Confirm that the block valve in the spent degassing air line is open.
C.
Confirm that both the Degassing Air Blower discharge valves are fully closed.
D.
Start a Degassing Air Blower: (1)
Open the valve in its blow-off line.
(2)
Start the blower push-button.
(3)
Once the blower comes up to speed, slowly "pinch" the valve in the blow-off line until the discharge pressure increases to 0.07-0.15 kg/cm2(g).
(4)
Press the "reset" push-button on the blower to open its discharge valve.
(5)
Slowly close the valve in the blow-off line.
NOTE:
using
its
local
start/stop
control
Do not allow the pressure to exceed 3.5 kg/cm2(g), as this will cause the relief valves on the blower discharge lines to open in order to relieve the excessive pressure.
Issued 30 August 2011
E.
As degassing air begins to flow into the Sulfur Degassing Reactor and aerate the sulfur inside, the discharge pressure on the Sulfur Feed Pump will begin to drop, which will change the sulfur feed rate to the reactor. Be prepared to take control of the sulfur feed rate flow controller in the DCS if necessary to stabilize the sulfur feed rate.
F.
Confirm that the degassing air flow rate indicated in the DCS is 200 Nm3/H or higher.
G.
Place the level controller for the Train 1 Sulfur Surge Tank in service as follows:
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SULFUR BLOCK
H.
(1)
Confirm that the level controller in the DCS is in "automatic".
(2)
Confirm that the remote setpoint the level controller is supplying to the sulfur feed rate controller matches the current local sulfur feed rate setpoint on the controller.
(3)
Switch the sulfur feed rate controller to "cascade" mode so that the setpoint for the sulfur feed rate will now be adjusted automatically by the level controller.
(4)
The setpoint of the level controller will be set at the last reading. Adjust the setpoint to its normal value.
Once SRU Train 2 has been started up and there is sufficient sulfur production into the Train 2 Sulfur Surge Tank, the Train 2 Sulfur Feed Pump can be placed in service as follows:
Issued 30 August 2011
(1)
Place the Train 2 sulfur feed rate controller in the DCS in "manual" and set its output to 0%.
(2)
Verify that the control valve in the Train 2 spill-back line is closed.
(3)
Verify that the shutdown valves in the discharge lines from the Train 2 Sulfur Feed Pumps are closed.
(4)
Start a Sulfur Feed Pump, A2-GA1542A or A2-GA1542B, using its local start/stop control push-button and verify that its discharge valve is open.
(5)
The Train 2 sulfur flow meter should begin to indicate that sulfur is flowing to the Sulfur Degassing Reactor.
(6)
Confirm that the setpoint of the Train 2 sulfur feed rate flow controller is tracking its current reading, then switch it to "automatic" (not "cascade"). Slowly adjust the setpoint as necessary so that the spill-back valve opens to regulate the sulfur feed rate to roughly the same value as the current sulfur production rate.
(7)
Place the level controller for the Train 2 Sulfur Surge Tank in service.
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SULFUR BLOCK I.
Issued 30 August 2011
The Sulfur Degassing Unit is now in operation. Before directing your attention away from this system make sure that: (1)
The Train 1 sulfur feed rate controller is functioning properly.
(2)
The level in the Train 1 Sulfur Surge Tank is under control.
(3)
The Train 2 sulfur feed rate controller is functioning properly.
(4)
The level in the Train 2 Sulfur Surge Tank is under control.
(5)
The degassing air flow rate is at its normal value or above.
(6)
Sulfur is draining freely from the Degassed Sulfur Drain Seal Assembly.
(7)
All steam heating systems are in service and functioning properly.
(8)
The TTO is operating smoothly.
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SULFUR BLOCK 10.8.2
Normal Startup of the Sulfur Degassing System To place the Sulfur Degassing Unit back in operation, the Sulfur Degassing Reactor must be filled with sulfur and degassing air flow established. Prior to commencing startup: 1.
Check for the completion of all maintenance work (connecting lines, removing blinds, etc.) if such work was performed.
2.
Place all steam heating systems in service. Check all steam traps for proper operation, and use the vent valves to sweep non-condensibles out of the steam spaces.
The following steps are based on placing the Train 1 Sulfur Feed Pump in service first. The same procedures can be used for the Train 2 Sulfur Feed Pump. 10.8.2.1
Filling the Sulfur Degassing Reactor
CAUTION
CHECK THE SULFUR LEVEL IN THE SULFUR SURGE TANK BEFORE STARTING UP THE SULFUR DEGASSING UNIT. DO NOT PROCEED UNTIL THE LEVEL MEASURES AT LEAST 450 mm ABOVE THE BOTTOM OF THE TANK.
Issued 30 August 2011
A.
Place the Train 1 sulfur feed rate controller in the DCS in "manual" and set its output to 0%.
B.
Verify that the control valve in the Train 1 spill-back line is closed.
C.
Verify that the block valve in the Sulfur Degassing Reactor overhead line is open.
D.
Verify that the block valve in the sulfur rundown line is open.
E.
Verify that the shutdown valves in the discharge lines from the Train 1 Sulfur Feed Pumps are closed.
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SULFUR BLOCK
Issued 30 August 2011
F.
Start a Sulfur Feed Pump, A2-GA1532A or A2-GA153/B, using its local start/stop control push-button and verify that its discharge valve is open.
G.
The Train 1 sulfur flow meter should begin to indicate that sulfur is flowing into the Sulfur Degassing Reactor.
H.
It will take the Sulfur Feed Pump about 3-5 hours to fill the Sulfur Degassing Reactor up to the top of the weir on the side of its draw pan so that sulfur begins to flow out the degassed sulfur outlet nozzle. Once it does so, it will take a few more minutes for sulfur to fill the Degassed Sulfur Drain Seal Assembly, A2-ME1550, and begin flowing into the Sulfur Storage Tank.
I.
Open the view hatch on the Degassed Sulfur Drain Seal Assembly and observe when sulfur begins to flow into the tank. When sulfur begins to flow out of the Degassed Sulfur Drain Seal Assembly, proceed to the next section to complete the startup of the Sulfur Degassing Unit.
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SULFUR BLOCK 10.8.2.2
Placing the Sulfur Degassing Reactor in Operation
WARNING
NEVER START A DEGASSING BLOWER UNLESS EACH OF THE FOLLOWING IS TRUE: 1.
THE SULFUR DEGASSING REACTOR IS FILLED WITH LIQUID SULFUR UP TO ITS NORMAL OPERATING LEVEL AND SULFUR IS RUNNING OUT OF THE SULFUR DRAIN SEAL.
2.
A SULFUR FEED PUMP IS RUNNING AND THE ASSOCIATED SULFUR FLOW METER INDICATES SULFUR IS FLOWING.
3.
THE UPSTREAM SRU(S) IS OPERATING SMOOTHLY IF IT(THEY) IS ON-LINE.
4.
THE THERMAL OXIDIZER IS ON-LINE AND OPERATING SMOOTHLY.
FAILURE TO OBSERVE THESE PRECAUTIONS COULD CAUSE A FIRE AND/OR EXPLOSION IN THE SULFUR DEGASSING REACTOR. A.
Confirm that the setpoint of the Train 1 sulfur feed rate flow controller is tracking its current reading, then switch it to "automatic" (not "cascade"). Slowly adjust the setpoint as necessary so that the spill-back valve opens to regulate the sulfur feed rate to roughly the same value as the current sulfur production rate. Note:
Issued 30 August 2011
1 metric ton per day = 42 kg/H
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SULFUR BLOCK B.
Confirm that both the Degassing Air Blower discharge valves are fully closed.
C.
Start a Degassing Air Blower: (1)
Open the valve in its blow-off line.
(2)
Start the blower push-button.
(3)
Once the blower comes up to speed, slowly "pinch" the valve in the blow-off line until the discharge pressure increases to 0.07-0.15 kg/cm2(g).
(4)
Press the "reset" push-button on the blower to open its discharge valve.
(5)
Slowly close the valve in the blow-off line.
NOTE:
using
its
local
start/stop
control
Do not allow the pressure to exceed 3.5 kg/cm2(g), as this will cause the relief valves on the blower discharge lines to open in order to relieve the excessive pressure.
Issued 30 August 2011
D.
Be prepared to take control of the sulfur feed rate flow controller in the DCS if necessary to stabilize the sulfur feed rate.
E.
Confirm that the degassing air flow rate indicated in the DCS is 200 Nm3/H or higher.
F.
Place the level controller for the Train 1 Sulfur Surge Tank in service as follows: (1)
Confirm that the level controller in the DCS is in "automatic".
(2)
Confirm that the remote setpoint the level controller is supplying to the sulfur feed rate controller matches the current local sulfur feed rate setpoint on the controller.
(3)
Switch the sulfur feed rate controller to "cascade" mode so that the setpoint for the sulfur feed rate will now be adjusted automatically by the level controller.
(4)
The setpoint of the level controller will be set at the last reading. Adjust the setpoint to its normal value. Sulfur Degassing
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SULFUR BLOCK G.
Once SRU Train 2 has been started up and there is sufficient sulfur production into the Train 2 Sulfur Surge Tank, the Train 2 Sulfur Feed Pump can be placed in service as follows:
H.
Issued 30 August 2011
(1)
Place the Train 2 sulfur feed rate controller in the DCS in "manual" and set its output to 0%.
(2)
Verify that the control valve in the Train 2 spill-back line is closed.
(3)
Verify that the shutdown valves in the discharge lines from the Train 2 Sulfur Feed Pumps are closed.
(4)
Start a Sulfur Feed Pump, A2-GA1542A or A2-GA1542B, using its local start/stop control push-button and verify that its discharge valve is open.
(5)
The Train 2 sulfur flow meter should begin to indicate that sulfur is flowing to the Sulfur Degassing Reactor.
(6)
Confirm that the setpoint of the Train 2 sulfur feed rate flow controller is tracking its current reading, then switch it to "automatic" (not "cascade"). Slowly adjust the setpoint as necessary so that the spill-back valve opens to regulate the sulfur feed rate to roughly the same value as the current sulfur production rate.
(7)
Place the level controller for the Train 2 Sulfur Surge Tank in service.
The Sulfur Degassing Unit is now in operation. Before directing your attention away from this system make sure that: (1)
The Train 1 sulfur feed rate controller is functioning properly.
(2)
The level in the Train 1 Sulfur Surge Tank is under control.
(3)
The Train 2 sulfur feed rate controller is functioning properly.
(4)
The level in the Train 2 Sulfur Surge Tank is under control.
(5)
The degassing air flow rate is at its normal value or above.
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SULFUR BLOCK
10.8.3
(6)
Sulfur is draining freely from the Degassed Sulfur Drain Seal Assembly.
(7)
All steam heating systems are in service and functioning properly.
(8)
The TTO is operating smoothly.
Initial Sulfur Loading Operation Once a level of liquid sulfur has been established in the Sulfur Storage Tank, loading of sulfur trucks can commence. A.
Confirm that the steam-jacket heating systems are operating properly on each Sulfur Loading Pump, their seals, their suction piping and valves, their discharge piping and valves, and the sulfur loading arm at each loading spot.
B.
Confirm that there is sufficient sulfur in the Sulfur Storage Tank to load a truck.
C.
Select a Sulfur Loading Pump for service by turning the selector switch to that pump.
D.
Position a truck under a sulfur loading arm, and connect the grounding cable to it.
E.
Confirm that the applicable grounding status light is illuminated on the loading control panel, then lower the loading arm into the tank hatch.
F.
Start the selected Sulfur Loading Pump by pressing the applicable start/stop push-button mounted at the sulfur loading platform.
G.
If sulfur does not begin flowing into the truck within 60 seconds, stop the Sulfur Loading Pump by pressing the start/stop push-button. The following items should be investigated to determine why sulfur is not being pumped:
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(1)
Confirm that selector switch is set to the correct Sulfur Loading Pump.
(2)
Confirm that the "stop" switch for that pump, either is in the "run" position.
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SULFUR BLOCK (3)
Confirm that the steam-jacketed heating systems, steam traps, etc. on the pumps, piping, and loading arms are functioning properly.
(4)
Confirm that there is adequate level in the tank.
Once the problem has been corrected, station an observer by the Sulfur Loading Pump, return to Step F to commence loading again, and have the observer confirm that the pump suction valve opens, the pump starts, and then the discharge valve opens. H.
Once the sulfur truck is full, stop the Sulfur Loading Pump by pressing the start/stop push-button at the loading spot.
I.
Confirm that the Sulfur Loading Pump has stopped and its suction and discharge valves are now closed.
CAUTION
ALWAYS CONFIRM THAT THE BLOCK VALVE AT THE LOADING SPOT CLOSES AFTER STOPPING THE SULFUR LOADING PUMP. THE SULFUR LOADING ARMS ARE LOWER THAN THE TOP OF THE SULFUR STORAGE TANK, SO THE TANK CAN PARTIALLY EMPTY THROUGH THE LOADING LINE, EVEN WHEN A PUMP IS NOT RUNNING, IF THE LEVEL IN THE TANK IS HIGH ENOUGH AND THE BLOCK VALVE REMAINS OPEN.
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SULFUR BLOCK 10.8.4
Normal Sulfur Loading Operation A.
Position a truck under a sulfur loading arm, and connect the grounding cable to it.
B.
Confirm that the applicable grounding status light is illuminated on the loading control panel, then lower the loading arm into the tank hatch.
C.
Commence sulfur loading by pressing the applicable start/stop push-button mounted at the sulfur loading platform.
D.
If sulfur does not begin flowing into the truck within 60 seconds, stop the Sulfur Loading Pump by pressing the start/stop push-button. Investigate the items listed above to determine why sulfur is not being pumped.
E.
Once the sulfur truck is full, stop the sulfur loading operation by pressing the start/stop push-button at the loading spot.
CAUTION ALWAYS CONFIRM THAT THE BLOCK VALVE AT THE LOADING SPOT CLOSES WHEN LOADING IS STOPPED.
THIS WILL
PREVENT THE SULFUR STORAGE TANK FROM PARTIALLY EMPTYING ITSELF DUE TO GRAVITY-FLOW THROUGH THE LOADING LINE IF THE LEVEL IN THE TANK IS HIGH.
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SULFUR BLOCK
10.9 Shutdown Procedures The procedures to be used in performing a planned shutdown of the Sulfur Degassing Unit will vary depending on the extent and type of work to be performed in and around the Sulfur Degassing Reactor during the downtime period. If there are no plans for entering the Sulfur Degassing Reactor, no special procedures are required in performing the shutdown. However, if you plan to enter any vessels for inspection or maintenance, the procedure for Planned Shutdown with Entry should be followed to accomplish a satisfactory shutdown and minimize the time required for performance of the desired maintenance work. Typical shutdown procedures are outlined and discussed in the sections that follow for the more common cases. Your existing company procedures and common sense operational judgment should be used to modify these procedures as needed to serve the purpose of any given planned shutdown situation.
10.9.1
Planned Shutdown - No Reactor Entry If there are no plans to enter the Sulfur Degassing Reactor during the shutdown, the Sulfur Degassing Reactor can remain full of liquid. This will allow placing the Sulfur Degassing Unit back on-line quicker, since there will be no delay while filling the vessel with sulfur. A.
Stop the Sulfur Feed Pump, A2-GA1532A/B using its local start/stop control push-button. Stop the Sulfur Feed Pump, A2-GA1542A/B using its local start/stop control push-button. This should activate the SDU ESD system to shut down the Degassing Air Blower.
B.
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Place the Train 1 sulfur feed rate controller in the DCS, in "manual" and set its output to 0% to close the control valve in the spill-back line.
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SULFUR BLOCK Place the Train 2 sulfur feed rate controller in the DCS, in "manual" and set its output to 0% to close the control valve in the spill-back line. This will prevent sulfur from draining out of the Sulfur Degassing Reactor. C.
D.
Visually confirm that: (1)
All Sulfur Feed Pumps are stopped, and that their discharge valves are closed.
(2)
Both Degassing Air Blowers are stopped and their discharge valves are closed.
(3)
The control valves in both spill-back lines are closed.
Confirm that all steam heating services are still functioning and the steam traps are operating properly.
The Sulfur Degassing Unit can remain in this condition indefinitely. Periodically confirm that the steam heating services are functioning properly so that solid sulfur cannot form anywhere in the system.
10.9.2
Planned Shutdown for Reactor Entry Use the following steps to shut down the Sulfur Degassing Unit for maintenance or inspection. A.
Stop the Sulfur Feed Pump, A2-GA1532A/B using its local start/stop control push-button. Stop the Sulfur Feed Pump, A2-GA1542A/B using its local start/stop control push-button. This should activate the SDU ESD system to shut down the Degassing Air Blower.
B.
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Visually confirm that: (1)
All Sulfur Feed Pumps are stopped, and that their discharge valves are closed.
(2)
Both Degassing Air Blowers are stopped and their discharge valves are closed.
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SULFUR BLOCK C.
Confirm that the block valve in the spent degassing air line is open to the TTO. This will prevent creating a vacuum in the Sulfur Degassing Reactor as the sulfur is drained back into the Sulfur Surge Tank(s).
Note:
The sulfur from the Sulfur Degassing Reactor may be drained into the surge tank for either SRU. Unless noted otherwise, the following procedure applies to both Train 1 and Train 2. D.
Place the sulfur feed rate controller in the DCS, in "manual" and set its output to 100%. This will fully open the control valve in the spill-back line and allow all of the liquid sulfur to empty from the Sulfur Degassing Reactor back into the Sulfur Surge Tank.
E.
Once the Sulfur Degassing Reactor is empty, set the output from the flow controller to 0%. Confirm that the control valve in the spill-back line is fully closed.
F.
Remove the blind flange then open the steam-out valve on the degassing air line and use LP steam to purge the gases in the Sulfur Degassing Reactor out to the TTO.
G.
Discontinue steam-out of the vessel and re-install the blind flange.
H.
Isolate the Sulfur Degassing Reactor from all potential contaminating gases using slip blinds or by disconnecting the piping. In particular, isolate the Sulfur Degassing Reactor from the TTO using slip-blinds, etc.
I.
Close the block valve in the sulfur drain line to isolate the Sulfur Degassing Reactor from the drain trap and the Sulfur Storage Tank. Once the Sulfur Degassing Reactor is isolated, it can be opened for entry. Refer to the "General Safety" section of these guidelines for procedures to be followed when performing maintenance work on this plant.
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SULFUR BLOCK 10.9.3
Shutdown for Tank Entry If the Sulfur Storage Tank is to be entered, it should be isolated, emptied, purged, and ventilated using normal procedures. This should include at least the following: A.
Close the block valves in the sulfur inlet lines to the Sulfur Storage Tank and install slip blinds at the tank flanges.
B.
Use the Sulfur Loading Pump to empty the Sulfur Storage Tank as completely as possible. Since the pump suction lines inside the tank extend to near the bottoms of recessed sumps in the tank bottom, it should be possible to remove all of the molten sulfur covering the tank floor before the pump loses suction.
C.
Briefly operate the other Sulfur Loading Pump until it loses suction to remove as much sulfur as possible from the other suction sump.
D.
Install slip blinds in the pump suction lines at the tank flanges.
E.
Close the block valves in the steam and condensate lines for the steam coils inside the tank, then de-pressure the coils.
F.
Remove the covers from the roof and shell manholes, then use fans or other means to sweep air through the tank and displace all of the tank vapors.
G.
If desired, the steam supply to the steam jacket on the air sweep vent stack can be left in service so that the stack will help ventilate the tank.
H.
Monitor the air inside the tank and continue to sweep the tank with air until no H2S is detected.
I.
Once these steps have been completed, entry into the tank following your company's policies for "confined space entry" should be possible.
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SULFUR BLOCK
WARNING
THE SULFUR STORAGE TANK ALWAYS HAS THE POTENTIAL TO CONTAIN H2S AND/OR SO2.
ALL SAFETY PRECAUTIONS
OUTLINED IN THE GENERAL SAFETY SECTION OF THIS GUIDELINES REGARDING WORKING SAFELY WHEN H2S AND/OR SO2 MAY BE PRESENT SHOULD BE FOLLOWED. MOLTEN SULFUR MAY ALSO BE PRESENT INSIDE THE TANK, INCLUDING UNDERNEATH WHAT OTHERWISE APPEARS TO BE SOLID SULFUR. MOLTEN SULFUR CAN CAUSE SEVERE BURNS, SO ALWAYS USE APPROPRIATE PERSONAL PROTECTION EQUIPMENT.
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SULFUR BLOCK
Table of Contents 11.
TAILGAS CLEANUP .............................................................................................. 11-1
11.1 PURPOSE OF SYSTEM ..................................................................................... 11-1 11.2 SAFETY ............................................................................................................... 11-2 11.3 PROCESS DESCRIPTION.................................................................................. 11-3 11.3.1 General ......................................................................................................... 11-3 11.3.2 Tailgas Hydrogenation/Hydrolysis ................................................................ 11-3 11.3.3 Process Gas Cooling .................................................................................... 11-4 11.3.4 Gas Contacting ............................................................................................. 11-5 11.3.5 Solvent Regeneration Section ...................................................................... 11-6 11.3.6 Steam Production/Consumption ................................................................... 11-7 11.4 EQUIPMENT DESCRIPTION .............................................................................. 11-8 11.4.1 TGCU Quench Column, A2-DA1560 ............................................................ 11-8 11.4.2 TGCU Quench Column Packing, A2-DB1560 .............................................. 11-8 11.4.3 TGCU Contactor, A2-DA1561 ...................................................................... 11-8 11.4.4 TGCU Contactor Packing & Internals, A2-DB1561 ...................................... 11-8 11.4.5 TGCU Stripper, A2-DA1562 ......................................................................... 11-9 11.4.6 TGCU Stripper Trays, A2-DB1562 ............................................................... 11-9 11.4.7 TGCU Reactor, A2-DC1560 ....................................................................... 11-10 11.4.8 TGCU Stripper Reflux Accumulator, A2-FA1560 ....................................... 11-10 11.4.9 Catalyst for TGCU Reactor, A2-MC1560 ................................................... 11-10 11.4.10 TGCU Stripper Reboiler Condensate Pot, A2-FA1562 ........................... 11-10 11.4.11 TGCU Reactor Feed Heater, A2-EA1560 ............................................... 11-11 11.4.12 TGCU Waste Heat Reclaimer, A2-EA1561 ............................................ 11-11 11.4.13 TGCU Quench Water Trim Cooler, A2-EA1562A/B ................................ 11-11 11.4.14 TGCU Lean/Rich Exchanger, A2-EA1564 .............................................. 11-11 11.4.15 TGCU Stripper Reboiler, A2-EA1565 ..................................................... 11-12 11.4.16 TGCU Lean Amine Trim Cooler, A2-EA1563 ......................................... 11-12 11.4.17 TGCU Quench Water Cooler, A2-EC1560 ............................................. 11-12 11.4.18 TGCU Stripper Reflux Condenser, A2-EC1562 ...................................... 11-12 11.4.19 TGCU Lean Amine Cooler, A2-EC1561 ................................................. 11-12 11.4.20 TGCU Quench Water Pump, A2-GA1560A/B......................................... 11-13 11.4.21 TGCU Rich Amine Pump, A2-GA1561A/B ............................................. 11-14 11.4.22 TGCU Stripper Reflux Pump, A2-GA1563A/B ........................................ 11-14 11.4.23 TGCU Lean Amine Pump, A2-GA1562A/B ............................................. 11-14 11.4.24 TGCU Start-Up Blower, A2-GB1560 ....................................................... 11-14 11.4.25 Refractory for TGCU Reactor, A2-MR1560 ............................................ 11-15 11.4.26 TGCU Reactor Feed Mixer, A2-ME1560 ................................................ 11-16
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SULFUR BLOCK 11.4.27 TGCU Quench Water Filter, A2-FD1560A/B .......................................... 11-16 11.4.28 TGCU Rich Amine Filter, A2-FD1562A/B ............................................... 11-16 11.4.29 TGCU Lean Amine Filter, A2-FD1563 .................................................... 11-17 11.4.30 TGCU Amine Carbon Filter, A2-FD1564 ................................................ 11-17 11.4.31 TGCU Amine After-Filter, A2-FD1565 .................................................... 11-17 11.4.32 pH Meter Sample Filter, A2-FD1561A/B ................................................. 11-17 11.5 INSTRUMENTATION AND CONTROL SYSTEMS ........................................... 11-18 11.5.1 TGCU Reactor Feed Control Loops ........................................................... 11-18 11.5.1.1 Reactor Feed Temperature Control .................................................... 11-18 11.5.1.2 Hydrogen Concentration Control ......................................................... 11-19 11.5.1.3 Controls for Startup and Shutdown ..................................................... 11-20 11.5.2 Hydrogen and Hydrogen Sulfide Analyzer, A2-AE15858/A2-AE15859 ...... 11-23 11.5.3 Boiler Low-Low Level S/D Transmitter Testing .......................................... 11-24 11.5.4 Tailgas Switching Valve Controls ............................................................... 11-26 11.5.4.1 Repositioning the Tailgas Valves Following a TGCU ESD ................. 11-26 11.5.4.2 Introducing SRU Tailgas into the TGCU — Scenario 1 ....................... 11-27 11.5.4.3 Introducing SRU Tailgas into the TGCU — Scenario 2 ....................... 11-29 11.5.5 TGCU Shutdown System ........................................................................... 11-33 11.5.5.1 Causes ................................................................................................ 11-33 11.5.5.2 Effects ................................................................................................. 11-36 11.5.5.3 Non-ESD Shutdowns .......................................................................... 11-37 11.6 PROCESS PRINCIPLES AND OPERATING TECHNIQUES ........................... 11-39 11.6.1 Equipment Damage .................................................................................... 11-39 11.6.2 Catalyst Fouling .......................................................................................... 11-40 11.6.3 TGCU Reactor Operation ........................................................................... 11-41 11.6.4 TGCU Catalyst ........................................................................................... 11-43 11.6.5 TGCU Start-Up Blower Operation .............................................................. 11-44 11.6.6 TGCU Quench Column Operation.............................................................. 11-45 11.6.7 TGCU Contactor Operation ........................................................................ 11-48 11.6.8 TGCU Stripper Operation ........................................................................... 11-52 11.6.9 TGCU Amine Water Balance...................................................................... 11-55 11.6.10 TGCU Amine Loss .................................................................................. 11-59 11.6.11 Operation at Low Flow Rates.................................................................. 11-60 11.6.12 Pressure Drop Surveys ........................................................................... 11-61 11.6.13 Boiler Water Treatment ........................................................................... 11-63 11.7 PRECOMMISSIONING PROCEDURES ........................................................... 11-64 11.7.1 Preliminary Check-out ................................................................................ 11-64 11.7.2 Shutdown System Check-out ..................................................................... 11-65 11.7.3 Commissioning Nitrogen and Utility Air to the Process .............................. 11-66 11.7.4 Commissioning Hydrogen to the Process .................................................. 11-72
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SULFUR BLOCK 11.7.5 Leak Testing the Process Piping and Equipment ....................................... 11-75 11.7.6 Washing the Quench Water System .......................................................... 11-79 11.7.6.1 Water Flush ......................................................................................... 11-79 11.7.6.2 Acid Wash ........................................................................................... 11-82 11.7.6.3 Alkaline Wash...................................................................................... 11-82 11.7.6.4 Initial Water Fill .................................................................................... 11-84 11.7.7 Washing the Amine System ....................................................................... 11-85 11.7.7.1 Water Flush ......................................................................................... 11-86 11.7.7.2 Acid Wash ........................................................................................... 11-89 11.7.7.3 Weak Amine Wash .............................................................................. 11-91 11.7.7.4 Initial Solvent Fill ................................................................................. 11-93 11.7.8 Purging the Low Pressure TGCU Columns ................................................ 11-97 11.7.8.1 Establishing Nitrogen Flow .................................................................. 11-97 11.7.8.2 Purging the TGCU Start-Up Blower .................................................... 11-99 11.7.8.3 Purging the Columns ......................................................................... 11-100 11.8 STARTUP PROCEDURES.............................................................................. 11-102 11.8.1 Initial Startup of the TGCU ....................................................................... 11-102 11.8.1.1 Initial Preparations............................................................................. 11-102 11.8.1.2 Establishing Nitrogen Flow ................................................................ 11-103 11.8.1.3 Establishing Re-circulation Flow ....................................................... 11-104 11.8.2 Pre-Sulfiding the TGCU Catalyst .............................................................. 11-107 11.8.2.1 Establishing Reducing Gas Flow....................................................... 11-108 11.8.2.2 Pre-Sulfiding the Catalyst .................................................................. 11-111 11.8.3 Routing SRU Tailgas to the TGCU ........................................................... 11-115 11.8.3.1 Introducing SRU Tailgas into the TGCU — Scenario 1 ..................... 11-116 11.8.3.2 Introducing SRU Tailgas into the TGCU — Scenario 2 ..................... 11-119 11.8.4 Quench Water and Amine Systems ......................................................... 11-122 11.8.5 Process Gas Flow to the TGCU Columns ................................................ 11-124 11.8.6 Normal Startup of the TGCU .................................................................... 11-128 11.8.6.1 Initial Preparations............................................................................. 11-128 11.8.6.2 Purging the Low Pressure TGCU Columns....................................... 11-130 11.8.6.3 Establishing Nitrogen Flow ................................................................ 11-130 11.8.6.4 Establishing Re-circulation Flow ....................................................... 11-131 11.8.6.5 Establishing Reducing Gas Flow....................................................... 11-133 11.8.6.6 Routing SRU Tailgas to the TGCU.................................................... 11-134 11.8.6.7 Quench Water and Amine Systems .................................................. 11-138 11.8.6.8 Process Gas Flow to the TGCU Columns ......................................... 11-140 11.9 SHUTDOWN PROCEDURES ......................................................................... 11-144 11.9.1 Planned Shutdown - No Reactor Entry..................................................... 11-145 11.9.2 Planned Shutdown for Reactor Entry ....................................................... 11-151
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SULFUR BLOCK 11.9.3 Shutting Down When Boiler Tubes Are Leaking ...................................... 11-158 11.9.4 Special Precaution During Shutdowns ..................................................... 11-159 11.9.5 Emergency Shutdown .............................................................................. 11-163 11.9.6 Effects of Shutdowns and Outages in Other Systems.............................. 11-164 11.9.6.1 Amine Regeneration Unit Outages.................................................... 11-164 11.9.6.2 Sour Water Stripper Outages ............................................................ 11-164 11.9.6.3 Sulfur Recovery Unit ESD System .................................................... 11-164 11.9.6.4 Thermal Oxidizer ESD System.......................................................... 11-165 11.9.6.5 Steam System Outage ...................................................................... 11-166 11.10 ANALYTICAL PROCEDURES ..................................................................... 11-167 11.10.1 General Procedures for Analyzing TGCU Solvent, ............................... 11-167 11.10.2 Determination of Amine Concentration in TGCU Solvent ..................... 11-171 11.10.3 Determination of Total Acid Gas Loading in TGCU Solvent ................. 11-173 11.10.4 Determination of H2S and CO2 Loading in TGCU Solvent .................... 11-175 11.10.5 Determination of Foaming Tendency of TGCU Solvent ........................ 11-179 11.10.6 H2S Conc. in TGCU Contactor Ovhd by the Tutweiler Method ............. 11-181 11.10.7 H2S Conc. in TGCU Contactor Ovhd Using Gas Detector Tubes ......... 11-182 11.10.7.1 Operating Principles.......................................................................... 11-182 11.10.7.2 Sampling the TGCU Contactor Overhead Gas ................................. 11-183 11.10.7.3 Calculations ...................................................................................... 11-184 11.10.8 Monitoring the Performance Level of TGCU Catalyst ........................... 11-185
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SULFUR BLOCK
11.
TAILGAS CLEANUP 11.1 Purpose of System The purpose of the Tailgas Cleanup system is to remove objectionable components from the sulfur plant tailgas, thereby allowing the treated effluent to be incinerated and safely discharged to the atmosphere. The Shell Claus Off-gas Treating (SCOT) process licensed by Shell Global Solutions (US) Inc. processes the tailgas from the SRU, converting sulfur compounds present in the tailgas back into H2S. The H2S is then absorbed in a selective solvent, stripped from the solvent, and recycled back to the SRU, allowing an overall sulfur recovery in excess of 99.9%. Treated vent gas from the Tailgas Cleanup Unit (TGCU) is routed to the Tailgas Thermal Oxidation system and afterwards dispersed to the atmosphere. Due to the sulfur removal by the TGCU process, the incinerated effluent gas will normally contain less than 200 PPMV of SO2 on a dry, 0% oxygen basis.
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SULFUR BLOCK
11.2 Safety
WARNING
ALL PIPING AND VESSELS INCLUDED IN THIS UNIT EITHER CONTAIN OR HAVE THE POTENTIAL FOR CONTAINING HAZARDOUS GASES THAT MAY CAUSE SERIOUS INJURY OR DEATH. THE TWO GASES THAT ARE MOST COMMON AND HAZARDOUS IN A TOXIC WAY ARE HYDROGEN SULFIDE AND SULFUR DIOXIDE. CLOSE ATTENTION SHOULD BE PAID TO THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES AS TO THE NATURE AND ABILITY OF THESE GASES TO CONTAMINATE OTHER ELEMENTS IN THIS UNIT. AN EMPLOYEE'S KNOWLEDGE OF THE HAZARDOUS CHEMICALS AND COMPOUNDS WITH WHICH HE WILL BE WORKING IS ONE OF THE MOST BASIC PREREQUISITES FOR HIS OWN SAFETY, THE SAFETY OF OTHERS, AND THE PROTECTION OF EQUIPMENT. ALL EMPLOYEES SHOULD REVIEW THE "GENERAL SAFETY" SECTION OCCASIONALLY TO REFRESH THEIR MEMORIES. NEW EMPLOYEES SHOULD STUDY IT UNTIL THE INFORMATION IS THOROUGHLY UNDERSTOOD. PEOPLE WHO HAVE NOT BEEN PROPERLY TRAINED SHOULD NOT BE ALLOWED TO OPERATE OR WORK IN AND AROUND THIS PLANT.
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11.3 Process Description 11.3.1
General The Systems Diagram, Material Balance and Process Flow Diagrams, Dwg. Nos. 507000-7000-01, and 507000-7000-10 through -12, are contained in the "Process Flow Diagrams" Section of the Basic Engineering Package. Please refer to these drawings to follow this description of the process. The Tailgas Cleanup Unit (TGCU) receives tailgas from the two Sulfur Recovery Units and uses the Shell Claus Off-gas Treating (SCOT) process licensed by Shell Global Solutions (US) Inc. for sulfur removal. The TGCU Unit has been designed to process the 7,655 Nm3/H of sulfur plant tailgas that results when each SRU receives a total fresh acid gas feed containing 34.6 MT/D of sulfur. The TGCU process reduces all of the sulfur compounds in the sulfur plant tailgas to H2S, then uses selective amine absorption to recover H2S from the tailgas while allowing most of the CO2 to "slip" by. The H2S and CO2 removed by the amine are stripped from the amine and recycled to the two SRUs, allowing an overall sulfur recovery in excess of 99.9 wt. %. Less than 220 PPMV of sulfur (wet basis, expressed as H2S) remains in the treated effluent flowing to the Tailgas Thermal Oxidation Unit. This sulfur content is low enough to keep the SO2 content of the incinerated effluent below 200 PPMV (on a dry, 0% oxygen basis) when the H2S and sulfur in the spent degassing air from the Sulfur Degassing Unit and the sweep air from the Sulfur Surge Tanks are included, due to the dilution effect of the thermal incineration process.
11.3.2
Tailgas Hydrogenation/Hydrolysis The tailgas stream from the fourth pass of the Sulfur Condenser in each SRU is combined and heated using HP steam in the TGCU Reactor Feed Heater, A2-EA1560. The heated gas is then mixed with hydrogen-rich reducing gas by the TGCU Reactor Feed Mixer, A2-ME1560, (a static mixer) before the mixture flows to the TGCU Reactor, A2-DC1560, at 240°C [464°F]. As the gas flows through the bed of Criterion 234 cobalt-molybdenum catalyst, the reducing atmosphere hydrogenates or hydrolyzes most of the sulfur compounds to H2S: (1)
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SO2 + 3 H2
H2S + 2 H2O
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SULFUR BLOCK (2)
S + H2
H2S
(3)
COS + H2O
H2S + CO2
(4)
CS2 + 2 H2O
2 H2S + CO2
Carbon monoxide in the tailgas also reacts with the water vapor in the gas to form hydrogen, the classic "water gas shift" reaction: (5)
CO + H2O
H2 + CO2
These reactions are all exothermic, causing the gas temperature to increase to 291°C [556°F] at the outlet of the TGCU Reactor.
11.3.3
Process Gas Cooling Before the amine solvent can be used to remove the H2S from the process gas, the gas must be cooled to an acceptable contact temperature. The first stage of cooling occurs in the TGCU Waste Heat Reclaimer, A2-EA1561, where the effluent from the TGCU Reactor is cooled to 166°C [331°F] by generating LP steam. During the course of starting up the TGCU, the equipment must be brought up to operating temperature before the sulfur plant tailgas is introduced. The TGCU Start-Up Blower, A2-GB1560, accomplishes this by re-circulating gas from the outlet of the TGCU Waste Heat Reclaimer back to the TGCU Reactor Feed Heater. This gas is circulated through the system and heated with the TGCU Reactor Feed Heater until the sulfur plant tailgas is ready to be routed to the TGCU, at which time the TGCU Start-Up Blower can be shut down. The partially cooled gas from the TGCU Waste Heat Reclaimer enters the bottom of the TGCU Quench Column, A2-DA1560, for the second stage of cooling. As the gas passes upward through the packed bed in this tower, it is further cooled by direct contact with a circulating stream of quench water. As the gas is cooled, most of the water vapor produced by the upstream reactions (Claus, combustion, and hydrogenation) is condensed and removed from the gas stream. In addition to cooling the gas, direct contact with the quench water serves to absorb trace quantities of SO2 that may "break through" the TGCU Reactor periodically. Since SO2 will react with amines to form heat-stable salts, the "washing" action of the quench water helps minimize degradation of the MDEA solvent.
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SULFUR BLOCK The cooled gas stream leaves the top of the TGCU Quench Column at 39°C [102°F] and flows to the TGCU Contactor, A2-DA1561, while the quench water exits the bottom of the tower at 67°C [153°F]. The TGCU Quench Water Pump, A2-GA1560A/B, circulates the water stream to the TGCU Quench Water Cooler, A2-EC1560, and the TGCU Quench Water Trim Cooler, A2-EA1562A/B, to reject the heat removed in the TGCU Quench Column. This cools the quench water to 38°C [104°F] before it is returned to the top of the tower. A sidestream of the quench water flows through the TGCU Quench Water Filter, A2-FD1560A/B, to remove solids from the quench water system. A portion of the filtrate is routed to the Sour Water Stripping Unit to balance the water condensed from the gas in the TGCU Quench Column, on level control from the tower. The remainder of the filtrate returns to the suction of the circulating pump.
11.3.4
Gas Contacting The cooled gas from the TGCU Quench Column enters the bottom of the TGCU Contactor at 39°C [102°F] and 0.06 kg/cm2(g) [0.9 PSIG]. As the gas flows upward through the packed bed in this tower, it is contacted with an aqueous solution of methyldiethanolamine, MDEA. The MDEA solvent (45 wt% MDEA) absorbs the H2S in the gas stream to reduce the total sulfur content below 220 PPMV on a wet basis while allowing the majority of the CO2 to "slip" overhead. The treated gas exits the top of the TGCU Contactor at 39°C [102°F] and flows to the Tailgas Thermal Oxidation Unit. The reactions between the acidic gases and the basic amine solution can be represented by: (6) H2S + CH3(CH2OHCH2)2N
CH3(CH2OHCH2)2NH+ + HS–
(7) CO2 + CH3(CH2OHCH2)2N + H2O
CH3(CH2OHCH2)2NH+ + HCO3–
The selectivity of the solvent for H2S over CO2 is important since the absorbed gases are recycled to the SRUs. Minimizing CO2 pickup reduces the amount of gas recycling to the sulfur plants, and allows the equipment in the Sulfur Recovery and Tailgas Cleanup Units to be smaller. The selectivity of tertiary amines like MDEA for H2S is a result of the indirect reaction that must occur between the amine and CO2. Unlike
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SULFUR BLOCK primary amines (such as MEA) and secondary amines (such as DEA), tertiary amines do not react directly with CO2. Instead, the CO2 must first be ionized into a bicarbonate ion (a slow reaction) before it will react with the amine. Since MDEA reacts directly (and quickly) with H2S, proper selection of the contact time between the amine and the process gas allows preferential removal of the H2S. The selectivity of MDEA for H2S over CO2 is enhanced by lower contact temperatures, hence the use of the trim cooler to reduce the solvent temperature before it enters the TGCU Contactor. The rich amine leaves the bottom of the tower at 42°C [108°F] and is pumped by the TGCU Rich Amine Pump, A2-GA1561A/B, through the TGCU Rich Amine Filter, A2-FD1562A/B, to remove accumulated solids. The rich amine then flows on level control through the tube side of the TGCU Lean/Rich Exchanger, A2-EA1564A/B/C, and is preheated to 105°C [221°F] by cooling the lean amine before flowing to the TGCU Stripper, A2-DA1562, entering between trays #4 and #5.
11.3.5
Solvent Regeneration Section The TGCU Stripper contains 28 valve trays (4 wash water trays, 24 stripping trays) and one chimney draw tray. As the solvent flows down the column, the absorbed H2S and CO2 are stripped from the MDEA by countercurrent contact with stripping steam rising upward. This stripping steam is generated in the TGCU Stripper Reboiler, A2-EA1565, using LP steam as the heat input. The heat input to the reboiler is adjusted by flow control of the steam. The steam flow controller can optionally be reset by the TGCU Stripper overhead temperature, which will maintain the desired overhead temperature of 118°C [244°F] by varying the heat input in proportion to the amount of acid gas contained in the rich amine. The stripping steam supplies the heat of reaction required to reverse reactions (6) and (7), and carries the H2S and CO2 stripped from the solvent overhead to the TGCU Stripper Reflux Condenser, A2-EC1562, where the steam is condensed as the stream is cooled to 49°C [120°F]. The condensed water is removed by the TGCU Stripper Reflux Accumulator, A2-FA1560, and returned as reflux to the wash water trays in the tower by the TGCU Stripper Reflux Pump, A2-GA1563A/B. The acid gas (H2S and CO2, along with the uncondensed water) stripped from the solvent exits the reflux drum at 0.85 kg/cm2(g) [12.1 PSIG] and flows to the two Sulfur Recovery Units.
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SULFUR BLOCK The TGCU Lean amine Pump, A2-GA1562A/B, pumps the regenerated lean MDEA solvent from the bottom of the TGCU Stripper through the shell side of the TGCU Lean/Rich Exchanger, cooling the lean amine from 127°C [261°F] to 66°C [152°F] by countercurrent heat exchange with the cool rich amine. A slipstream of the lean amine then flows through the TGCU Lean Amine Filter, A2-FD1563, to remove accumulated solids from the solvent and through the TGCU Amine Carbon Filter, A2-FD1564, where the activated carbon adsorbs contaminants such as degradation products from solvent. The TGCU Amine After-Filter, A2-FD1565, catches any carbon "fines" before the filtered slipstream rejoins the main solvent stream and flows to the TGCU Lean Amine Cooler, A2-EC1561, and the TGCU Lean Amine Trim Cooler, A2-EA1563A/B, which cool the solvent to 38°C [100°F] before it returns to the top of the TGCU Contactor on flow control.
11.3.6
Steam Production/Consumption The TGCU consumes steam at two pressure levels, and produces steam at one pressure level. Saturated HP steam from the SRUs is used to heat the TGCU Reactor feed stream, and LP steam is used to reboil solvent in the TGCU Stripper Reboiler. LP steam is produced in the TGCU Waste Heat Reclaimer, supplying a portion of the steam consumed in reboiling the TGCU solvent.
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SULFUR BLOCK
11.4 Equipment Description 11.4.1
TGCU Quench Column, A2-DA1560 The TGCU Quench Column contains a single bed of random packing to provide good contact between the hot process gas and the quench water that is to cool it. The tower has a 304 S.S. woven wire mist eliminator above the packed bed to remove entrained water droplets from the gas before it leaves the tower.
11.4.2
TGCU Quench Column Packing, A2-DB1560 This bed of random packing provides good contact between hot process gas entering below it and quench water fed above it inside the TGCU Quench Column. The packing has a bed limiter above it and rests on a bed support. The quench water is distributed over the packing by a distributor tray. The packing is 304 S.S.; the other internals are 304 S.S. Gaskets are installed where the bed support and distributor tray bolt to the support ring and clips inside the TGCU Quench Column to prevent direct contact between the stainless steel internals and the carbon steel vessel. This electrically isolates the dissimilar metals from each other to prevent direct contact that could lead to galvanic corrosion.
11.4.3
TGCU Contactor, A2-DA1561 The TGCU Contactor contains a single bed of random packing to provide good contact between the process gas and the TGCU solvent to remove H2S from the process gas. The tower has a 304 S.S. woven wire mist eliminator above the top bed to remove entrained solvent droplets from the gas before it leaves the tower.
11.4.4
TGCU Contactor Packing & Internals, A2-DB1561 This random packing bed provides good contact between process gas entering below it and TGCU lean amine fed above it inside the TGCU Contactor. The packing has a bed limiter above it and rests on a bed support. The lean amine is distributed over the packing by a distributor tray. The packing elements are 304 S.S.; the other internals are 304 S.S. Gaskets are installed where the bed support and distributor tray bolt to the support ring and clips inside the TGCU Quench Column to prevent direct contact between the stainless steel internals and the carbon steel vessel.
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SULFUR BLOCK This electrically isolates the dissimilar metals from each other to prevent direct contact that could lead to galvanic corrosion.
11.4.5
TGCU Stripper, A2-DA1562 The TGCU Stripper contains 28 valve trays to provide good contact between the rich TGCU solvent and the reboiler vapors to strip H2S and CO2 from the solvent. The rich amine enters on the fifth tray from the top; the four trays above that are "water wash" trays that allow the reflux water (entering on the top tray) to remove traces of MDEA from the overhead vapor and minimize solvent losses. A chimney tray is located below the bottom valve tray to gather all of the column liquids to feed the TGCU Stripper Reboiler. The column section located below this chimney tray serves to separate the outlet steam and lean amine from the reboiler and to provide surge for the solvent circulating system.
11.4.6
TGCU Stripper Trays, A2-DB1562 These 1-pass valve trays provide good contact between the rich TGCU solvent fed above them and the reboiler vapors fed below them inside the TGCU Stripper. The trays are designed per Shell's requirements. The tray decks are 304 S.S., and the valves are fabricated from 304 S.S. to resist corrosion and to prevent "sticking" to the tray decks. The chimney tray deck is 304 S.S. The bottom valve tray has a seal pan for its downcomer to maintain a liquid seal and prevent gas from blowing up the downcomer. The chimney tray gathers the tower liquids to feed the reboiler. The outlet from the reboiler reenters the column below the chimney tray, with the vapor produced by the reboiler flowing upward through the chimneys in order to reach the valve trays above. The top four trays in the column are located above the rich amine feed point and serve as water-wash trays to minimize the amount of amine carried-over in the tower overhead. Since these trays have only the reflux water flowing over them, the liquid rates for these trays are much lower than for the trays lower in the column. For this reason, these four trays are designed for minimum leakage (i.e., picket fence weirs, minimum downcomer clearance, etc.).
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SULFUR BLOCK 11.4.7
TGCU Reactor, A2-DC1560 The TGCU Reactor is of the down-flow type, with the feed gas entering the top of the vessel and proceeding vertically downward through the catalyst bed. A perforated baffle is installed below the inlet nozzle to distribute the gas over the length of the vessel and prevent the inlet gas stream from impinging directly on the catalyst bed. A catalyst support grating is installed in the vessel to support the catalyst bed in the center of the vessel. The support grating is covered with a stainless steel screen to prevent the catalyst from sifting through the grating. A small bead of castable refractory is used to seal the edges of the support grating to prevent catalyst leaks between the grating and the vessel shell.
11.4.8
TGCU Stripper Reflux Accumulator, A2-FA1560 This vertical pressure vessel removes condensed water from the stream leaving the TGCU Stripper Reflux Condenser so that the water can be used as reflux for the TGCU Stripper. The vessel has a 304 S.S. woven wire mist eliminator in the top to remove entrained liquid droplets from the gas before it leaves the vessel.
11.4.9
Catalyst for TGCU Reactor, A2-MC1560 Refer to the Basic Engineering Package for the type of catalyst used in the TGCU Reactor.
11.4.10 TGCU Stripper Reboiler Condensate Pot, A2-FA1562 This vertical pressure vessel collects the condensate from the TGCU Stripper Reboiler and returns it to the condensate system on level control. This method of removing condensate from the exchanger provides much smoother control of the heat input to the reboiler than a conventional steam trap could. As stated above, this vessel is simply a very good steam trap. During normal operation, the steam pressure required to provide the necessary reboil heat to the TGCU Stripper may be much less than the 3.5-4.2 kg/cm2(g) steam pressure available in the LP steam system. The normal steam pressure in the shell of the reboiler may be such that the water level in the condensate pot will rise upwards from the pot, perhaps even within the shell of the reboiler. During these periods, the level valve will remain fully open and the sight glass will indicate a full water level.
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SULFUR BLOCK This is a normal operating condition for this vessel. The vessel will usually operate with a visible level only when the TGCU Stripper Reboiler is operating near its maximum capacity with full steam pressure on the shell of the exchanger. Under these conditions, the level control and level valve will function normally and maintain a water level in the vessel.
11.4.11 TGCU Reactor Feed Heater, A2-EA1560 This shell and tube exchanger uses HP steam to heat the tailgas stream from the fourth pass of the two Sulfur Condensers up to reaction initiation temperature before it is mixed with hydrogen-rich reducing gas and flows to the TGCU Reactor.
11.4.12 TGCU Waste Heat Reclaimer, A2-EA1561 The TGCU Waste Heat Reclaimer is a fixed tubesheet shell and tube heat exchanger. The tubes are immersed in the water-filled section of the shell, allowing the boiling water in the shell of the exchanger to cool the hot gas leaving the TGCU Reactor catalyst bed by producing LP steam. There is no pressure control on the shell side of the boiler; it simply "floats" on the LP steam header pressure. The boiler is equipped with level transmittersthat will shut down the TGCU should the water level fall to within 75 mm of the top row of tubes. Operation of the boiler without a sufficient water level could possibly damage the tubes.
11.4.13 TGCU Quench Water Trim Cooler, A2-EA1562A/B This shell and tube exchanger is used to provide the final cooling of the quench water, with cooling water from the complex as the cooling medium.
11.4.14 TGCU Lean/Rich Exchanger, A2-EA1564 This shell and tube exchanger conserves energy by providing heat exchange between the rich amine and the lean amine, so that the hot lean amine leaving the TGCU Stripper can preheat the rich amine before it feeds the TGCU Stripper. This cross exchange saves reboiler duty by preheating the rich amine, and reduces the load on the TGCU Lean amine Cooler by partially cooling the hot lean amine.
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SULFUR BLOCK 11.4.15 TGCU Stripper Reboiler, A2-EA1565 The TGCU Stripper Reboiler is a fixed tubesheet shell and tube heat exchanger. The exchanger is arranged as a once-through vertical thermosiphon reboiler, mounted on the side of the TGCU Stripper. The static head of the solvent above the inlet nozzle on the lower channel provides the driving force to circulate the solvent through the tubes. LP steam on the shell of the exchanger heats the solvent inside the tubes, partially vaporizing it to create stripping steam to remove the H2S and the CO2 from the solvent flowing down the TGCU Stripper.
11.4.16 TGCU Lean Amine Trim Cooler, A2-EA1563 This shell and tube exchanger is used to provide the final cooling to the TGCU solvent returning from the regeneration section of the process, with cooling water from the complex as the cooling medium. Since the selectivity of MDEA for absorbing H2S in the presence of CO2 is better at lower temperatures, the use of cooling water is very beneficial to the process and results in reducing the emission of SO2 from the TTO.
11.4.17 TGCU Quench Water Cooler, A2-EC1560 This forced-draft aerial exchanger is used to reject some of the heat from cooling the process gas stream in the TGCU Quench Column by cooling the circulating quench water stream. Fans are used to circulate air across the finned tubes to remove heat from the quench water.
11.4.18 TGCU Stripper Reflux Condenser, A2-EC1562 This forced-draft aerial exchanger provides cooling to condense the majority of the water from the acid gas stream leaving the overhead of the TGCU Stripper. Fans are used to circulate air across the finned tubes to remove heat from the overhead stream and condense the water to be used as reflux for the tower.
11.4.19 TGCU Lean Amine Cooler, A2-EC1561 This forced-draft aerial exchanger provides some of the final cooling of the lean amine stream returning from the regeneration section of the TGCU process. Fans are used to circulate air across the finned tubes to remove heat from the solvent.
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SULFUR BLOCK
CAUTION SINCE THE PUMPS DESCRIBED IN THE FOLLOWING SECTIONS ARE CONSTRUCTED OF STAINLESS STEEL, DO NOT HYDROTEST THE ASSOCIATED VESSELS OR PIPING WITH WATER CONTAINING HIGH LEVELS OF CHLORIDES. AVOID ALLOWING WATER CONTAINING MORE THAN 50 PPM CHLORIDES TO COME IN CONTACT WITH THESE PUMPS TO PREVENT STRESS CORROSION CRACKING OF THE STAINLESS STEEL.
WARNING THE LIQUID IN THESE PUMPS CONTAINS DISSOLVED H2S. THIS H2S CAN BE RELEASED TO THE SURROUNDINGS WHEN LIQUID IS DRAINED FROM THESE PUMPS OR FROM THE PIPING CONNECTED TO THE PUMPS. ALWAYS OBSERVE PROPER PROCEDURES AND PRECAUTIONS WHEN DRAINING LIQUID FROM THESE PUMPS OR PERFORMING MAINTENANCE ON THEM. THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES SHOULD BE CONSULTED IF THERE IS ANY DOUBT ABOUT HOW TO WORK SAFELY WHEN H2S MAY BE PRESENT.
11.4.20 TGCU Quench Water Pump, A2-GA1560A/B These centrifugal pumps are used to circulate quench water to cool the process gas in the TGCU Quench Column. Each pump is designed for the total duty; the other pump is a 100% spare. These pumps are equipped with tandem seals to reduce the likelihood of releasing H2S to the surroundings.
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SULFUR BLOCK 11.4.21 TGCU Rich Amine Pump, A2-GA1561A/B These centrifugal pumps are used to send the rich amine from the TGCU Contactor to the TGCU Stripper. Each pump is designed for the total duty; the other pump is a 100% spare. These pumps are equipped with tandem seals to reduce the likelihood of releasing H2S to the surroundings.
11.4.22 TGCU Stripper Reflux Pump, A2-GA1563A/B These centrifugal pumps are used to send the reflux from the TGCU Stripper Reflux Accumulator to the TGCU Stripper. Each pump is designed for the total duty; the other pump is a 100% spare. These pumps are equipped with tandem seals to reduce the likelihood of releasing H2S to the surroundings.
11.4.23 TGCU Lean Amine Pump, A2-GA1562A/B These centrifugal pumps are used to send the lean amine from the TGCU Stripper to the TGCU Contactor. Each pump is designed for the total duty; the other pump is a 100% spare. These pumps are equipped with tandem seals to reduce the likelihood of releasing H2S to the surroundings.
11.4.24 TGCU Start-Up Blower, A2-GB1560 The TGCU Start-Up Blower is a single-stage fan, used process gas within the TGCU Unit. Flexible connectors are the fan from the suction and discharge piping to allow freedom for the expansion and movement that occurs operation.
to re-circulate used to isolate the necessary during normal
The shaft seal is made gas-tight by using a gas-lubricated non-contacting dual cartridge seal, so that process gas cannot escape to the surroundings. The nitrogen seal purge should be kept in service at all times, whether the blower is operating or not, to prevent leakage of process gas. The blower casing and impeller are constructed of carbon steel and coated with "Heresite", a baked phenolic coating, for corrosion resistance.
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SULFUR BLOCK
WARNING THIS BLOWER HANDLES GASES CONTAINING H2S, SO2, AND OTHER HARMFUL GASES. ALWAYS OBSERVE PROPER PROCEDURES AND PRECAUTIONS WHEN PERFORMING MAINTENANCE ON THIS BLOWER. THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES SHOULD BE CONSULTED IF THERE IS ANY DOUBT ABOUT HOW TO WORK SAFELY WHEN H2S AND/OR SO2 MAY BE PRESENT.
CAUTION
WHEN THIS BLOWER IS NOT OPERATING, WATER CAN CONDENSE FROM THE PROCESS GAS AND CAUSE CORROSION DAMAGE TO THE BLOWER. TO PREVENT THIS, THE BLOWER IS AUTOMATICALLY ISOLATED FROM THE PROCESS BY CLOSING ITS SUCTION AND DISCHARGE BLOCK VALVES WHEN IT STOPS, THEN PURGING THE BLOWER CASING WITH NITROGEN. THE NITROGEN PURGE SHOULD BE CHECKED PERIODICALLY TO CONFIRM THAT IT IS OPERATING PROPERLY.
11.4.25 Refractory for TGCU Reactor, A2-MR1560 A 50 mm bead of castable refractory is installed around the edges of the catalyst bed support inside the TGCU Reactor. This seals the edges of the bed support so that the small catalyst pellets cannot escape from the bed.
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SULFUR BLOCK 11.4.26 TGCU Reactor Feed Mixer, A2-ME1560 This static mixer is designed to thoroughly mix the tailgas leaving the TGCU Reactor Feed Heater and the hydrogen-rich reducing gas before the combined stream enters the TGCU Reactor.
11.4.27 TGCU Quench Water Filter, A2-FD1560A/B This filter is designed to remove solid particles 5 microns and larger from a slipstream of the circulating quench water. If SO2 enters the TGCU Quench Column and reacts with H2S to form small particles of colloidal sulfur, the filter will also help remove them.
WARNING A COMMON CONTAMINANT REMOVED BY THIS FILTER IS IRON SULFIDE, WHICH IS PYROPHORIC AT AMBIENT TEMPERATURE. IF THE FILTER ELEMENTS CONTAIN SUFFICIENT IRON SULFIDE, THE ELEMENTS MAY SPONTANEOUSLY IGNITE ONCE THE ELEMENTS DRY. ACCORDINGLY, EXERCISE PROPER CARE WHEN HANDLING AND DISPOSING OF USED FILTER ELEMENTS.
11.4.28 TGCU Rich Amine Filter, A2-FD1562A/B This full-flow filter is designed to remove solid particles 5 microns and larger from the circulating rich TGCU solvent, which will help prevent fouling of the downstream heat exchangers.
WARNING THIS FILTER HANDLES LIQUID CONTAINING H2S AND OTHER HARMFUL SUBSTANCES. ALWAYS OBSERVE PROPER PROCEDURES AND PRECAUTIONS WHEN PERFORMING MAINTENANCE ON THIS FILTER. THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES SHOULD BE CONSULTED IF THERE IS ANY DOUBT ABOUT HOW TO WORK SAFELY WHEN H2S MAY BE PRESENT.
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SULFUR BLOCK 11.4.29 TGCU Lean Amine Filter, A2-FD1563 This filter is designed to remove solid particles 5 microns and larger from a slipstream of the circulating lean TGCU solvent.
11.4.30 TGCU Amine Carbon Filter, A2-FD1564 This filter is designed to remove organic contaminants (trace hydrocarbons, degradation products, etc.) from a slipstream of the circulating lean TGCU solvent using a bed of activated carbon.
11.4.31 TGCU Amine After-Filter, A2-FD1565 This filter is designed to remove solid particles, particularly carbon fines, 5 microns and larger from the lean TGCU solvent leaving the TGCU Amine Carbon Filter.
11.4.32 pH Meter Sample Filter, A2-FD1561A/B These filters are designed to remove solid particles 5 microns and larger from the small stream of quench water flowing to the pH analyzer probe. There are two 100% filters so that one filter can remain in service while the other filter is being cleaned.
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SULFUR BLOCK
11.5 Instrumentation and Control Systems 11.5.1
TGCU Reactor Feed Control Loops The TGCU Reactor Feed Heater, A2-EA1560, and TGCU Reactor Feed Mixer, A2-ME1560, condition the combined tailgas from the SRUs before it enters the TGCU Reactor, A2-DC1560, by heating the tailgas and mixing it with reducing gas (hydrogen). Saturated HP steam produced in the SRUs is used to heat the tailgas to the desired reaction temperature (~240°C [~464°F]). External reducing gas is then mixed with the tailgas to supply some of the hydrogen needed to convert all of the sulfur compounds to H2S in the reactor. Thus, here are two important control parameters: the reactor feed temperature and the hydrogen concentration in the reactor feed. The loop diagram on page 11-22 illustrates the components of these control loops when implemented in a distributed control system (DCS). There are also controls for handling specific requirements during startup and shutdown of the front-end of the TGCU. These control loops are shown on the loop diagram as well. All of the control loops are discussed in the sections that follow.
11.5.1.1
Reactor Feed Temperature Control The feed to the TGCU Reactor is the gas leaving the TGCU Reactor Feed Mixer. The temperature of this stream depends on the amount of heating that takes places as the combined tailgas stream flows through the TGCU Reactor Feed Heater. A2-TIC15820 on the mixer outlet raises or lowers the setpoint of the steam pressure controller, A2-PIC15820, to control this temperature by adjusting the steam pressure inside the shell of the exchanger. To raise the reactor feed temperature, A2-TIC15820 increases the steam pressure by increasing the setpoint of A2-PIC15820. This will cause A2-PIC15820 to open steam control valve A2-PV15820 more, which results in two effects. First, as the valve opens more, the pressure drop is reduced across the valve, increasing the steam pressure inside the shell of the exchanger. This in turn increases the saturation temperature of the steam inside the shell, increasing the temperature driving force and thus raising the heat input to the process gas in the tubes. Second, as the valve opens more, the steam flow rate increases, supplying more heat to the exchanger to
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SULFUR BLOCK match the increase in the heat input. The net result is to increase the heat transfer, raising the feed temperature accordingly. Conversely, A2-TIC15820 lowers the reactor feed temperature by reducing the setpoint of A2-PIC15820 so that it closes A2-PV15820 more. This drops the steam pressure inside the shell to reduce the heat input, and reduces the steam flow to match. This reduces the heat transfer, thus lowering the feed temperature. 11.5.1.2
Hydrogen Concentration Control To ensure complete conversion of the sulfur compounds in the TGCU Reactor, it is necessary to maintain an excess of hydrogen in the gas leaving the reactor. The hydrogen concentration is measured by the hydrogen analyzer, A2-AE15858, and supplied to A2-AIC15816 in the DCS. The output from A2-AIC15816 is limited from high and low extremes by A2-AY15816 (to protect the process from analyzer malfunctions), and adjusts the flow rate of external reducing gas being supplied to the TGCU Reactor Feed Mixer via adjustment of the remote setpoint on the reducing gas flow controller, A2-FIC15816. A2-AY15816 restricts the remote setpoint supplied to A2-FIC15816 between 10% and 100% of the maximum range of the reducing gas flow meter, 51.3 Nm3/H and 513.0 Nm3/H, respectively. The normal sample point for hydrogen analyzer A2-AE15858 is the treated gas leaving the overhead of the TGCU Contactor, A2-DA1561, because this stream is the "cleanest" due to the H2S removal accomplished in the tower. During startup of the TGCU, however, there is no process gas flowing through the TGCU Contactor until after operation of the TGCU Reactor has been "lined out" and the process gas flow is directed into the TGCU Quench Column and the TGCU Contactor. Until then, there is no gas flowing in the TGCU Contactor overhead line, so an alternate sample point is provided on the outlet of the TGCU Waste Heat Reclaimer, A2-EA1561, to allow the analyzer to sample the gas leaving the TGCU Reactor. The 4-way selector valve, A2-HV15858, provided with the analyzer allows the operators to switch between the two sample points. LP purge gas is also connected to this valve, so that when one sample point is supplying process gas to the analyzer, the other sample point
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SULFUR BLOCK is being back-purged with inert gas. This minimizes the possibility of having one of the sample points plug when it is not in use. The process gas that is being sampled is saturated with water, so the data sheet for the analyzer system specifies that the sample conditioning system includes a dryer. For the sample point on the outlet of the TGCU Waste Heat Reclaimer, there is also the possibility of elemental sulfur vapor being present in the gas during process upsets. To prevent sulfur from reaching the analyzer and damaging it, a "sacrificial sample loop" consisting of a coil of bare tubing is provided in this sample line. The tubing coils provide heat transfer surface, so that if sulfur does find its way to this point in the process, the gas will cool off enough for the sulfur to solidify, plugging the sample loop and stopping the flow of process gas to the analyzer before the sulfur can damage the analyzer. Should this occur, only the coiled tubing will need to be replaced, rather than the expensive analyzer. Note that the sample lines are to free-drain from the analyzer back to the sample points, so the tubing coils should be oriented in the horizontal so that the coils due not cause a "pocket" in the sample line for this sample point. 11.5.1.3
Controls for Startup and Shutdown The front-end of the TGCU is also equipped with three sets of controls for use during startup and shutdown: a.
Prior to introducing SRU tailgas into the TGCU, the equipment in the front-end of the unit must be brought up to operating temperature. This is accomplished by using the TGCU Startup Blower, A2-GB1560, to re-circulate gas from the outlet of the TGCU Waste Heat Reclaimer to the inlet of the TGCU Reactor Feed Heater (via the TGCU Warmup/Bypass Valve, A2-NV15800). This allows using the TGCU Reactor Feed Heater to heat the gas and thereby bring all the equipment up to operating temperature. Flow controller A2-FIC15808 is provided to allow filling the front-end with nitrogen prior to establishing the re-circulation flow during startup. This same control can also be used to add nitrogen during shutdown of the unit for cool-down purposes.
b.
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Prior to the initial startup of the unit, the catalyst in the TGCU Reactor must be pre-sulfided so that it retains its activity when it Tailgas Cleanup
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SULFUR BLOCK is exposed to hydrogen at elevated temperatures. The catalyst will also have to be pre-sulfided when fresh catalyst is added to the reactor following a catalyst change-out. A source of H2S is needed for pre-sulfiding the catalyst, for which a slipstream of amine acid gas from the ARU serves nicely. Flow controller A2-FIC15824 is provided to allow adding a small amount of acid gas to give an H2S concentration of 1-2% in the nitrogen circulating through the front-end of the unit during catalyst pre-sulfiding activities. c.
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After the TGCU has been operating for a period of time, the catalyst becomes pyrophoric due to the presence of iron sulfide, FeS. Exposing catalyst containing pyrophoric FeS to air may result in uncontrolled burning of the FeS to form H2S and/or SO2, which obviously will prevent the entrance of personnel into the vessel. When the TGCU is to be shut down to replace the catalyst, or for other maintenance activities that will allow oxygen to enter the reactor, it is necessary to perform a controlled oxidation ("passivation") of the FeS in the catalyst by operating at low temperature (~150°C [~300°F]) and controlling a small concentration (1-2%) of oxygen in the circulating gas. This converts the FeS into non-pyrophoric iron oxide, Fe2O3, while leaving the catalyst in its sulfided state. Flow controller A2-FIC15805 is provided to allow adding a small amount of utility air to the nitrogen circulating through the front-end of the unit to provide the oxygen for catalyst passivation.
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SULFUR BLOCK
TGCU Reactor Feed Control Loops
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SULFUR BLOCK 11.5.2
Hydrogen and Hydrogen Sulfide Analyzer, A2-AE15858/A2-AE15859 Analyzer A2-AE15858/A2-AE15859 has two separate sensors, one for measuring hydrogen concentration and one for measuring hydrogen sulfide concentration. The H2S sensor is a photometric sensor that is very similar to the one used in the SRU air demand analyzers. It uses the absorption of a specific wavelength of UV light to determine the H2S concentration in the process gas. The H2 sensor in this analyzer is actually a thermal conductivity sensor. Hydrogen has a much higher thermal conductivity than the other gases found in the process stream, so the thermal conductivity of the process gas is a good indication of the hydrogen concentration. To make the sensor reading as accurate as possible, it is necessary to "zero" and "span" the sensor with special calibration gas mixtures that have the same "background" thermal conductivity as the expected process gas. Although this technique works well, always remember that this sensor does not measure hydrogen concentration directly, so its reading (particularly at low hydrogen concentrations) may not always be accurate. The H2/H2S analyzer can sample the process gas from two different locations, depending on the position of the selector valve inside the analyzer enclosure. The first sample connection is on the outlet of the TGCU Waste Heat Reclaimer. It should be used only during startup, pre-sulfiding, and other special operations when the process gas is bypassing the quench and contacting sections. This connection has a "sacrificial" sample line, which is essentially a disposable sample cooling coil. It is intended to protect the analyzer by cooling, condensing, and freezing any sulfur vapor that may be present in the sample due to process upsets. If this occurs, the cooling coil will plug before the sulfur can reach the analyzer, sacrificing the inexpensive tubing to protect the expensive analyzer. The second sample point is on the overhead line from the TGCU Contactor, and is the normal sampling point. During startup of the TGCU, the hydrogen analyzer should be switched to this sample point as soon as the Quench Column hand control in the DCS is used to open the Quench Column Inlet Valve and close Quench Column Bypass Valve to send gas through the TGCU Quench Column and the TGCU Contactor. There is much less chance of damaging the analyzer with contaminants when sampling gas at this point, so it is the preferred sample connection.
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SULFUR BLOCK Liquid water will destroy the H2 sensing element in this analyzer. Although the sample conditioning system includes a dryer to remove water vapor from the sample gas, liquid water can get through the dryer and damage the analyzer. Since water tends to condense from the process gas and accumulate in stagnant areas, make sure there is no liquid in the sample line before switching from one sample point to another.
11.5.3
Boiler Low-Low Level S/D Transmitter Testing The TGCU Waste Heat Reclaimer has three independent level transmitters connected to the PLC that activate the TGCU ESD system before the water level can get low enough to cause tube damage. The shutdown is activated when two out of three transmitters show a low-low level. These transmitters should be tested periodically to determine that they are functioning properly. Since 2oo3 voting is used for the low-low level shutdowns in the TGCU ESD, the level transmitters can be tested one at a time without having to bypass the ESD system. Consider A2-LT15845A on the Waste Heat Reclaimer, for example. The procedure for testing A2-LT15845B and A2-LT15845C will be similar. The procedure for testing A2-LT15845A is as follows:
Issued 30 August 2011
(1)
The outside operator notifies the DCS operator that he is preparing to test shutdown level transmitter "A" on the Waste Heat Reclaimer.
(2)
The DCS operator confirms that A2-LI15845B and A2-LI15845C are both indicating adequate level in the boiler, then notifies the outside operator to proceed.
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SULFUR BLOCK
CAUTION
DO NOT PROCEED UNLESS THE OTHER TWO LEVEL INDICATORS SHOW ADEQUATE LEVEL IN THE BOILER. OTHERWISE THE LOW-LOW LEVEL SHUTDOWN IN THE TGCU ESD WILL BE ACTIVATED AS SOON AS THE OUTSIDE OPERATOR BEGINS DRAINING THE LEVEL TRANSMITTER IN THE NEXT STEP. (3)
After being notified to proceed by the DCS operator, the outside operator blocks-in A2-LT15845A by closing its block valves, then opens the drain valve on the bottom of the transmitter to drain the water from the instrument.
(4)
If the transmitter is operating properly, the DCS will alarm that there is a low level in the Waste Heat Reclaimer on A2-LI15845A. The DCS operator acknowledges the alarm on the DCS and reports it to the outside operator.
(5)
After being notified of the alarm, the outside operator closes the drain valve on A2-LT15845A, slowly opens its bottom block valve to allow the transmitter to fill with water then opens its top block valve. This should clear the low level alarm on A2-LI15845A in the DCS.
(6)
After confirming that the low level alarm has cleared, the other level transmitters can be tested in a similar fashion.
NOTE:
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The DCS operator must not begin another task until confirming that the low level alarm has cleared. This is to guard against having a level transmitter malfunction that causes a TGCU ESD when the other transmitters are tested.
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SULFUR BLOCK 11.5.4
Tailgas Switching Valve Controls The tailgas switching valves and their controls for the Train 1 and Train 2 SRUs are depicted on the P&ID, dwg. no. 507000-7100-34, while the logic flowcharts, show the logic for these controls for the Train 1 SRU. However, it may be helpful to explain why the controls are implemented in this manner. The discussion that follows will describe how these controls allow routing the Train 1 SRU and Train 2 SRU tailgas streams to the Thermal Oxidizer and the TGCU under different operating scenarios, and will explain how the controls depicted on the P&ID correspond to the different sections of the logic diagrams.
11.5.4.1
Repositioning the Tailgas Valves Following a TGCU ESD As shown on the P&ID, prior to restarting the TGCU following a TGCU ESD, the SRU tailgas valves to the TGCU (A2-HV15462 and A2-HV15662) must be closed to satisfy the permissives for the TGCU ESD system reset. However, before these valves can be closed, the tailgas valves to the TTO (A2-HV15457 and A2-HV15657) must be opened first to avoid blocking the tailgas flow and causing the SRUs to shut down on high-high pressure. If the valves are not opened and closed in the proper order, the SRUs could inadvertently be shut down while preparing to restart the TGCU. For this reason, the TGCU ESD is an input to the PLC interlock blocks that manipulate the controllers (A2-HIC15457, A2-HIC15462, A2-HIC15657, and A2-HIC15662) for these valves. The PLCs and DCS automatically reposition the valves following a TGCU ESD to divert the SRU tailgas to the TTO, meaning that the valves are already positioned properly for the subsequent restart of the TGCU. The logic that accomplishes this for the Train 1 SRU is depicted on the logic flow diagram. When the TGCU ESD is activated, the Train 1 SRU PLC directs the DCS to set the output from A2-HIC15457 to 100% to open A2-HV15457, proves the valve open, then directs the DCS to set the output from A2-HIC15462 to 0% to close A2-HV15462 and proves the valve closed. This diverts the Train 1 SRU tailgas directly to the TTO. (The PLC logic will not take these actions if the Train 1 SRU has its startup/run selector switch, A2-HS15314, set to "STARTUP", since both tailgas valves will already be closed by the startup logic for the Train 1 SRU)
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SULFUR BLOCK Note that this same logic is also used to open the tailgas valve to the TTO and close the tailgas valve to the TGCU if the TGCU startup/run selector switch (A2-HS15830) is set to "STARTUP". This safeguard is to prevent sending SRU tailgas into the TGCU before the TGCU Reactor is ready, as this could cause a severe upset in the TGCU Quench Column and/or TGCU Contactor (and possibly damage the piping, equipment, quench water, and/or solvent). 11.5.4.2
Introducing SRU Tailgas into the TGCU — Scenario 1 The first scenario to consider for introducing tailgas into the TGCU is a normal startup of the SRUs and the TGCU. Before being routed to the TGCU, the tailgas from both SRUs is sent to the TTO via valves A2-HV15457 and A2-HV15657, while the TGCU uses the TGCU Startup Blower to re-circulate gas to the TGCU Reactor Feed Heater via the TGCU warmup/bypass valve, A2-NV15800. Once the TGCU is warmed up and ready to accept tailgas, the Train 1 and Train 2 SRUs can be routed to the TGCU as follows (using the Train 1 SRU for this example).
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1.
The operator toggles the "fast" transfer switch, A2-HS15463 in the DCS, to "TRANSFER TO TGCU".
2.
The PLC directs the DCS to set the output from A2-HIC15462 to 100% to open the Tailgas Valve to the TGCU, A2-HV15462, then proves that the valve is open.
3.
Since the Tailgas Valve to the TTO, A2-HV15457, is still open, the SRU tailgas will continue flowing to the TTO at this time (the path of least resistance).
4.
Once the limit switches prove A2-HV15462 is open, the PLC directs the DCS to set the output from A2-HIC15457 to 0% to close A2-HV15457, then proves that the valve is closed.
5.
Since A2-NV15800 is open at this time, some of the SRU tailgas may still flow through this valve directly to the TTO. The TGCU Startup Blower will pull the rest of the tailgas into the TGCU Reactor Feed Heater.
6.
If the second SRU (Train 2 in this example) is also ready to send its tailgas to the TGCU, the operator can also toggle its "fast" transfer switch in the DCS (A2-HS15663) to repeat these actions for the second SRU. Tailgas Cleanup
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SULFUR BLOCK 7.
Once one or both of the tailgas valves to the TGCU is open and the corresponding tailgas valve(s) to the TTO are closed, the operator can use A2-HIC15800 in the DCS to close A2-NV15800.
8.
This will force all of the SRU tailgas to flow to the TGCU Reactor Feed Heater.
9.
Once A2-NV15800 is fully closed, all of the SRU tailgas must flow to the TGCU Reactor Feed Heater because there are no longer any other open paths to the TTO. The TGCU Startup Blower can now be shut down by toggling A2-HPB15855 in the DCS to "STOP" to open the blower bypass valve, turn off the blower, and close the blower suction and discharge valves.
10. All of the SRU tailgas will now be flowing through the TGCU Reactor Feed Heater, TGCU Reactor Feed Mixer, TGCU Reactor, and TGCU Waste Heat Reclaimer, then flowing to the TTO via the TGCU Quench Column bypass valve, A2-HV15851, at the TGCU Startup Blower. Once the plant stabilizes and there is excess hydrogen in the reactor outlet, the TGCU Quench Column inlet valve, A2-HV15850, can be opened and A2-HV15851 closed using A2-HIC15850 in the DCS to send the process gas into the TGCU Quench Column and TGCU Contactor. For this scenario, the opening and closing of A2-HV15462 and A2-HV15457, respectively, (or A2-HV15662 and A2-HV15657 for Train 2) in Steps 2 and 3 can occur rapidly with no impact on either the SRU or the TGCU. This is because A2-NV15800 will still be open at this time, so there will be very little differential pressure across A2-HV15462 (A2-HV15662) and there will not be an abrupt change in pressure when A2-HV15462 (A2-HV15662) is opened or when A2-HV15457 (A2-HV15657) is closed. Note that A2-HS15463 and A2-HS15663 can also be used to take the Train 1 SRU and/or Train 2 SRU tailgas out of the TGCU. Every other toggle of these selector switches will take the opposite action to open the tailgas valve to the TTO and then close the tailgas valve to the TGCU. For instance, if a problem develops while introducing the tailgas into the TGCU, toggling A2-HS15463 and A2-HS15663 to "TRANSFER TO TTO" will immediately divert the SRU tailgas to the TTO
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SULFUR BLOCK and block it from flowing into the TGCU. Once the problem has been corrected, A2-HS15463 and A2-HS15663 can be toggled once again to "TRANSFER TO TGCU" to send the SRU tailgas into the TGCU. 11.5.4.3
Introducing SRU Tailgas into the TGCU — Scenario 2 The second startup scenario to consider is when the TGCU is already processing tailgas from one SRU, and the tailgas from the second SRU needs to be introduced into the TGCU. Assume that the Train 2 SRU is currently feeding the TGCU. Due to the back-pressure from the TGCU, the pressure downstream of A2-HV15462 will be about 0.07 kg/cm2(g), while the pressure upstream of this valve will be close to 0 kg/cm2(g) (since A2-HV15457 will be open to the TTO at this time). If the Train 1 tailgas was quickly switched into the TGCU in the same manner as described above for the first scenario, a major upset would result in both SRUs and in the TGCU: (1)
As soon as A2-HV15462 started to open, tailgas from the Train 2 SRU would begin to back-flow through A2-HV15462 and flow to the TTO, since the pressure downstream of A2-HV15462 at that moment would be higher than the pressure upstream of A2-HV15462. Since A2-HV15462 is a more direct path to the TTO for the tailgas from the Train 2 SRU, most of the Train 2 tailgas would flow through A2-HV15462 as it opens rather than flow through the TGCU. The outlet temperature from the TGCU Reactor Feed Heater would begin to rise (due to the drop in tailgas flow), causing the controls to begin reducing the steam flow rate to the heater. Once A2-HV15462 was fully open, all of the Train 1 tailgas and most of the Train 2 tailgas would be flowing directly to the TTO through A2-HV15457. The TGCU controls would continue reducing the steam flow rate to the TGCU Reactor Feed Heater to try to keep its outlet temperature under control.
(2)
With A2-HV15462 fully open, A2-HV15457 would begin to close. This would begin forcing all of the Train 1 tailgas and Train 2 tailgas into the TGCU Reactor Feed Heater. The outlet temperature from the TGCU Reactor Feed Heater would begin to drop, causing the controls to begin increasing the steam flow rate to the heater. Once A2-HV15457 was fully
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SULFUR BLOCK closed, all of the Train 1 and Train 2 tailgas would be flowing to the TGCU Reactor Feed Heater, causing an abrupt increase in its operating pressure from about 0.07 kg/cm2(g) to about 0.25 kg/cm2(g). This would cause the air and acid gas flow rates to the SRUs to suddenly drop, possibly causing the SRUs to flame-out. If so, the SRUs and the TGCU would shut down and the operators would have to start over again. (3)
If the SRUs and TGCU did manage to stay on-line, the TGCU Reactor Feed Heater would be supplying less than half as much heating as needed until the controls recover and bring the steam flow rate up to the new requirements. Until then, the inlet temperature to the TGCU Reactor would be low, possibly causing incomplete conversion of SO2 in the reactor and allowing SO2 to reach the quench water and solvent systems and foul them. The reducing gas flow rate might also require time to adjust to the higher tailgas flow rate, further compounding the problems with conversion in the reactor.
So, the best that could be expected if the second SRU is routed to the TGCU in the same manner as under the first scenario is an upset in both SRUs, the TGCU Reactor Feed Heater, the TGCU Reactor, the quench water system, and the solvent system. Depending on how quickly the SRUs respond to sudden changes in operating pressure, the SRU burners might flame-out. In this worst case, a complete restart of the SRUs and the TGCU would then be required. Instead of introducing the tailgas from the second SRU into the TGCU in an abrupt manner, what is needed is a slow, controlled redirection of the tailgas from the TTO to the TGCU. This can be accomplished by the DCS operator using A2-HIC15457 and A2-HIC15462: 1.
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Under this scenario, the TGCU is already processing tailgas from the Train 2 SRU. This means that the TGCU warmup/bypass valve, A2-NV15800, is already closed. This signals the PLC to disable the "fast" transfer switches in the DCS, A2-HS15463 and A2-HS15663 so that the rapid switching sequence (scenario 1) cannot be activated inadvertently.
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SULFUR BLOCK 2.
The DCS operator initiates the over-ride for the Train 1 tailgas valves by toggling the "slow" transfer switch, A2-HS15464 in the DCS, to "OVER-RIDE". The PLC temporarily removes the limit switches on A2-HV15457 and A2-HV15462 from the "complete flowpath interlock" for the Train 1 SRU alarms and deactivates the "valve malfunction" alarms on these two valves, then directs the DCS to release control of A2-HIC15457 and A2-HIC15462 to the operator.
3.
The operator uses A2-HIC15457 to slowly begin throttling the tailgas flow with A2-HV15457, so that the pressure at the front-end of Train 1 is slightly higher than at the front-end of the Train 2 SRU. The DCS operator can monitor the flows and pressure in the Train 1 SRU and adjust A2-HIC15457 accordingly.
4.
Once A2-HV15457 is throttling, the operator uses A2-HIC15462 to slowly open A2-HV15462. Some of the Train 1 tailgas may begin to flow into the TGCU at this time, but most of it will still flow through A2-HV15457 directly to the TTO. The DCS operator can monitor the flows and pressures in the Train 1 SRU and the TGCU, and adjust the rate at which A2-HV15462 is opened accordingly.
5.
Once A2-HV15462 is fully open, the operator uses A2-HIC15457 to slowly close A2-HV15457 the rest of the way and send all of the Train 1 tailgas to the TGCU. The DCS operator can monitor the flow rates and temperatures in the TGCU, and adjust the rate at which A2-HV15457 is closed as needed to allow time for the controls in the TGCU to respond.
6.
Once A2-HV15457 is fully closed, the Train 1 SRU is flowing to the TGCU along with the Train 2 SRU, and the TGCU is fully on-line. When A2-HV15462 is fully open and A2-HV15457 is fully closed, the PLC will automatically restore the limit switches on A2-HV15457 and A2-HV15462 to the "complete flowpath interlock" in the SRU alarms, restore the malfunction alarms for these valves to their normal configurations, and reset the "slow"
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SULFUR BLOCK transfer switch, A2-HS15464 in the DCS, back to "NORMAL" to remove the over-ride. One further point to note is that the "slow" transfer over-ride switches can also be used to "back" tailgas out of the TGCU. If the operator wants to shut down the TGCU in a controlled fashion, this can be accomplished by using the TGCU Startup Blower to circulate gas through the TGCU Reactor Feed Heater while slowly "backing" the SRU tailgas out of the TGCU. The steps to perform this are essentially the same as those listed above (but in reverse order).
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SULFUR BLOCK 11.5.5
TGCU Shutdown System The purpose of the Tailgas Cleanup Unit Emergency Shutdown system (TGCU ESD) is to shut off the flow of tailgas, reducing gas, pre-sulfiding gas, nitrogen, and passivation air to the TGCU when serious problems occur. The Cause and Effect Diagram, contained in the Instrumentation and Controls Diagrams section of the Basic Engineering Package, describes the TGCU ESD system in block format. For reference, the causes and effects of the ESD system shown on this diagram are explained below. As noted on the Cause and Effect Diagram, it is recommended that a 5 second delay be used for most of the process parameters included in the causes of the ESD system. This is to prevent the "nuisance" shutdowns that are sometimes caused by momentary fluctuations in the process or the sensing elements.
11.5.5.1
Causes Any one of the causes listed below will activate the TGCU ESD system: a.
Manual Shutdown Switch, A2-HS15827 An operator can activate the TGCU ESD system using the NORMAL / ESD selector switch in the DCS.
b.
Both SRU ESD Systems For normal modes of operation, the TGCU ESD system is activated when both SRU ESD systems are activated. Without any SRU tailgas flowing through the front-end of the TGCU, there is nothing to process in the unit, so the TGCU is shut down whenever both sulfur plants shut down. (Note, however, that the TGCU ESD is not activated if one of the SRUs is still on-line when the other SRU shuts down.) However, if the TGCU is not yet fully processing tailgas from either SRU, there is no reason to shut it down if no SRUs are running. This simplifies startup of the TGCU by allowing its ESD system to be independent of the SRU ESD systems until tailgas is introduced into the TGCU. The example logic below shows this concept:
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SULFUR BLOCK
c.
Complete Flowpath Interlock (see Logic Flow Diagrams for the limit switch tag numbers) In order for the TGCU to operate without over-pressuring itself or the Sulfur Drain Seal Assemblies in the upstream SRUs, there must be a complete flowpath for SRU tailgas through the TGCU to the TTO. The ESD logic can determine whether such a complete flowpath exists by examining the status of the limit switches on the process gas valves. There are basically three different paths that the SRU tailgas can take to reach the TTO: (1)
The TGCU Warmup/Bypass Valve, A2-NV15800, and the TGCU Outlet Valve, A2-HV15801, are both fully open.
(2)
The process gas is diverted to the TTO upstream of the TGCU Quench Column:
(3)
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(a)
The TGCU Quench Column A2-HV15851, is fully open;
Bypass
Valve,
(b)
Either the TGCU Startup Blower Bypass Valve, A2-HV15853, is fully open, or both the TGCU Startup Blower Suction Valve, A2-HV15852, and the TGCU Startup Blower Discharge Valve, A2-HV15854, are fully open; and
(c)
The TGCU Outlet Valve is fully open.
The process gas is flowing through the TGCU Quench Column and the TGCU Contactor to the TTO: (a)
The TGCU Quench Column A2-HV15850, is fully open; and
(b)
The TGCU Outlet Valve is fully open.
Tailgas Cleanup
Inlet
Valve,
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SULFUR BLOCK If the "open" limit switches do not indicate that at least one of these flowpaths is valid, the "complete flowpath interlock" is tripped and the TGCU ESD system is activated. Note that the TGCU Complete Flowpath Interlock signal to the Complete Flowpath Interlock logic for the Train 1 SRU and the Train 2 SRU is over-ridden for 60 seconds when this occurs, allowing time for the SRU tailgas valves to be repositioned (see Section 11.5.4.1) and preventing nuisance alarms in the SRUs. d.
TGCU Reactor A2-TT15842A/B/C
Outlet
High-High
Temperature,
These devices shut down the TGCU if the reactor outlet temperature reaches 400°C. The most common cause of high reactor outlet temperature is large concentrations of SO2 in the SRU tailgas streams due to poor sulfur plant performance, leading to excessive heat of reaction in the catalyst bed. These devices will prevent excessive temperatures in the reactor from causing damage to the reactor vessel, its catalyst, or its catalyst bed support. Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD (i.e., at least two transmitters must show high-high temperature) to avoid spurious "trips" due to the malfunction of a single transmitter. e.
TGCU Waste Heat A2-LT15845A/B/C
Reclaimer
Low-Low
Water
Level,
These devices activate the TGCU ESD system to prevent having the water level drop below the top of the tubes in this boiler while hot gas is flowing through the tubes, thereby averting high effluent temperatures and higher than normal tube wall temperatures. High effluent temperatures could cause high overhead temperature from the TGCU Quench Column and result in poor H2S removal in the TGCU Contactor, and high tube wall temperatures could possibly damage the tubes due to differential expansion. These devices are set to actuate if the level falls to within 75 mm of the top of the tubes. Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD.
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SULFUR BLOCK 11.5.5.2
Effects A TGCU shutdown, activated either manually or automatically, has the following effects on the TGCU:
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a.
Opens the Train 1 SRU Tailgas Valve to the TTO, A2-HV15457, proves it open, then closes the Train 1 SRU Tailgas Valve to the TGCU, A2-HV15462, and proves it closed.
b.
Opens the Train 2 SRU Tailgas Valve to the TTO, A2-HV15657, proves it open, then closes the Train 2 SRU Tailgas Valve to the TGCU, A2-HV15662, and proves it closed.
c.
Disables the "fast" and "slow" tailgas transfer switches for the Train 1 SRU (A2-HS15463 and A2-HS15464, respectively) and for the Train 2 SRU (A2-HS15663 and A2-HS15664, respectively).
d.
Shuts off and depressurizes the nitrogen and plant air supplies by closing block valves A2-NV15809 and A2-NV15811 and opening vent valve A2-NV15810.
e.
Shuts off and depressurizes the reducing gas supply by closing block valves A2-NV15817 and A2-NV15819 and opening vent valve A2-NV15818.
f.
Closes the reducing gas flow control valve, A2-FV15816, by placing A2-FIC15816 in "manual" and setting its output to 0%.
g.
Shuts off the pre-sulfiding gas flow by closing block valve A2-NV15825.
h.
Closes the TGCU Quench Column Inlet Valve, A2-HV15850, and the TGCU Quench Column Bypass Valve, A2-HV15851, to stop the flow of SRU tailgas into the TGCU.
i.
Forces the output of A2-HIC15850 in the DCS (which controls the TGCU Quench Column inlet and bypass valves) to 0% in preparation for the subsequent restart.
j.
Shuts down the TGCU Startup Blower, A2-GB1560; closes its suction valve (A2-HV15852), its discharge valve (A2-HV15854), and the nitrogen purge valve for the blower seal (A2-HV15856); and opens its bypass valve (A2-HV15853) and the nitrogen purge valve for the blower casing, (A2-HV15857).
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SULFUR BLOCK k.
11.5.5.3
Resets DCS toggle switches A2-HS15817, A2-HS15825, and A2-HS15809 to "OFF" and A2-HPB15855 to "STOP".
Non-ESD Shutdowns In addition to the devices listed in Section 11.5.5.1 that activate the TGCU ESD system, there are several interlocks of significance that either generate an alarm or shut down an individual piece of equipment. These devices/interlocks and their effects are described in this section. a.
TGCU Quench Column Low-Low Level, A2-LT15867A/B/C The TGCU Quench Water Pump (A2-GA1560A/B) could be damaged if the pump loses suction because the level in the TGCU Quench Column drops too low. These devices will protect the pump by stopping it before this can occur. The shutdown setpoint is 450 mm above the bottom seam of the column. Note that there are three independent transmitters and 2oo3 voting logic is used for the S/D (i.e., at least two transmitters must show low-low level) to avoid spurious "trips" due to the malfunction of a single transmitter.
b.
TGCU Quench A2-WSH15879
Water
Cooler
Fan
High
Vibration,
Each fan on the TGCU Quench Water Cooler (A2-EC1560) is provided with its own vibration switch. If the vibration sensed by the switch exceeds the preset level, the switch will trip to stop the associated fan and activate an alarm in the DCS. The fan will not restart until the vibration switch is reset by an operator. c.
TGCU Contactor Low-Low Level, A2-LT15895A/B/C The TGCU Rich Solvent Pump (A2-GA1561A/B) could be damaged if the pump loses suction because the level in the TGCU Contactor drops too low. These devices will protect the pump by stopping it before this can occur. The shutdown setpoint is 450 mm above the bottom seam of the column. Note that there are three independent transmitters and 2oo3 voting logic is used for the S/D.
d.
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SULFUR BLOCK Each fan on the TGCU Lean Solvent Cooler (A2-EC1561) is provided with its own vibration switch. If the vibration sensed by the switch exceeds the preset level, the switch will trip to stop the associated fan and activate an alarm in the DCS. The fan will not restart until the vibration switch is reset by an operator. e.
TGCU Stripper Low-Low Level, A2-LT15932A/B/C The TGCU Lean Solvent Pump (A2-GA1562A/B) could be damaged if the pump loses suction because the level in the TGCU Stripper drops too low. These devices will protect the pump by stopping it before this can occur. The shutdown setpoint is 450 mm above the bottom seam of the column. Note that there are three independent transmitters and 2oo3 voting logic is used for the S/D.
f.
TGCU Stripper A2-WSH15942
Reflux
Condenser
Fan
High
Vibration,
Each fan on the TGCU Stripper Reflux Condenser (A2-EC1562) is provided with its own vibration switch. If the vibration sensed by the switch exceeds the preset level, the switch will trip to stop the associated fan and activate an alarm in the DCS. The fan will not restart until the vibration switch is reset by an operator.
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SULFUR BLOCK
11.6 Process Principles and Operating Techniques The more important considerations involved in startup, operation, shutdown, maintenance, and emergency procedures for the TGCU are discussed in the remaining sections of this portion of the operating guidelines. The operator should also be thoroughly acquainted with the equipment and the "Process Description" section in these guidelines before attempting to operate the plant in accordance with the operating techniques that follow. If the function of each portion of the plant equipment is understood, the sequence of steps outlined in the "procedures" sections will be more easily understood. In addition, the following general discussion of principles and techniques will clarify the reasons for some of the procedures.
11.6.1
Equipment Damage After the initial startup, the front-end of the TGCU may contain some sulfur, including the catalyst bed in the TGCU Reactor. Sulfur fires will ignite at temperatures as low as 150°C if sufficient oxygen is available. In addition, TGCU catalyst is pyrophoric at ambient temperatures when in its sulfided state (which is its normal operating condition). For these reasons, it is very important to minimize the time periods when air (or other gases containing oxygen) is routed through the catalyst bed. Localized high temperatures can exist in the catalyst bed even though the temperatures measured around the reactor are low. Because of this, sulfur and/or catalyst ignition sometimes occurs in a catalyst bed when it is not anticipated by temperatures that are readily available for observation. Under ordinary circumstances, oxygen-bearing gases will only be flowing through the reactor when passivating its catalyst. When passivating the catalyst in the reactor, observe the reactor temperatures frequently. If the temperatures begin to increase above 150°C, reduce the amount of air entering the reactor to limit the passivation so that the reactor temperatures remain below 150°C. This will prevent the catalyst from reacting with oxygen so that pre-sulfiding is not required during the subsequent startup. Do not use water to quickly cool the TGCU Reactor after a fire. Not only will this damage the catalyst, the rapid cooling may cause structural damage to the TGCU Reactor. The acidic water that forms may cause corrosion damage to the TGCU Reactor or other equipment. Nitrogen is available to the TGCU for use in cooling a hot catalyst bed.
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SULFUR BLOCK
CAUTION NEVER "HYDROBLAST" THE TUBES (OR ANY OTHER STEEL SURFACES) IN THE TGCU EQUIPMENT. NOT ONLY DOES THIS REMOVE THE PROTECTIVE SULFIDE FILM THAT FORMS ON CARBON STEEL AND PREVENTS CORROSION, THE WATER WILL REACT WITH THE SULFUR COMPOUNDS PRESENT IN THE EQUIPMENT TO FORM A VARIETY OF ACIDS (SULFUROUS, POLYTHIONIC, ETC.) THAT RAPIDLY CORRODE THE STEEL. THERE HAVE BEEN NUMEROUS INSTANCES OF SULFUR PLANT BOILERS BEING BLASTED DURING A TURNAROUND TO CLEAN THEM UP, THEN HAVING THE TUBES BEGIN LEAKING AS SOON AS THE BOILER IS RETURNED TO SERVICE. IF THE TGCU WASTE HEAT RECLAIMER TUBES HAVE BECOME PLUGGED, THE BEST WAY TO CLEAR THE TUBES IS TO MECHANICALLY "ROD" THEM. IF SULFUR OR SULFUR COMPOUNDS HAVE PLUGGED THE TUBES, IT IS OFTEN HELPFUL TO APPLY HEAT TO THE TUBES BEFORE "RODDING", AS THIS WILL MELT ANY SULFUR THAT MAY BE PART OF WHAT HAS PLUGGED THE TUBES. ONE WAY TO DO THIS IS TO DRAIN THE WATER FROM THE BOILER AND PUT STEAM ON THE SHELL. DRAIN THE CONDENSATE PERIODICALLY TO KEEP LIVE STEAM ON THE TUBES.
11.6.2
Catalyst Fouling The catalyst bed in the TGCU Reactor may be severely fouled by carry-over of heavy hydrocarbon liquids or vapors. This will cause permanent damage to the catalyst and is to be avoided if possible, even if shutting down the TGCU for periods is required. The most common source of heavy hydrocarbons in TGCUs is contaminants in the reducing gas stream. The pressure drop across the TGCU Reactor should be monitored regularly to help detect this problem before the pressure drop becomes so high that a plant shutdown is required to remove the fouled catalyst.
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SULFUR BLOCK 11.6.3
TGCU Reactor Operation The purpose of the TGCU Reactor is to convert all of the sulfur compounds in the tailgas from both SRUs into hydrogen sulfide. This is accomplished by catalytic hydrogenation of the sulfur dioxide and sulfur vapor, and hydrolysis of the organic sulfur compounds: (1)
SO2 + 3 H2
H2S + 2 H2O
(2)
S + H2
H2S
(3)
COS + H2O
H2S + CO2
(4)
CS2 + 2 H2O
2 H2S + CO2
The catalyst also promotes the classic "water gas shift" reaction: (5)
CO + H2O
H2 + CO2
This effectively converts carbon monoxide in the tailgas gas into hydrogen for use in reactions (1) and (2) above. This is an equilibrium reaction, so it is typical for a small amount of CO to leave a reactor, depending on the amount of hydrogen and carbon dioxide in the reactor outlet. The CO concentration in the reactor outlet is usually less than 100 PPM, but may be higher if the CO2 content of the feed gas is high or if the catalyst has lost activity. NOTE:
A small portion of the COS and CS2 may either not react at all, or be reduced by the hydrogen to form methane and/or methyl mercaptan:
(6)
COS + 4 H2
CH4 + H2S + H2O
(7)
CS2 + 4 H2
CH4 + 2 H2S
(8)
COS + 3 H2
CH3SH + H2O
(9)
CS2 + 3 H2
CH3SH + H2S
These reactions should produce only a few PPM of methane and/or mercaptan unless there is a large amount of COS/CS2 in the SRU tailgas, or the TGCU catalyst has lost activity. Since the TGCU amine will not remove mercaptans from the gas, any mercaptans formed will escape to the Thermal Oxidizer and cause increased SO2 emissions. Methane in the reactor effluent may result in increased CO emissions from the Thermal
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SULFUR BLOCK Oxidizer (due to partial oxidation), depending on the operating conditions in the Thermal Oxidizer. To avoid these problems, the amount of COS/CS2 entering the TGCU should be maintained as low as possible by proper operation of the upstream SRUs (and amine and sour water stripping units). All of these reactions are exothermic, causing the temperature of the gas to rise as it flows through the reactor. The hydrogenation of the SO2 into H2S is the predominant factor in the temperature rise, so the temperature rise across the TGCU Reactor is usually a direct indication of the amount of SO2 entering the TGCU from the SRUs. If the temperature rise is higher than normal (about 50-60°C at design conditions), this is usually a sign that the upstream sulfur plant(s) is off-ratio. The resulting high outlet temperature from the TGCU Reactor cannot be corrected in the TGCU. Rather, the problem must be corrected in the SRUs, or the upstream units feeding the SRUs. Regardless of the amount of SO2, sulfur vapor, and organic sulfur entering the TGCU Reactor, all of it must be converted to H2S for proper operation of the downstream equipment. This can be achieved (assuming normal catalyst activity) by maintaining an adequate excess of hydrogen in the TGCU Reactor outlet, so that all of the reactions go to completion. The hydrogen concentration is normally measured in the treated gas leaving the TGCU Contactor. Although the design material balance calls for a hydrogen concentration of about 3% at this point, a concentration in the range of 1-2% is normally adequate. However, controlling the concentration at 3% or higher allows a much larger margin for tolerating upsets in the upstream SRUs, and is generally preferred. Unlike other TGCUs which use in-line burners to generate reducing gas (because external hydrogen is not available), this TGCU receives reducing gas from a hydrogen purification unit. However, poor ratio control in either SRU can still lead to an excessively high outlet temperature from the TGCU Reactor. If, for instance, an SRU is operating with excess air, the H2S:SO2 ratio will be low in the SRU tailgas (registered as high air demand) and the SO2 concentration will be high in the TGCU Reactor feed. This will cause a large temperature rise in the reactor. Left unchecked, the temperatures in the TGCU Reactor could rise to the point of damaging the catalyst, the catalyst bed support, and/or the reactor vessel itself. The thermocouples in the catalyst bed and in the outlet line have alarms to provide an early warning of this condition. If the
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SULFUR BLOCK temperature reaches 400°C in the outlet line, the TGCU ESD system will be activated to shut down the TGCU and divert the SRU tailgas to the Thermal Oxidizer, before damaging the TGCU Reactor or its catalyst. Be aware, however, that the "thermal mass" of the TGCU Reactor and its catalyst bed is quite large relative to the gas flowing through them, so temperature changes occur very slowly (particularly at low flow rates). For this reason, it is important to watch the temperature trends around the reactor and be prepared to take corrective action early so that the corrections have time to take effect before a high-high temperature shutdown is activated. It is particularly important to watch these temperatures closely during periods of startup, shutdown, or process upsets when the TGCU Reactor inlet temperature, composition, and/or flow rate are changing significantly.
11.6.4
TGCU Catalyst The active components for the hydrogenation reactions are cobalt and molybdenum sulfides in the cobalt/molybdenum catalyst. The catalyst is normally supplied by the catalyst vendor in its oxidized state, although some vendors can supply pre-sulfided catalyst. Contacting the catalyst with hydrogen at temperatures exceeding 200°C prior to sulfiding should be avoided to prevent impairing the catalyst activity, as hydrogen will irreversibly sinter the metal oxides to form metal hydrides that do not catalyze the TGCU reactions. Pre-sulfiding the catalyst before exposing it to hydrogen at high temperature yields a catalyst with stable, high activity. The catalyst is pre-sulfided by contacting it with an H2S-containing gas (such as the inlet amine acid gas to the SRUs) in the presence of hydrogen. During this operation, the following reactions occur: (1)
CoO + H2S
CoS + H2O
(2)
MoO3 + x H2S + (3-x) H2
1/n MonSn*x + 3 H2O
The molybdenum sulfide will probably be present in the form of Mo2S3, MoS2, and MoS3. These reactions are exothermic (heat liberating), so it is necessary to carefully control pre-sulfiding operations to prevent overheating the catalyst and/or equipment. The TGCU Startup Procedures Section of these guidelines contains a complete description of the suggested pre-sulfiding procedure.
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SULFUR BLOCK The catalyst should be exposed to air only under controlled conditions when it is in the reduced (sulfided) state as it is pyrophoric (capable of spontaneous ignition) and rapid oxidation could occur, causing damage to the catalyst, the TGCU Reactor, and/or the downstream equipment and piping. The pyrophoric nature of the catalyst is caused by the presence of iron sulfide (FeS), which gradually builds up in the catalyst due to accumulation of corrosion products from upstream equipment and piping. Controlled burn-off of the catalyst (passivation) to eliminate FeS can be accomplished by low-temperature oxidation which destroys the FeS but leaves the active Co/Mo sulfides intact. The TGCU Reactor can then be opened for maintenance, etc. The procedure to accomplish this catalyst "passivation" is fully described in TGCU Shutdown Procedures Section these guidelines. The catalyst activity should be monitored regularly so that there is forewarning of catalyst deactivation. Shell Global Solutions recommends using a gas chromatograph to analyze the gas downstream of the TGCU Reactor (TGCU Contactor overhead gas, for instance) for CO, H2, and COS. The CO/H2 ratio (PPM CO divided by vol % H2) and the COS PPM can then be plotted versus time. When the CO/H2 ratio and/or the COS PPM rise rapidly, preparations should be made to replace the TGCU catalyst within a few months.
11.6.5
TGCU Start-Up Blower Operation Prior to introducing SRU tailgas into the TGCU during startup, the equipment in the front-end of the unit must be brought up to operating temperature. This is accomplished by using the TGCU Start-Up Blower, A2-GB1560, to re-circulate gas from the outlet of the TGCU Waste Heat Reclaimer to the inlet of the TGCU Reactor Feed Heater (via the TGCU Warmup/Bypass Valve). This allows using the TGCU Reactor Feed Heater to heat the gas and thereby bring all the equipment up to operating temperature. A flow controller is provided to allow filling the front-end equipment and piping with nitrogen prior to establishing the re-circulation flow during startup. Once the tailgas from the SRU(s) is brought into the TGCU, the re-circulation from the TGCU Start-Up Blower is no longer needed, so the blower can then be shut down.
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SULFUR BLOCK 11.6.6
TGCU Quench Column Operation The operating conditions shown on the Process Flow Diagram for this system (in terms of circulation rate and water temperature) should generally be maintained. Decreasing the water circulation rate will increase the bottoms temperature (which increases the corrosion rate), while increasing the circulation rate increases the load on the pump and the coolers. The flow rate and temperatures shown are usually a good compromise between minimizing corrosion and minimizing utility costs. The quench water circulation rate is controlled by the quench water flow controller in the DCS, while the temperature is controlled by a temperature controller adjusting the speed of one of the fans on the TGCU Quench Water Cooler, A2-EC1560. Although the design values will give adequate operation, there are advantages in maintaining the quench water temperature (which controls the overhead temperature) as low as possible. These conditions will minimize the temperature and water content of the overhead gas leaving the TGCU Quench Column and thus minimize the load on the TGCU Contactor. The bottoms temperature of the TGCU Quench Column is not critical except for controlling corrosion; this temperature depends on the gas feed rate and the temperature and flow rate of the circulating quench water. However, operating the quench water at a lower or higher temperature than the TGCU lean amine can cause the TGCU amine system to be out of water balance. Normally, both the quench water and the TGCU amine should operate at roughly the same temperature to minimize the impact on the amine system water balance. A portion of the quench water is sent to SWS Flash Drum on level control to balance the water condensed from the process gas by the circulating quench water and maintain the bottoms level in the TGCU Quench Column. This "bleed" water rate depends on the amount of water in the SRU tailgas, and the amount of water contained in the gas leaving the column. The TGCU Quench Water Filter removes sulfur and particulates from the circulating quench water to maintain water clarity. The flow rate to the filter should be maintained at its design value to provide maximum filtration. The appearance of the circulating quench water is a good indicator of whether the TGCU Reactor is operating properly. A sight glass is
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SULFUR BLOCK provided to allow the operator to observe the condition of the water. If SO2 should escape from the TGCU Reactor, it will react with the H2S dissolved in the water to form sulfur: (1)
2 H2S + SO2
3 S + 2 H2O
This sulfur will be produced as tiny particles of solid sulfur, forming a colloidal suspension in the water and giving the water a milky appearance. The SO2 may also remain dissolved in the water and form a weak solution of sulfurous acid: (2)
H2O + SO2
H2SO3
If sufficient acid is formed to drop the pH of the quench water below 7, the acid will often scour the iron sulfide film (which normally protects the steel from corrosion) from the carbon steel equipment and piping. The iron sulfide particles will turn the quench water black (or green). Either color change (milky or black/green) is a symptom of SO2 "break-through" from the TGCU Reactor, meaning that inadequate reducing gas is being supplied to the reactor. An abnormal increase in the pressure drop across the TGCU Quench Water Filter is also a good indication of SO2 break-through, as the sulfur and/or iron sulfide particles collect on the filter elements. Should any of these events occur, immediately observe the readings on the air demand analyzers in the SRUs, the hydrogen analyzer in the TGCU, and the quench water pH analyzer. Make appropriate corrections to the air:acid gas ratio in the SRU(s), the hydrogen rate to the TGCU Reactor Feed Mixer, or both to eliminate the SO2 breakthrough. Also, begin (or increase) caustic injection into the quench water to raise the pH and minimize the corrosion to the system. Failure to maintain the proper pH (generally 8.0-9.5) will quickly damage the quench water equipment and piping due to acid corrosion, and may allow SO2 to reach the TGCU Contactor and form heat-stable salts with the amine. Heat-stable salts can cause accelerated corrosion in the TGCU amine system. If a large SO2 deviation occurs (very low pH, very dirty quench water, rapid plugging of the TGCU Quench Water Filter, etc.), it may be desirable to dilute the quench water with fresh condensate makeup. This accomplishes two things to facilitate cleanup of the quench water system: the fresh makeup will dilute the SO2 and help raise the pH, and the makeup will raise the level in the TGCU Quench Column and cause the quench water column level controller to increase the "bleed" rate of
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SULFUR BLOCK quench water to the Sour Water Stripping Unit. The rate at which condensate is added to the system must be regulated to keep the temperature to the circulating pump low enough that the pump does not cavitate. Experience will show how quickly condensate can be added without causing pumping problems. In this fashion, the TGCU Quench Column serves as a good scrubber preceding the TGCU Contactor to prevent minor upsets in the SRUs or the TGCU Reactor from degrading the TGCU amine with SO2. Nevertheless, the hydrogen and pH analyzers in the TGCU should be carefully observed and properly maintained to minimize the number and duration of pH excursions in the quench water system. This will maximize the service life of the quench water system and minimize the degradation of the amine. In addition, consider diverting the process gas from the TGCU Reactor to the Thermal Oxidizer before it enters the TGCU Quench Column during periods of large upsets when SO2 may break through the reactor, before SO2 gets into the quench water and causes problems. Taking this preventative measure will cause higher SO2 emissions from the Thermal Oxidizer and put it out of compliance, but it will allow the TGCU to be brought back to normal operation much more quickly by avoiding a pH excursion in the quench system and the water cleanup operation that often results (i.e., numerous filter changes in the TGCU Quench Water Filter). When the TGCU is operating in "normal" mode, the TGCU Reactor effluent can be diverted directly to the Thermal Oxidizer simply by reducing the output on the Quench Column bypass hand controller in the DCS to 0%. This will open the TGCU Quench Column bypass valve, and close the TGCU Quench Column inlet valve. Since the TGCU Start-Up Blower bypass valve is open when the blower is not operating, this gives the process gas a path to flow to the Thermal Oxidizer. The TGCU Reactor effluent will then be diverted to the Thermal Oxidizer and cannot cause problems in the TGCU columns if SO2 escapes from the reactor. Once the upset has been corrected and gas flow into the columns can be re-initiated by increasing the output on the Quench Column bypass hand controller in the DCS to 100% output to restore flow to the columns. These changes should be performed slowly enough to minimize the "bobbles" on the air:acid gas ratio control in the SRUs, as the operating pressures in the units will change as the valves are
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SULFUR BLOCK repositioned. Operator judgment should be used to determine whether the process upset or the diversion of the process gas will have the worse impact on TGCU operation and the duration of non-compliance due to SO2 emissions from the Thermal Oxidizer.
11.6.7
TGCU Contactor Operation The main requirement for the TGCU Contactor is to consistently produce a vent gas for incineration which contains a low level of residual H2S. Secondarily, a good degree of CO2 "slip" (rejection) to the vent gas is desirable to minimize CO2 buildup due to the recycle of acid gas to the upstream Claus sulfur plant. The important parameters for controlling the H2S content of the TGCU Contactor vent gas, assuming the amine is adequately stripped, are amine temperature, amine flow rate, and contact time. The design values for amine temperature and flow rate shown on the Process Flow Diagram should give satisfactory operation, but it is possible to adjust these values either to maximize the capacity of the system to tolerate upsets, or to optimize the "slipping" of CO2 to the vent gas. The following discussion should be helpful if improving plant operations is desired. The single most important factor determining the H2S-absorbing capacity of the amine is its temperature. The lower the temperature of the amine, the more favorable is its selectivity for absorbing H2S over CO2. In fact, lowering the amine temperature has a two-fold effect on improving its ability to absorb H2S. First, at lower temperature the partial pressure of H2S in the amine is lower, allowing the amine to treat the gas to a lower H2S content (since the vent gas approaches equilibrium with the amine in the top of the TGCU Contactor). Second, the higher selectivity at the lower temperature means the amine picks up less CO2, resulting in less heat of reaction and less temperature rise in the column, increasing the ability of the amine to pick up H2S. Thus, the best possible operation results when both the gas and the amine fed to the TGCU Contactor are as cool as possible. For this reason, many operators leave the quench water and amine coolers at full capacity so that the coolers provide maximum cooling year-round. As would be expected, keeping the amine circulation rate at its maximum value gives the amine system the highest capacity to handle H2S "peaks" due to upsets in the upstream systems. It may not be immediately apparent, however, that high circulation rates are detrimental to amine
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SULFUR BLOCK performance when plant throughput is lower. Circulating more amine than necessary increases the amount of CO2 absorbed by the amine by increasing the contact time in the TGCU Contactor. This increase in CO2 pickup reduces the ability of the amine to pick up H2S. In general, most companies favor operating TGCU amine systems to provide maximum ability to tolerate upsets without going out of compliance. These companies adhere to the following guidelines: (1)
Circulate amine at maximum capacity.
(2)
Cool the quench water and amine as much as possible.
The amine strength should be monitored and the amine content of the circulating amine should be maintained close to the 45% (by weight) design value. Should the amine concentration decrease (normally due to blowdown and other amine losses), it will be necessary to add fresh amine to compensate. Laboratory procedures for analyzing TGCU amine are given in Section 11.10 of these guidelines. The amine should also be checked periodically for heat-stable salt content. Heat-stable salts form when the amine in the amine (a base) reacts with strong acids to form salts that do not decompose at the normal amine regeneration temperature. The most common heat-stable salts encountered in TGCU amine systems are SO2 salts, although oxygen contamination of the amine is another common culprit for heat-stable salts in these systems. Heat-stable salts increase the corrosivity of the amine (particularly at higher temperatures, like in the TGCU Stripper Reboiler) and increase the foaming tendencies of the amine. (Interestingly, heat-stable salts sometimes improve the H2S-removal capability of the amine, but the higher corrosion rate caused by the salt far outweighs this advantage.) A heat-stable salt content of 2 wt % or lower is desirable. Salt contents in the 5-20 wt % range can be corrosive and should be avoided if possible. The only way to reduce the heat-stable salt content of the amine is by dilution, blowing down some of the circulating amine and making up with fresh amine. There is no means for regenerating heat-stable salt from the amine while it is in the TGCU, as vacuum distillation is required. (In recent years, however, several companies have successfully reclaimed amine on-line using ion exchange on a slipstream of the amine.) There are firms that specialize in reclaiming amine (usually off-site), and it may be economical to use such a firm if a large amount of amine has been
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SULFUR BLOCK contaminated with heat-stable salts. The best practice, however, is to avoid forming heat-stable salt in the first place by proper operation of the SRU and TGCU to avoid SO2 breakthrough from the TGCU Reactor, and gas-blanketing the fresh amine to avoid oxygen contamination. The H2/H2S analyzer on the TGCU Contactor overhead, measures the concentrations of both H2 and H2S in the vent gas leaving the TGCU Contactor. As such, it is an extremely useful troubleshooting and optimizing tool for the TGCU. This analyzer should be maintained and calibrated at appropriate intervals so that it will be on-line and available to the operators. The H2S concentration is particularly useful when trying to pinpoint the cause of high SO2 emissions from the Thermal Oxidizer, as the TGCU Contactor is not the only possible source of high emissions. There are several valves in the SRU and the TGCU that can allow process gases with high sulfur content to reach the Thermal Oxidizer if the valves leak or are not fully closed. If the SO2 emissions from the Thermal Oxidizer are high but the analyzer shows low H2S content in the TGCU Contactor overhead, then a leaking valve is the most likely source of the excessive sulfur reaching the Thermal Oxidizer. In particular, the automated bypass valves in the TGCU may open slightly if their positioners or actuators are not properly adjusted, or if sudden changes in ambient conditions cause the positioners to move the valves slightly. If this situation occurs, it is suggested (as the first step in troubleshooting the problem) that the following valves be "stroked" slightly (in the order given below) to be sure that they are fully closed:
Issued 30 August 2011
(1)
A2-NV15800
The TGCU Warmup/Bypass Valve can leak SRU tailgas directly to the Thermal Oxidizer.
(2)
A2-HV15851
If the TGCU Start-Up Blower is not operating and A2-HV15853 is open ("normal" mode operation), the TGCU Quench Column Bypass Valve can leak TGCU Reactor effluent directly to the Thermal Oxidizer.
(3)
A2-HV15457 A2-HV15657
The Tailgas Valve to the TTO can leak SRU tailgas directly to the Thermal Oxidizer.
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK (4)
A2-HV15441/641 A2-HV15454/654
The SRU Warmup Bypass Valves to the TTO can leak SRU process gas directly to the Thermal Oxidizer if the nitrogen purge fails or is inadequate.
Check the SO2 emissions after stroking each valve. If the emissions are still high after checking all the valves, then verify that both the H2S analyzer and the SO2 analyzer are calibrated properly. If these valves are not leaking, there is usually no obvious reason why these two analyzers should show a discrepancy in the sulfur content of the TGCU effluent. In such cases, a systematic sampling program is usually required to isolate the source of the sulfur entering the Thermal Oxidizer. This sampling program need not be elaborate, as gas detector tubes for H2S and SO2 (such as Dräger tubes) are often sufficient for this purpose. The main point is to start at the TGCU Contactor overhead and work toward the Thermal Oxidizer, taking gas samples at each spot where gas may enter the line, in order to determine when the sulfur content goes up and isolate the source of the sulfur. Some detective work may still be necessary, however, as there may not be sample points available at every location. If so, and if there are several episodes of high emissions requiring this type of sampling, consideration should be given to installing additional sample points during the next plant turnaround.
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 11.6.8
TGCU Stripper Operation The lean amine must remain comparatively free of H2S and CO2 to assure attainment of the vent gas specification. These acid gases are removed from the rich amine in the TGCU Stripper by stripping them out with steam. The stripping steam supplies heat to reverse the acid-base reaction between the H2S/CO2 and the amine, and also reduces the H2S/CO2 partial pressure in the vapor phase inside the column to promote mass transfer from the liquid. The stripping steam is produced by vaporizing some of the water in the amine in the TGCU Stripper Reboiler, using LP (3.5-4.2 kg/cm2(g)) steam for the heat input. The steam rate to the reboiler (and, hence, the amine stripping rate) is controlled by the steam flow controller. Adjust this steam rate as needed to keep the H2S and CO2 loading in the lean amine low, i.e., below about 0.005 mole/mole or lower. For a given column operating pressure, the overhead temperature is a direct indication of the stripping rate: the higher the temperature, the more stripping. Column bottoms temperature should not be used as a guideline for degree of stripping, as it is a function only of amine concentration and column pressure.
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
CAUTION THE DESIGN STRIPPING STEAM RATE SHOWN ON THE PROCESS FLOW DIAGRAM SHOULD BE CLOSE TO OPTIMUM. ALTHOUGH IT MAY BE POSSIBLE TO REDUCE THIS SOMEWHAT WITHOUT GOING OUT OF COMPLIANCE (I.E., WITH LITTLE CHANGE IN THE H2S LOADING OF THE LEAN AMINE), REDUCING THE STRIPPING STEAM RATE SIGNIFICANTLY CAN CAUSE ACCELERATED CORROSION DUE TO HIGH CO2 LOADINGS IN THE LEAN AMINE. SEVERAL PLANTS HAVE REPORTED UNEXPECTEDLY HIGH CORROSION RATES IN THE HOT, HIGH VELOCITY AREAS OF THE LEAN AMINE SYSTEM, SUCH AS THE OUTLET ENDS OF THE REBOILER TUBES AND THE LEAN AMINE PUMPS, AFTER REDUCING THE REBOILER STEAM. IF IT IS NECESSARY TO OPTIMIZE THE STEAM TO THE TGCU STRIPPER REBOILER, REDUCE THE STEAM BY SMALL INCREMENTS AND CHECK THE LEAN AMINE LOADINGS (BOTH H2S AND CO2) AFTER EACH CHANGE. DO NOT REDUCE THE STEAM FURTHER IF EITHER LOADING BEGINS TO RISE SIGNIFICANTLY, AND BE PREPARED TO PERFORM MORE EXTENSIVE CORROSION MONITORING WHEN OPERATING THE TGCU STRIPPER IN THIS MANNER. REFER TO SECTION 11.10 OF THESE GUIDELINES FOR THE PROCEDURES TO BE USED TO DETERMINE THE LEAN AMINE LOADINGS. The withdrawal of lean amine from the bottom of the TGCU Stripper is on flow control to the TGCU Contactor. As a result, the level in the bottom of the TGCU Stripper, which serves as the "surge" for the system, will usually indicate if adjustments of water makeup to the amine system (or water "bleed" from the system) are required to maintain the proper water balance. Even if water must be bled from the system by diverting some of the column reflux to The SWS Flash Drum, the amine content of that waste stream should be low and only infrequent makeup of fresh amine should be required. It may also be necessary to "purge" ammonia from the reflux water periodically by routing some of the reflux water to the Sour Water Stripper.
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK Although the two-zone Reactor Furnaces in the SRUs will normally destroy almost all of the ammonia entering with the SWS gas, PPM levels of ammonia will typically leave the furnace and enter the TGCU with the sulfur plant tailgas. This ammonia is usually removed by the circulating water in the TGCU Quench Column, where it has the beneficial effect of helping maintain a high pH in the quench water. In fact, ammonia (rather than caustic) is used for pH control in many TGCUs. Over a period of time, however, some of the ammonia may carry over into the TGCU Contactor and dissolve in the TGCU amine. When this ammonia-containing amine reaches the TGCU Stripper, the ammonia becomes "trapped" because it is too light (volatile) to leave in the column bottoms and too heavy to leave in the overhead (the acid gas). As a result, the ammonia will become concentrated in the reflux water, to the point where it exceeds its solubility limits and begins to cause plugging problems. If this problem is suspected, simply "bleed" a small amount of the reflux water to the disposal header to purge the ammonia from the system, while monitoring the reflux flow rate to ensure that adequate reflux is maintained to the TGCU Stripper. Operating experience will show how often (and how much) the reflux must be purged in this manner to prevent excessive ammonia concentrations for a particular plant. Due to the moderate temperatures and fluid velocities typical for this section of the plant, wet H2S-NH3 corrosion is usually not a concern. There is full-flow of rich amine through the TGCU Rich Amine Filter, and a slipstream of lean amine flow through the TGCU Lean Amine Filter, the TGCU Amine Carbon Filter, and the TGCU Amine After-Filter. These four filters will remove solids and organic contaminants from the circulating amine, such as degradation or corrosion products. The flow rate through the lean amine filters should be maintained at the design value, and the filter elements should be changed as soon as the "change" pressure drop is reached, to remove as many solids from the amine as possible. Finely divided solids can cause foaming and thereby limit column capacity. While it is possible to reduce foaming to some extent with anti-foam agents, the presence of such agents may also reduce H2S/CO2 selectivity in the TGCU Contactor, so it is preferable that they not be used as an alternative to regular conscientious filter maintenance
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 11.6.9
TGCU Amine Water Balance The water content of the circulating amine in a TGCU is determined by the following factors: A.
The water content of the feed gas to the TGCU Contactor (the overhead from the TGCU Quench Column).
B.
The water content of the vent gas leaving the TGCU Contactor.
C.
The water content of the TGCU recycle gas leaving the TGCU Stripper Reflux Accumulator.
D.
The amount of water makeup to (or water "bleed" from) the amine system.
For given operating pressures, the water content of each gas stream will be determined by the temperature at the top of the respective vessel (TGCU Quench Column, TGCU Contactor, and TGCU Stripper Reflux Accumulator, respectively), and will increase as the temperature increases. Since the TGCU Contactor inlet gas is at a slightly higher pressure than the outlet (vent) gas, the inlet gas will normally contain less water than is contained in the outlet gas (if both gas streams are at the same temperature), thus requiring water makeup to maintain the proper water content of the amine. This situation will be reversed if the TGCU Contactor overhead temperature is lower than the TGCU Quench Column overhead temperature, requiring a "bleed" of water to maintain water balance. Since the lean amine to the TGCU Contactor is on flow control and withdrawal of the rich amine from the bottom of the TGCU Contactor is on level control, a net gain or loss in the amine water balance will be reflected by an increase or decrease, respectively, of the liquid level in the bottom of the TGCU Stripper. Observation of this liquid level can thus guide adjustment of water makeup/bleed rate or operating conditions to maintain the desired water concentration of the circulating amine. Since the degree of H2S removal can depend on the amine concentration of the amine, the concentration should be maintained close to the design value (45 wt %) by appropriate maintenance of water concentration. It is usually possible to control the water balance without adding fresh water or "bleeding" water to the Sour Water Stripping Unit by adjusting the operating temperatures in the unit, as discussed in the following paragraphs. Following the steps outlined below will allow controlling the water balance with minimum
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK usage of treated makeup water and minimum impact on the sour water system. A persistently increasing liquid level in the bottom of the TGCU Stripper at constant flow rates and conditions for TGCU Contactor feed gas and amine indicates a gain in the amine water content. To reduce the water content of the amine, the preferred sequence of gradual adjustments is: A.
Reduce or terminate water makeup to the amine. Makeup water is steam condensate, added at the TGCU Stripper Reflux Accumulator. (1)
Decrease the TGCU Contactor feed gas temperature by lowering the quench water temperature on the quench water temperature controller and/or increasing the quench water flow rate on the quench water flow controller. This will reduce the amount of water entering the TGCU Contactor, but the magnitude of adjustment available from this step will generally be limited by the capacity of the aerial and trim water coolers.
(2)
Begin "bleeding" water (or increase the "bleed" water rate) from the amine system with the flow controller on the discharge line of the TGCU Stripper Reflux Pump. Be careful, however, not to starve the TGCU Stripper for reflux by withdrawing too much water. Use the DCS flow indicator for the reflux water to monitor the operation so that adequate reflux is maintained to the TGCU Stripper when bleeding water from the amine system.
CAUTION
UNDER NORMAL CONDITIONS, THE REFLUX WATER CONTAINS LITTLE OR NO AMINE BECAUSE OF THE "WASH WATER" TRAYS ABOVE THE SOLVENT FEED TRAY IN THE TGCU STRIPPER. HOWEVER, IF THE TGCU STRIPPER IS FLOODING OR FOAMING (AS INDICATED BY HIGH OR ERRATIC COLUMN DIFFERENTIAL PRESSURE), THE REFLUX CAN CONTAIN LARGE AMOUNTS OF AMINE.
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK IF THE "BLEED" WATER LINE IS IN USE AT SUCH TIMES, A SIGNIFICANT QUANTITY OF SOLVENT CAN BE LOST TO THE SOUR WATER SYSTEM, AND WILL HAVE TO BE REPLACED WITH FRESH AMINE FROM THE STORAGE TANK. FOR THIS REASON, THE "BLEED" WATER SYSTEM SHOULD BE BLOCKED-IN DURING UPSETS IN THE TGCU STRIPPER. (3)
Increase the TGCU Contactor overhead temperature by raising the setpoint of the lean solvent temperature controller to increase the lean solvent temperature. This will increase the amount of water leaving in the vent gas, but it will also reduce the H2S-removal capability of the solvent. An increase in solvent flow rate will probably be needed to maintain the same H2S content in the vent gas, increasing the load on the TGCU Stripper and the other process equipment associated with the circulating solvent. Additionally, some impairment of the CO2 "slip" by the solvent would be expected as a result of both the higher contact temperatures in the TGCU Contactor and the higher solvent circulation. This will increase the CO2 recycled to the sulfur plants and increase the CO2 content of the tailgas to the TGCU, further hampering the H2S-removal capability of the solvent.
(4)
Increase the TGCU recycle gas temperature by increasing the temperature setpoint of the reflux temperature controller to raise the outlet temperature from the TGCU Stripper Reflux Condenser. Although this will increase the water content of this stream and reduce the water in the solvent, the effect will be small because the quantity of recycle gas is small relative to the vent gas, and the pressure of the recycle gas is considerably higher. This adjustment is the least effective and would not normally be considered during routine operations.
(5)
Issued 30 August 2011
Should the solvent inventory be difficult to control due to continuing problems with an excessive amount of water in the solvent, the steam-heated TGCU Stripper Reboiler should be checked for tube leaks.
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK B.
Conversely, a persistently decreasing liquid level in the bottom of the TGCU Stripper indicates a loss in the solvent water content. To increase the water content of the solvent, the preferred sequence of gradual adjustments is: 1.
Reduce or terminate the "bleed" water from the TGCU Stripper Reflux Accumulator.
2.
Decrease the TGCU Contactor overhead temperature by lowering the lean solvent temperature with the lean solvent temperature controller to reduce the amount of water leaving in the vent gas.
3.
Decrease the TGCU recycle gas temperature with the aerial cooling from the TGCU Stripper Reflux Condenser to reduce the water loss in the stream as much as possible.
4.
Begin water makeup (or increase the makeup water rate) to the solvent system using the make-up flow controller to add condensate to the TGCU Stripper Reflux Accumulator. The TGCU Stripper Reflux Pump will then send the makeup water to the TGCU Stripper, increasing the water content of the TGCU solvent. Be careful, however, to regulate the makeup rate so that the temperature to the pump does not become hot enough to cause cavitation. Also, make sure that the makeup water rate is not so high that the pump cannot keep up, which would cause high level in the TGCU Stripper Reflux Accumulator. Experience will show how quickly condensate can be added without causing pumping or level problems.
5.
Increase the TGCU Contactor feed temperature by increasing the temperature of the quench water feeding the TGCU Quench Column by raising the setpoint of the quench water temperature controller. This will increase the water content of the gas entering the TGCU Contactor, but it also increases the vapor load and hampers H2S removal, so this step should not be taken to extremes.
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 11.6.10 TGCU Amine Loss At the low process temperatures and low amine loadings normally prevailing in the TGCU process, the loss of MDEA by chemical degradation is expected to be negligible. Amine degradation can occur, however, under abnormal operating conditions. Amine degradation can occur via reaction with SO2, which can enter the TGCU Contactor during periods when insufficient reducing gas is fed to the TGCU Reactor. During such periods, most of the SO2 "breaking through" the TGCU Reactor should be scrubbed out in the TGCU Quench Column. However, any traces of SO2 entering the TGCU Contactor will react with the MDEA to form a thermally non-regenerable complex (i.e., heat-stable salt). If present in sufficient quantity, this salt can alter the H2S-amine equilibrium and prevent removal of H2S to the desired level in the TGCU Contactor overhead. Heat-stable salts also increase the corrosivity of the TGCU amine. Amine quality can be restored by treatment with an amount of caustic equivalent to the non-regenerable salt present but, if repeated caustic treatments are necessary due to repeated mal-operation, the potential for salt deposition in the system may rise. The equipment in the TGCU, including the seals of pumps and blowers, should be operated at positive pressure to minimize the potential for oxygen (air) ingress into the amine. Oxygen will react with the amine to produce carboxylic acids that cause the solution to be corrosive. For this same reason, it is important to maintain an inert gas "blanket" on the MDEA storage tank to prevent oxygen contamination of the fresh amine. Amine losses due to entrainment in the vent gas or the recycle gas can be minimized by proper process operation (avoidance of column overloading, foaming, etc.) and routine inspection of the vessel internals. Amine losses in the water "bleed" from the TGCU Stripper reflux should be negligible if the rectifying trays (the "wash water" trays above the amine feed point) in the TGCU Stripper are operating properly (no flooding or foaming, no mechanical damage). The primary source of amine loss will likely be the mechanical losses from pump drips, cleaning of filters, etc. Good housekeeping practices, including prompt replacement or repair of leaking pumps, together with proper collection of amine drips for reuse will minimize the mechanical loss of amine.
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 11.6.11 Operation at Low Flow Rates As discussed in the Sulfur Recovery Unit section of these guidelines, operating the SRUs at low flow rates (below about 20-25% of design load) can lead to several operating problems in the sulfur plant. It can also cause poor column performance in the TGCU. The TGCU contains three columns: the TGCU Quench Column and the TGCU Contactor, which contain structured packing; and the TGCU Stripper, which contains valve trays. In general, the liquid feed rate to packed towers can decrease in proportion with the gas flow rate down to about 50% of design gas flow rate. Below this point, the liquid rate cannot be allowed to drop any further without risking poor column performance due to uneven liquid distribution and wetting of the packing. Trayed towers typically offer somewhat better turndown, allowing the liquid rate to drop to 30-40% of design before "weeping" of the trays begins to significantly affect performance. At a total acid gas feed rate of 14 MT/D (of contained sulfur) to the SRUs, the gas flow rates to the TGCU Quench Column and the TGCU Contactor will be about 40% of design. In the case of the TGCU Quench Column, simply setting the quench water flow rate to the column at about 50% of design should maintain adequate performance. (It should be noted, however, that there is really no detrimental effect if the quench water circulation is simply left at the design value at all times. The only drawback is slightly higher power consumption by the pump and aerial cooler.) In the packed TGCU Contactor, circulating more amine relative to the gas flow rate should maintain performance. The liquid flow rate should be maintained at a minimum of about 50%. This higher amine circulation also has the advantage of absorbing more CO2 from the TGCU Contactor feed, which is subsequently stripped from the amine and recycled back to the SRUs. While TGCUs are normally operated to minimize CO2 pickup, increasing the CO2 pickup in this situation is advantageous. It raises the mass flow rate in the SRUs and the TGCU, minimizing the operating problems throughout the SRU/TGCU systems by preventing sulfur fog formation in the Sulfur Condensers. A higher circulation rate also means the TGCU has more capacity to remove H2S from the amine, making it less likely that SRU upsets will cause SO2
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK emissions to exceed permit limits. It will also keep the TGCU Stripper trays well above their minimum operating rate.
11.6.12 Pressure Drop Surveys A commonly encountered problem in TGCUs (and sulfur plants and Thermal Oxidizers) is a flow restriction due to high pressure drop. High pressure drop is typically caused by a restriction at one point in the equipment or piping, due to: 1.
Accumulation of liquid (sulfur, etc.) in equipment or piping
2.
Partial plugging of a catalyst bed (soot, carbon, polymers, etc.)
3.
Partial plugging of a mist eliminator (sulfur, soot, catalyst, etc.)
4.
Partial plugging of the packing and/or trays in a column
5.
Flooding or foaming in a column
The first step in identifying the cause of the high pressure drop is to determine which equipment pass or section of piping contains the restriction. (It is unusual to have more than one area of high pressure drop.) This is best accomplished by making a pressure survey of the process side of the TGCU (and the SRUs and Thermal Oxidizer, if necessary). Due to the low operating pressure in the TGCU (generally 0.3 kg/cm2(g) or less) and the low pressure drop in each equipment pass (generally 0.00-0.04 kg/cm2 per pass), a single pressure gauge must be used to make the pressure survey in order to get meaningful results. The gauge should be a low pressure gauge for best results (a -1 - 0 - +1.5 kg/cm2 gauge is recommended). Beginning at the front end of the TGCU, use the pressure tap valves on the inlet and outlet lines from each equipment pass to measure the pressure at each point in the process. Proceed toward the back end of the process until the pass with the high pressure drop is found. Note that some of the pressure tap valves may be plugged with solid sulfur. Rod-out the sample valves as necessary to obtain an accurate pressure reading.
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK
WARNING ALWAYS OBSERVE PROPER PROCEDURES AND PRECAUTIONS WHEN USING THE PRESSURE TAP VALVES, PARTICULARLY IF THE VALVES ARE PLUGGED AND MUST BE CLEARED. ALTHOUGH THE VALVES ARE ORIENTED TO MINIMIZE THE POSSIBILITY OF FILLING WITH MOLTEN SULFUR, HOT SULFUR MAY SUDDENLY BE EXPELLED FROM A VALVE WHEN THE PLUG IS CLEARED. RELEASE OF TOXIC GASES (H2S AND SO2, IN PARTICULAR) IS ALSO A POSSIBILITY. THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES SHOULD BE CONSULTED IF THERE IS ANY DOUBT ABOUT HOW TO WORK SAFELY WHEN H2S, SO2, OR MOLTEN SULFUR MAY BE PRESENT. When troubleshooting problems of this nature, it is very helpful to have pressure survey information taken previously when the unit was operating properly. It is recommended that one or more pressure surveys be performed early in the operating life of the plant, for comparison purposes later if problems are encountered. Since the pressure drop of the TGCU is a function of plant throughput (pressure drop is roughly proportional to flow rate squared), it is even more helpful for troubleshooting purposes if the early pressure surveys are performed at different plant throughput rates. It is also important to record the gas flow rates to the SRUs (amine acid gas, SWS gas, process air) and the TGCU (reducing gas) during the pressure survey, since pressure drop depends so strongly on plant throughput.
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea
SULFUR BLOCK 11.6.13 Boiler Water Treatment SAMSUNG TOTAL PETROCHEMICALS CO., LTD. IS RESPONSIBLE FOR ESTABLISHING AND MONITORING THE BOILER AND WATER CHEMICAL TREATMENT PROGRAM. Proper boiler water chemical treatment is essential to achieving long service life for the TGCU Waste Heat Reclaimer. Without good day-to-day control of the water quality, solids buildup, corrosion, and attack by the treating chemicals themselves can occur. It is Samsung Total Petrochemicals Co., Ltd.'s responsibility to see that a proper chemical treating program is initiated prior to startup and that the program is properly monitored and refined throughout the service life of the plant. There are many qualified boiler and water treatment companies that can advise the owner/operator on chemical treatment testing and controls. It is recommend that only those companies that have local technicians with extensive experience specifically in boiler water treatment be selected to assist with Samsung Total Petrochemicals Co., Ltd.'s program. The design details incorporated in the TGCU Waste Heat Reclaimer have proven to be very reliable when combined with good operator practice regarding water treatment. However, even properly designed equipment can be severely damaged during a short period of operation if the water treatment program is inadequate or improper. The TGCU Waste Heat Reclaimer is equipped with a continuous blowdown valve to remove suspended and dissolved solids from the water inside the boiler. In addition, this boiler is equipped with an intermittent blowdown valve. The intermittent blowdown valve should be used on a regular basis to give the boiler a good "blow" to prevent sludge from accumulating in the bottom of its shell. Prior to using the intermittent blowdown valve, use the level controller in the DCS to raise the water level in the boiler up to the high level alarm point. Then open the intermittent blowdown valve until the level drops back to the normal liquid level. Watch the boiler level in the sight glass throughout this operation to ensure that the level is not lost (which would activate the TGCU ESD and shut the TGCU down). Remember to reset the level controller at the conclusion of this procedure.
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SULFUR BLOCK
11.7 Precommissioning Procedures Prior to the initial startup, there are a number of precommissioning activities that are necessary to ensure that the newly constructed plant is ready to be placed in service. The activities outlined below should serve as a guide, but there may be others required as a part of your normal plant procedures.
11.7.1
Preliminary Check-out Check all equipment to ensure that it is properly installed. This will probably require consulting Manufacturer's literature as well as construction drawings.
Issued 30 August 2011
A.
Check and lubricate all equipment, in accordance with the Manufacturer's recommendations.
B.
Check the rotation of the TGCU Start-Up Blower by operating it for a short period (20 seconds or less) with its suction and discharge valves closed:
C.
Check the rotation of the following pumps by "bumping" them: (1) (2)
TGCU Quench Water Pump. TGCU Rich Amine Pump.
(3) (4)
TGCU Stripper Reflux Pump. TGCU Lean Amine Pump.
D.
Check the rotation of the fans on the TGCU Quench Water Cooler, the TGCU Lean Amine Cooler, and the TGCU Stripper Reflux Condenser, by operating each fan for a short period.
E.
Check all piping and equipment to be sure that all blinds have been removed and that no valves are vented to atmosphere.
F.
Place the Instrument Air System in service to all instruments and check the action of controllers and control valves.
G.
Turn on the steam supplies to all of the steam-jacketed sulfur vapor valves and use the vent valves on each jacket section to vent the air from the jackets. Manually "stroke" each valve and check to be sure each move freely.
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SULFUR BLOCK 11.7.2
Issued 30 August 2011
Shutdown System Check-out A.
Fill the TGCU Waste Heat Reclaimer with treated boiler feed water up to the high level alarm point. As the level rises, check the level transmitters and the high level alarms for proper operation.
B.
Use the quick-opening blowdown valve to lower the water level in the boiler and check for proper operation of the level transmitters, the low level alarms, and the low-low level shutdowns.
C.
Fill the boiler with treated boiler feed water back up to the normal liquid level.
D.
Physically check all shutdown activating devices to ensure that they activate the TGCU ESD system.
E.
Physically check all devices activated by the TGCU ESD system to ensure that they operate properly.
F.
Check all relief valves to ensure that they are installed in the proper locations and set for the correct relieving pressures.
G.
The low-low level shutdowns for the pumps in the quench water and amine systems will be tested while washing these systems as described in the following sections.
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SULFUR BLOCK 11.7.3
Commissioning Nitrogen and Utility Air to the Process The nitrogen and utility air supplies to the process side of the TGCU must be made ready for use prior to starting up the TGCU using the procedures in Section 11.8 of these guidelines. This requires blowing down each section of piping to ensure that there are no liquids and/or construction debris in the headers and supply lines. The procedure below can be used to make sure that these gas utility systems are ready for service.
Issued 30 August 2011
A.
Place the utility air controller in the DCS in "manual" and set its output to 0%.
B.
Place the nitrogen controller in the DCS in "manual" and set its output to 0%.
C.
Confirm that the following nitrogen and utility air valves are closed: (1)
The upstream block valve, flow control valve, and the downstream block valve in the nitrogen supply line.
(2)
The upstream block valve, flow control valve, and the downstream block valve in the utility air supply line.
(3)
The automated block valves, and the steam-jacketed block valve in the common nitrogen / air line.
(4)
The block valve in the HP nitrogen supply line located near the TGCU Reactor.
(5)
The gate valves upstream and the ball valves downstream of the flow indicators in the purges to the sensing lines for the TGCU Reactor d/P transmitter.
(6)
The ball valves in the sensing lines for the TGCU Reactor d/P transmitter.
(7)
The gate and ball valves in the purge line to the shaft seal on the TGCU Start-Up Blower.
(8)
The gate valve in the LP nitrogen supply line, and the ball valve downstream of the flow indicator in the purge line to the TGCU Start-Up Blower discharge line.
(9)
The gate valve upstream of the flow indicator in the supply line to the sample switching valve for the H2/H2S analyzer.
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SULFUR BLOCK (10) The block valves in the nitrogen supply line to the TGCU Stripper Reflux Accumulator.
Issued 30 August 2011
D.
Confirm that all of the manual vent/drain valves in the nitrogen and utility air piping are closed.
E.
If the orifice plate has already been installed in the utility air flow meter, remove it for now
F.
If the orifice plate has already been installed in the nitrogen flow meter, remove it for now
G.
Disconnect the nitrogen and utility air from the tailgas line by performing the following steps: (1)
Unbolt the flanged connections at the steam jacketed block valve and "drop out" this valve.
(2)
Isolate and, if necessary, disconnect the steam supply and condensate return connections for this valve.
(3)
Cover the open end of the piping to prevent debris from entering when the upstream piping is blown down.
H.
Confirm that the H.P. nitrogen, L.P. nitrogen, and Utility Air supply headers have been placed in service, with the pressure regulators set properly and the safety relief valves in service, and with the main supply header piping blown down and drained.
I.
Rotate the spectacle blind in the utility air line to the "open" position.
J.
Remove the following pressure regulators, then cover the downstream piping to prevent debris from entering when the upstream piping is blown down: (1)
The utility air supply regulator.
(2)
The nitrogen supply regulator.
K.
"Force" the PLC to open the two nitrogen blocks, and close the nitrogen vent valve.
L.
Confirm that these automated valves have moved to the proper positions.
M.
"Crack" the upstream block valve in the main utility air supply line and allow air to blow through the piping until it is clear. Then close
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SULFUR BLOCK the block valve, reinstall the utility air supply pressure regulator, and reopen the block valve.
Issued 30 August 2011
N.
Using the utility air supply pressure regulator and the vent valve downstream of the pressure control valve, adjust the utility air regulator to the setpoint specified on the P&IDs.
O.
"Crack" the block valve in the main nitrogen supply line and allow nitrogen to blow through the piping until it is clear. Then close the gate valve, reinstall the nitrogen supply pressure regulator, and reopen the gate valve.
P.
Using the pressure gauge and the vent valve downstream of the nitrogen supply pressure regulator, adjust the nitrogen regulator to its specified setpoint.
Q.
Open the flow valve in the utility air line by setting the output of the flow controller to 100% in the DCS, then use the downstream drain valve to blow out this section of piping. Close the drain valve when the piping is clear.
R.
Open the flow valve in the nitrogen line by setting the output of the flow controller to 100% in the DCS, then use the downstream drain valve to blow out this section of piping. Close the drain valve when the piping is clear.
S.
"Crack" the block valve downstream of the flow valve and allow air to blow through the piping until it is clear. Then close the bock valve.
T.
Close the flow valve in the utility air line by setting the output of the flow controller to 0% in the DCS
U.
"Crack" the block valve downstream of nitrogen control valve and allow nitrogen to blow through the piping until it is clear. Then close the block valve.
V.
Close the control valve in the nitrogen line by setting the output of the flow controller to 0% in the DCS
W.
Remove the "forces" from the PLC and confirm that both of the automated block valves close and the automated vent valve opens.
X.
Close the upstream block valve in the utility air supply line.
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SULFUR BLOCK Y.
Rotate the spectacle blind in the utility air line to the "closed" position.
Z.
Close the upstream block valve in the nitrogen supply line until the TGCU unit is ready for startup.
AA. Reconnect the nitrogen / air piping by performing the following steps: (1)
Reinstall the steam jacketed block valve and bolt the flanged connections back together.
(2)
Reinstate the steam supply and condensate return piping.
(3)
If the steam system is already in service, establish steam flow into the jacket by opening the steam supply valve. Open the vent valve on the steam jacket long enough to vent the air from the jacket.
(4)
Reinstall the orifice plate in the utility air flow meter.
(5)
Reinstall the orifice plate in the nitrogen flow meter.
BB. Open the block valve in the utility nitrogen supply line located near the TGCU Reactor until the line is clear. CC. The TGCU Reactor d/P transmitter has low pressure purges for both of its sensing lines, each with a rotameter near where it connects to the sensing line. Disconnect the upstream fitting at each rotameter and briefly open its upstream gate valve to blow any liquids or debris from its purge line. Reconnect each rotameter, disconnect the fitting where each purge connects to the sensing line, open the upstream gate valve, and open the ball valve downstream of each rotameter briefly to blow any liquids or debris from the purge lines. Then reconnect each purge to the sensing line and open its valve to place it in service. DD. Disconnect the fitting where each sensing line connects to its process line, and open the ball valve in each sensing line briefly to blow any liquids or debris from the lines. Then reconnect each sensing line to its process line and open its ball valve to place it in service. NOTE: The two rotameters must be adjusted to the same flow rate so that the pressure drop of the purge gas in the sensing lines does not affect the reading of the d/P transmitter. One
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SULFUR BLOCK way to do this is to confirm that the equalizing valve on the d/P transmitter manifold is closed, set the rotameter on the upstream sensing line to a small flow rate (~0.8-1.6 Nm3/H), and then adjust the flow rate of the other rotameter until the meter reads zero d/P. EE. Disconnect the upstream fitting (in the purge line to the shaft seal on the TGCU Start-Up Blower) and open the upstream gate and ball valves briefly to blow any liquids or debris from the purge line. Reconnect the rotameter and disconnect the fitting where the purge connects to the shaft seal. Open the upstream gate valve, open the ball valve briefly to blow any liquids or debris from the purge line, then reconnect the purge to the shaft seal and open the ball valve to place it in service. FF. The nitrogen purge valve for the blower casing should already be open. Disconnect the upstream fitting (in the purge line to the TGCU Start-Up Blower discharge line) and open the upstream gate valve briefly to blow any liquids or debris from the purge line. Reconnect the rotameter and disconnect the fitting where the purge connects to the discharge line on the TGCU Start-Up Blower. Open the upstream gate valve, open the downstream ball valve briefly to blow any liquids or debris from the purge line, then reconnect the purge to the discharge line. GG. Re-open the ball valve downstream of the nitrogen purge valve and allow the nitrogen to pressurize the TGCU Start-Up Blower and the piping inside the suction and discharge block valves. Check all of the blower and piping connections for visible or audible signs of leakage (by applying masking tape or "Snoop" to the flanges, listening for other leaks, etc.). When done, leave the ball valve open so that the purge is in service. HH. Disconnect the upstream fitting (in the nitrogen supply line to the sample switching valves) and open the upstream gate valve briefly to blow any liquids or debris from the purge line. Reconnect the rotameter and disconnect the fitting where the purge connects to the sample selector valve on the H2/H2S analyzer. "Crack" the gate valve to blow nitrogen through the piping until it is clear. Then close the gate valve, reconnect the piping, and reopen the gate valve. II.
Issued 30 August 2011
Remove the nitrogen supply regulator to the Reflux Accumulator.
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SULFUR BLOCK JJ.
"Crack" the upstream block valve in the nitrogen supply line and allow nitrogen to blow through the piping until it is clear. Then close the block valve, reinstall the nitrogen supply pressure regulator, and reopen the block valve.
KK. Using the nitrogen supply pressure regulator and the vent valve downstream of the regulator, adjust the nitrogen regulator to the setpoint specified on the P&IDs
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SULFUR BLOCK 11.7.4
Commissioning Hydrogen to the Process The external hydrogen supply must be made ready for use prior to starting up the TGCU using the procedures in Section 11.8 of these guidelines. This requires blowing down each section of piping to ensure that there are no liquids and/or construction debris in the headers and supply lines. Because of the fire hazard associated with venting high-purity hydrogen, nitrogen should be used for the initial flushing of the hydrogen piping and for setting the pressure regulator. Once this is completed, hydrogen can then be used to check the setting of the pressure regulator by venting the hydrogen to a safe location using the bypass valve.
Issued 30 August 2011
A.
Place the hydrogen controller in the DCS in "manual" and set its output to 0%.
B.
Confirm that the following valves are closed: (1)
The two block valves upstream of the pressure regulator.
(2)
The reducing gas supply line automated block valves, the flow control valve, the isolation valve downstream of the control valve and the bypass valve around the control valve.
C.
Confirm that all of the manual vent/drain valves in the hydrogen piping are closed.
D.
If the orifice plate has already been installed in the hydrogen flow meter, remove it for now.
E.
Rotate the spectacle blind in the hydrogen supply line to the "closed" position.
F.
Disconnect the hydrogen piping from the line going to the TGCU Reactor Feed Mixer by performing the following steps: (1)
Unbolt the flanged connections at the steam jacketed block valve and "drop out" this valve.
(2)
Isolate and, if necessary, disconnect the steam supply and condensate return connections for this valve.
(3)
Cover the open end of the piping to prevent debris from entering when the upstream piping is blown down.
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SULFUR BLOCK
Issued 30 August 2011
G.
Remove the pressure regulator, then cover the downstream piping to prevent debris from entering when the upstream piping is blown down.
H.
"Force" the PLC to open the block valves in the hydrogen supply line, and close the vent valve.
I.
Confirm that these automated valves have moved to the proper positions.
J.
Use a temporary "jumper" to connect a nitrogen supply to the drain valve upstream of the pressure regulator.
K.
"Crack" the gate valve upstream of the pressure regulator and allow nitrogen to blow through the piping until it is clear. Then close the gate valve, reinstall the pressure regulator and reopen the gate valve.
L.
Using the pressure gauge and the vent valve downstream of the pressure regulator, adjust the hydrogen regulator to the setpoint specified on the P&IDs.
M.
Open the reducing gas supply line control valve by setting the output of the hydrogen controller to 100% in the DCS, then use the downstream drain valve to blow out this section of piping. Close the drain valve when the piping is clear.
N.
"Crack" the gate valve downstream of the reducing gas supply line control valve and allow nitrogen to blow through the piping until it is clear. Then close the gate valve.
O.
Close the reducing gas supply line control valve by setting the output of the hydrogen controller to 0% in the DCS.
P.
Briefly open the bypass valve around the control valve and allow nitrogen to blow through the piping until it is clean. Then close the bypass valve.
Q.
Remove the "forces" from the PLC and confirm that both of the automated block valves close and the automated vent valve opens.
R.
Close the gate valve where the nitrogen "jumper" is connected to stop the flow of nitrogen, and disconnect the nitrogen jumper.
S.
Reconnect the hydrogen piping by performing the following steps:
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SULFUR BLOCK
T.
Issued 30 August 2011
(1)
Reinstall the steam jacketed block valve and bolt the flanged connections back together.
(2)
Reinstate the steam supply and condensate return piping.
(3)
If the steam system is already in service, establish steam flow into the jacket by opening the steam supply valve. Open the vent valve on the steam jacket long enough to vent the air from the jacket.
(4)
Reinstall the orifice plate in the hydrogen flow meter.
(5)
Rotate the spectacle blind in the hydrogen supply line to the "open" position.
Confirm that the hydrogen pressure regulator is properly adjusted: (1)
Open the two gate valves upstream of the pressure regulator.
(2)
"Crack" the bypass valve to vent hydrogen to the flare. Adjust the pressure regulator if necessary to maintain its setpoint, observing the pressure on the pressure gauge.
(3)
Close the bypass valve, and the gate valve immediately upstream of the pressure regulator.
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SULFUR BLOCK 11.7.5
Leak Testing the Process Piping and Equipment
CAUTION
THE LOW PRESSURE PROCESS PIPING (PROCESS GAS AND SULFUR VAPOR) AND LOW PRESSURE PROCESS EQUIPMENT IN THE TGCU ARE NOT DESIGNED TO BE HYDROSTATICALLY TESTED. ONLY THE PIPING AND EQUIPMENT DOWNSTREAM OF THE TGCU CONTACTOR (THE SOLVENT AND STRIPPER SYSTEMS) ARE DESIGNED TO BE HYDROTESTED. USE THE FOLLOWING PROCEDURE TO LEAK-TEST THE REST OF THE TGCU. The process piping and equipment in the TGCU can be checked for leaks by using nitrogen to pressurize the process side of the equipment and piping to about 0.6-0.7 kg/cm2(g), then checking flanges, etc. for leaks (usually by applying masking tape or "Snoop" to the flanges, and by listening for other leaks). In order to pressurize the TGCU with nitrogen, it is necessary to block-in the unit by closing the outlet valve. This procedure requires some special preparations to operate in this manner, as detailed below. The Complete Flowpath Interlock (see Section 11.5.5.1 of these guidelines) must be temporarily disabled in order to operate the TGCU in this manner. The Leak Test toggle switch in the DCS is used to direct the PLC to bypass most of the unit shutdowns and to enable the on/off selector switch for the nitrogen. This means that "jumpers" on the limits switches or "forces" in the PLC are not necessary to perform this test. It also means that it is not necessary to have water in the TGCU Waste Heat Reclaimer during the test since the low-low water level S/D is also bypassed. This same procedure can be used to leak test the TGCU following maintenance, before restarting the unit. Whenever plant maintenance requires opening one or more of the flanged connections in the TGCU, it is good practice to leak test the unit before returning it to service. This allows detecting any leaking connections that may have resulted from the maintenance operations before tailgas is reintroduced into the unit.
Issued 30 August 2011
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SULFUR BLOCK To perform leak testing in a TGCU, proceed as follows: A.
Confirm that the nitrogen flow controller in the DCS is set to 0% output and that the control valve in the nitrogen supply line is closed.
B.
Confirm that the Quench Column inlet hand control in the DCS is set to 0% output so that the TGCU Quench Column Bypass Valve will open later in Step F when the Startup/Run selector switch is switched to "STARTUP".
C.
Confirm that the TGCU Quench Column is isolated from the quench water circulation loop by confirming that the following valves are all closed:
D.
Issued 30 August 2011
(1)
The bypass valve and downstream block valve at the quench water flow control valve.
(2)
The block valve downstream of the pH analyzer.
(3)
The suction valves at the TGCU Quench Water Pumps.
(4)
The drain valve on the suction line to the pumps.
(5)
The block valve in the caustic supply line at the tie-in to the suction line.
(6)
The block valve in the condensate fill line at the tie-in to the suction line.
(7)
The bypass valve and downstream block valve at the filtered quench water flow control valve.
Confirm that the TGCU Contactor is isolated from the solvent circulation loop by confirming that the following valves are all closed: (1)
The bypass valve and downstream block valve at the lean solvent flow control valve.
(2)
The suction valves at the TGCU Rich Amine Pumps.
(3)
The drain valve on the suction line to pumps.
(4)
The block valves in the solvent makeup line at the tie-in to the suction line.
(5)
The block valve and globe valve in the condensate makeup line at the tie-in to the suction line.
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SULFUR BLOCK E.
Confirm that the spectacle blind in the utility air supply line is in the "closed" position.
F.
Switch the Startup/Run selector switch, the Startup/Run selector switch, in the DCS to "STARTUP". The PLC should perform the following actions: (1)
Bypasses the SRU ESD inputs to the TGCU ESD.
(2)
Disables the Tailgas Valves transfer switches.
(3)
Opens the TGCU Quench Column Bypass Valve.
(4)
Enables the Leak Test Switch.
G.
Confirm that the SRU Tailgas Valves to the TGCU are closed.
H.
Confirm that the TGCU Start-Up Blower Bypass Valve is fully open.
I.
Confirm that the block valve(s), and the steam-jacketed block valve in the nitrogen supply line are open.
J.
Toggle the Leak Test Switch in the DCS to "ON". The PLC should perform the following actions: (1)
Bypasses the TGCU ESD to allow opening the nitrogen supply valves via the nitrogen on/off push-button.
(2)
Opens TGCU Warmup/Bypass Valve.
K.
Close the TGCU Outlet Valve.
L.
Toggle the Nitrogen On/Off switch, the nitrogen on/off push-button, in the DCS to "ON". The PLC should perform the following actions:
Issued 30 August 2011
(1)
Opens the nitrogen block valves.
(2)
Closes the nitrogen vent valve.
M.
Use the nitrogen flow controller in the DCS to open the nitrogen flow control valve and send nitrogen to the TGCU to begin pressurizing it.
N.
Slowly increase the output from the nitrogen flow controller until the pressure reaches 0.6-0.7 kg/cm2(g) as measured by the pressure indicator in the DCS.
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SULFUR BLOCK Due to the volume inside the TGCU, it will take several minutes for the pressure to build up in the unit. O.
Once the desired pressure has been achieved, set the output from the nitrogen flow controller to 0% to close the nitrogen flow control valve. Check all of the equipment and piping connections for visible or audible signs of leakage.
P.
Toggle the Nitrogen On/Off switch in the DCS to "OFF". The PLC should perform the following actions:
Q.
(1)
Closes the nitrogen block valves.
(2)
Opens the nitrogen vent valve.
Toggle the Leak Test Switch in the DCS to "OFF". The PLC will enable all of the ESDs for the TGCU again.
Issued 30 August 2011
R.
Open the TGCU Outlet Valve.
S.
Re-open valves as necessary to restore the quench water and solvent circulation loops that were isolated from the columns in Steps C and D earlier.
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SULFUR BLOCK 11.7.6
Washing the Quench Water System The following procedure is intended to remove grease, rust, scale, dirt, and trash from the equipment and piping in the quench water system before it is placed in operation. Washing of the system consists of three steps: an initial water flush to remove dirt and trash from the system; an acid wash to remove grease, rust, and scale; and a caustic wash to acclimate the equipment and piping to alkaline pH. Failure to clean the system properly prior to startup can lead to operating problems (heat exchanger fouling, rapid filter plugging, etc.).
WARNING
THIS PROCEDURE REQUIRES WORKING WITH ACIDIC AND ALKALINE CHEMICALS AND SOLUTIONS. EMPLOYEES MUST OBSERVE ALL APPLICABLE SAFETY PROCEDURES AND ENVIRONMENTAL REGULATIONS CONCERNING USAGE OF PERSONAL PROTECTIVE EQUIPMENT, HANDLING OF HAZARDOUS MATERIALS, DISPOSAL OF WASTE STREAMS, ETC.
11.7.6.1
Issued 30 August 2011
Water Flush A.
Place the quench water flow controller in the DCS in "manual" and set its output to 100% to fully open the quench water flow control valve.
B.
Place the TGCU Quench Column level controller in the DCS in "manual" and set its output to 0% to fully close the level control valve.
C.
Confirm that the Quench Column inlet hand control in the DCS is set to 0% output so that the TGCU Quench Column inlet valve is fully closed.
D.
Place the filtered quench water flow controller in the DCS in "manual" and set its output to 100% to fully open the filtered quench water flow control valve.
E.
Verify that the quench water flow control valve is fully open. Open both of its isolation block valves and its bypass valve.
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SULFUR BLOCK
Issued 30 August 2011
F.
Verify that the TGCU Quench Column level control valve is fully closed. Close both of its isolation block valves and its bypass valve.
G.
Verify that the TGCU Quench Column inlet valve is fully closed. (This will prevent water from entering the TGCU Reactor if the TGCU Quench Column is accidentally over-filled.)
H.
Verify that the filtered quench water flow control valve is fully open. Open both of its isolation block valves and its bypass valve.
I.
The TGCU Quench Water Filter will not be used to filter solids during this time, but the filter vessel and its piping are to be flushed and cleaned. Remove the filter elements, then bolt-up the filter. Open the inlet and outlet block valves on the filter, and open the bypass valve around the filter.
J.
Similarly, remove the elements from both pH Meter Sample Filters and reinstall the filter housings. Open the inlet and outlet block valves to the sample loop for the pH analyzer, and open the inlet and outlet block valves for both pH Meter Sample Filters.
K.
The probe on the pH analyzer, the pH analyzer, should not be installed until the quench water system has been cleaned and refilled, ready for service. Verify that a temporary plug has been screwed into the probe housing installed in the sample piping.
L.
Verify that the block valve in the caustic line is closed.
M.
Add water (steam condensate) to the bottom of the TGCU Quench Column through the condensate line.
N.
Once there is an adequate level in the column, all the way to the top of its level gauge open the suction valve on a TGCU Quench Water Pump and use its drain valve to be sure the pump is flooded with water. Start the pump, then open its discharge valve.
O.
Watch the level in the TGCU Quench Column while placing the pump in service to be sure the pump does not lose suction while filling the downstream piping and equipment. If the level
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SULFUR BLOCK disappears in the column, shut the pump down until enough condensate is added to reestablish the level, then restart the pump. P.
Once circulation is achieved and the level in the TGCU Quench Column is adequate (about halfway up in the level gauge), discontinue the addition of condensate.
Q.
Use the low point drain valves to flush out each section of the system. Leave the drain valves open until the water is clear.
R.
Briefly open the bypass valve on the TGCU Quench Column level control valve to flush this section of piping to The Sour Water Stripping Unit. Open the upstream block valve, open the TGCU Quench Column level control valve with the level controller in the DCS, and use the downstream drain valve to flush the control station. Once the flush water clears up, close the TGCU Quench Column level control valve and the upstream block valve.
S.
Circulate the water and blow down the low point drains until all of the drain water is clear. Add more condensate as necessary to maintain the level in the TGCU Quench Column. At some point during the washing procedure, the standby pump should be placed in service while the other pump is shut down. This will ensure cleaning out both pumps and their associated piping.
Issued 30 August 2011
T.
Once the drain water is clear, completely drain the system. Drain the system as quickly as possible, so that the water velocity helps to flush the solids from all parts of the system.
U.
Allow the pump to continue running while the system drains, but watch the pump closely to verify that the low-low level shutdown shuts the pump down below the shutdown setpoint. If the level drops completely out of the gauge glass before the pump shuts down, stop the pump manually and correct the problem with the low-low level shutdown before proceeding further.
V.
Verify that the caustic supply line has been flushed and is ready for service.
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SULFUR BLOCK 11.7.6.2
Acid Wash A weak (0.1 wt %) citric acid solution is used next to remove grease, rust, and scale from the equipment and piping. The citric acid will chelate with the iron in the rust and scale so that it dissolves in the solution.
11.7.6.3
A.
Use the condensate makeup line to reestablish a level in the TGCU Quench Column.
B.
Once a level is established, start a TGCU Quench Water Pump to begin circulating the water.
C.
Add concentrated citric acid to the circulating water to make a 0.1 wt % citric acid solution.
D.
After circulating for about 3 hours, start the other TGCU Quench Water Pump and shut down the first one.
E.
Circulate the solution for a total of about 6 hours, blowing down the low point drains occasionally. Add more condensate if necessary to maintain the level in the TGCU Quench Column.
F.
Briefly open the bypass valve on the TGCU Quench Column level control valve to flush this section of piping to The Sour Water Stripping Unit. Then open both block valves and use the level controller in the DCS to open the TGCU Quench Column level control valve briefly and flush the control station. Close the TGCU Quench Column level control valve and the block valves.
G.
After 6 hours, shut down the pump and completely drain the system. Drain the system as quickly as possible, so that the liquid velocity will help flush any remaining solids from the system.
Alkaline Wash The washing operation is completed by circulating a weak alkaline solution through the system. This will neutralize any citric acid left in the system, and acclimate the system to high pH operation so that no further scale is removed from the equipment and piping when the normal quench water (8.0-9.5 pH) is circulated.
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SULFUR BLOCK
Issued 30 August 2011
A.
Use the condensate makeup line to reestablish a level in the TGCU Quench Column.
B.
Once a level is established, start a TGCU Quench Water Pump to begin circulating the water.
C.
Adjust a TGCU Caustic Injection Pump to full stroke. Open the block valve at the tank, the suction block valve, and the discharge block valve on the pump. Start the pump, then open the block valve in the caustic line where it enters the suction line to the TGCU Quench Water Pump.
D.
Allow the pump to run for long enough to displace the water in the caustic supply piping (left from the earlier water flush procedure). Add caustic to the circulating water to make a 0.02 wt% solution. This should give a pH in the range of 11-22.
E.
Shut off the TGCU Caustic Injection Pump, and close the block valve in the caustic supply at the injection point in the quench water piping.
F.
Check the pH of the circulating water. If the pH is less than 11, add more caustic from the caustic makeup line until the pH is 11 or higher.
G.
After circulating for about 1 hour, start the other TGCU Quench Water Pump and shut down the first one.
H.
Circulate the solution for a total of about 2 hours, blowing down the low point drains occasionally. Add more condensate if necessary to maintain the level in the TGCU Quench Column.
I.
Briefly open the bypass valve on the TGCU Quench Column level control valve to flush this section of piping to the sour water header. Then open both block valves and use the level controller in the DCS to open the TGCU Quench Column level control valve briefly and flush the control station. Close the TGCU Quench Column level control valve and the block valves.
J.
After 2 hours, shut down the pump and completely drain the system. Drain the system as quickly as possible, so that the liquid velocity will help flush any remaining solids from the system.
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SULFUR BLOCK 11.7.6.4
Initial Water Fill The quench water system should now be clean and ready to place in service. All that remains is to refill the system with water and establish the proper operating conditions. This includes "pre-charging" the system with caustic to serve as a "buffer" so that the system pH does not drop suddenly when process gas is first introduced into the TGCU Quench Column and H2S from the gas dissolves in the water.
Issued 30 August 2011
A.
Close the inlet and outlet block valves on the TGCU Quench Water Filter, then install the proper element(s) in the filter. Leave the block valves closed for now.
B.
Close the inlet and outlet block valves on the pH analyzer sample loop, then install the proper elements in both pH Meter Sample Filters. Leave the block valves closed for now.
C.
Use the condensate makeup line to reestablish a level in the TGCU Quench Column.
D.
Once a level is established, start a TGCU Quench Water Pump to begin circulating the water.
E.
Place the Quench Water flow controller in the DCS in service and set its setpoint to its normal value. Close the bypass valve on the quench water flow control valve.
F.
Confirm that the TGCU Quench Column level control valve is closed, then open both of its block valves. Place the level controller in the DCS in service and set its setpoint to its normal value.
G.
Place the TGCU Quench Water Filter in service as follows: (1)
Open the vent valve on the top of the filter.
(2)
"Crack" the filter inlet block valve open slightly and allow the filter to fill with water. When the filter is full, close the vent valve.
(3)
Open the filter inlet block valve fully and open the outlet block valve, then close the filter bypass valve.
(4)
Place the filtered quench water flow controller in the DCS in service and set its setpoint to its normal value. Close
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SULFUR BLOCK the bypass valve on the filtered quench water flow control valve. H.
Adjust a TGCU Caustic Injection Pump to full stroke. Start the pump, then open the block valve in the caustic line where it enters the quench water piping.
I.
Allow the pump to run for a few minutes until the pH of the solution is in the range of 12-13.
J.
Shut off the TGCU Caustic Injection Pump and close its suction valve. Leave the block valve at the injection point in the quench water piping open.
K.
Install the pH analyzer probe in its housing in the sample loop, following the manufacturer's instructions. Place the analyzer in service by opening the block valves on one of the pH Meter Sample Filters (the block valves should be closed on the other filter) and opening the inlet and outlet valves on the sample loop. Observe the flow indicator to verify flow through the sample loop. Analyze a sample of the quench water to confirm that the pH analyzer is measuring the correct pH.
L.
Add additional caustic if necessary to adjust the pH to 11-13.
M.
Commence cooling water flow to the TGCU Quench Water Trim Cooler if it has not already been placed in service.
The quench water system is now ready for service. It can remain in this operating mode indefinitely while the rest of the TGCU is prepared for startup. Check the system periodically for indications of plugging, etc. (low flow, erratic pump discharge pressure, high filter pressure drop), as solid materials may accumulate at various points in the system over time.
11.7.7
Washing the Amine System The following procedure is intended to remove grease, rust, scale, dirt, and trash from the equipment and piping in the solvent system before it is placed in operation. Washing of the system consists of three steps: an initial water flush to remove dirt and trash from the system; an acid wash and rinse to remove grease, rust, and scale; and a weak amine wash and rinse to acclimate the equipment and piping to alkaline pH.
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SULFUR BLOCK Failure to clean the system properly prior to startup can lead to operating problems (column foaming, poor treating, heat exchanger fouling, rapid filter plugging, etc.).
WARNING
THIS PROCEDURE REQUIRES WORKING WITH ACIDIC AND ALKALINE CHEMICALS AND SOLUTIONS. EMPLOYEES MUST OBSERVE ALL APPLICABLE SAFETY PROCEDURES AND ENVIRONMENTAL REGULATIONS CONCERNING USAGE OF PERSONAL PROTECTIVE EQUIPMENT, HANDLING OF HAZARDOUS MATERIALS, DISPOSAL OF WASTE STREAMS, ETC.
11.7.7.1
Issued 30 August 2011
Water Flush A.
Place the following controllers in the DCS in "manual" with their outputs set as indicated:
(a)
Set the output from the lean solvent flow controller to 100% to fully open the lean solvent flow control valve.
(b)
Open the manual block valve upstream of the lean solvent filters.
(c)
Set the output from the TGCU Contactor level controller to 100% to fully open the TGCU Contactor level control valve.
(d)
Set the output from the TGCU Stripper Reboiler steam flow controller to 0% to fully close the steam flow control valve.
(e)
Set the output from the TGCU Stripper Reflux Accumulator level controller to 0% to fully close the TGCU Stripper Reflux Accumulator level control valve.
(f)
Set the output from the bleed water flow controller to 0% to fully close the bleed water flow control valve.
(g)
Set the output from the makeup water flow controller to 0% to fully close the makeup water flow control valve.
(h)
Set the output from the TGCU Stripper pressure controller, to 0% to fully close the pressure control valve.
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SULFUR BLOCK B.
Place the other TGCU Stripper pressure controller in "automatic" with a setpoint of 0.85 kg/cm2(g). This will open the pressure control valve to the flare if pressure builds in the TGCU Stripper during this procedure.
C.
Verify that the following control valves are fully open. Open both of the isolation block valves and the bypass valve (where applicable) at each control station.
D.
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(1)
The lean solvent flow control.
(2)
The lean solvent from the lean solvent filters.
(3)
The TGCU Contactor level control, (the rich solvent from the TGCU Contactor).
Verify that the following control valves are fully closed. Close both of the isolation block valves and the bypass valve at each control station. (1)
The steam flow control valve to the TGCU Stripper Reboiler.
(2)
The TGCU Stripper Reflux Accumulator level control valve.
(3)
The bleed water flow control valve from the TGCU Stripper reflux.
(4)
The makeup water flow control valve to the TGCU Stripper Reflux Accumulator.
(5)
The acid gas pressure control to the SRU.
E.
Verify that the bypass valve on the pressure control valve to the flare is closed. Open both of the isolation block valves at this control station.
F.
The TGCU solvent filters will not be used to filter solids during this time, but the filter vessels and their piping are to be flushed and cleaned. Remove the filter elements, then bolt-up the individual filters. Open the inlet and outlet block valves on each filter, and open the bypass valves for the filters.
G.
Verify that the valves in the solvent makeup line are closed.
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SULFUR BLOCK H.
Add water (steam condensate) to the bottom of the TGCU Contactor through the condensate makeup line.
I.
Once there is an adequate level in the TGCU Contactor, all the way to the top of its level gauge open the suction valve on a TGCU Rich Amine Pump and use its drain valve to be sure the pump is flooded with water. Start the pump, then open its discharge valve. Watch the level in the TGCU Contactor as the pump fills the downstream piping and begins to fill the TGCU Stripper. When the level drops to the low-low level shutdown should shut down the pump. If it does not, stop the pump manually before it loses suction and correct the problem with the low level shutdown before proceeding.
J.
Continue filling the TGCU Contactor with condensate and pumping the water to the TGCU Stripper periodically, until the level in the TGCU Stripper is all the way to the top of its level gauge.
K.
Once there is an adequate level in the TGCU Stripper, open the suction valve on a TGCU Lean Amine Pump and use its drain valve to be sure the pump is flooded with water. Start the pump, then open its discharge valve. As the pump fills the downstream piping and begins to return water to the TGCU Contactor, watch the level in the TGCU Stripper to be sure the pump does not lose suction. If the level disappears in the column, shut the pump down, add more condensate to the TGCU Contactor and pump it to the TGCU Stripper to reestablish the level, then restart the TGCU Lean Amine Pump.
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L.
As the level begins to rise in the TGCU Contactor, restart the TGCU Rich Amine Pump. Watch the levels in both columns, and shut a pump down if necessary to keep from emptying either column.
M.
Once the levels in both columns are adequate, discontinue the addition of condensate.
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SULFUR BLOCK N.
At this point, neither the flow into or the level of the TGCU Contactor is being controlled. Both control stations are in "manual" with the valves fully open to flush the piping as much as possible. Depending on the hydraulics of the system, it may be necessary to place either or both of these controls in "automatic" to prevent losing the level in one of the columns. If so, leave the bypass valve on the control station "cracked" so that the bypass piping gets flushed.
O.
Use the low point drain valves to flush out each section of the system. Leave the drain valves open until the water is clear.
P.
Circulate the water and blow down the low point drains until all of the drain water is clear. Add more condensate as necessary to maintain the levels in the columns. At some point during the washing procedure, the standby TGCU Rich Amine Pump and standby TGCU Lean Amine Pump should be placed in service while the other pumps are shut down. This will ensure cleaning out both pumps and their associated piping in each service.
11.7.7.2
Q.
Once the drain water is clear, shut down the TGCU Rich Amine Pump and completely drain the system. Drain the system as quickly as possible, so that the water velocity will help flush the solids from all parts of the system.
R.
Allow the TGCU Lean Amine Pump to continue running while the system drains, but watch the pump closely to verify that the low-low level shutdown shuts the pump down when the level falls to the shutdown setpoint. If the level drops completely out of the gauge glass before the pump shuts down, stop the pump manually and correct the problem with the low level shutdown before proceeding further.
S.
Confirm that the solvent transfer line (for MDEA makeup) has been flushed and is ready for service.
Acid Wash A weak (0.1 wt %) citric acid solution is used next to remove grease, rust, and scale from the equipment and piping. The citric acid will chelate with the iron in the rust and scale so that it dissolves in the solution.
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SULFUR BLOCK
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A.
Use the condensate makeup line to re-establish the levels in the TGCU Contactor and the TGCU Stripper as before, and establish circulation of water in the system.
B.
Add concentrated citric acid to the circulating water to make a 0.1 wt % citric acid solution.
C.
Begin steam flow to the TGCU Stripper Reboiler and gradually raise the temperature of the circulating solution. For maximum effectiveness, the solution should be 65-95°C throughout the system, so adjust the steam flow accordingly. The fans on the TGCU Lean Amine Cooler should not be operating at this time, and cooling water should not be flowing to the TGCU Lean Amine Trim Cooler.
D.
It is unlikely that any steam will leave the top of the TGCU Stripper during this operation, so the TGCU Stripper Reflux Accumulator should remain dry. If a level should develop in this vessel, drain the water from the vessel using a drain valve on one of the TGCU Stripper Reflux Pumps.
E.
After circulating for about 3 hours, start the other TGCU Rich Amine Pump and shut down the first one. Do the same with the TGCU Lean Amine Pumps.
F.
Circulate the hot solution for a total of about 6 hours, blowing down the low point drains occasionally. Add more condensate if necessary to maintain the levels in the columns.
G.
After 6 hours, shut off the steam to the TGCU Stripper Reboiler, shut down the pumps, and completely drain the system. Drain the system as quickly as possible, so that the liquid velocity will help flush any remaining solids from the system.
H.
Use the condensate makeup line to reestablish the levels in the TGCU Contactor and the TGCU Stripper as before, and establish circulation of water to flush the system.
I.
Switch to the other pumps for a few minutes, then shut down the pumps and completely drain the system.
J.
Once again, use the condensate makeup line to reestablish the levels in the TGCU Contactor and the TGCU Stripper as before, and establish circulation of water in the system.
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SULFUR BLOCK
11.7.7.3
K.
Reestablish steam flow to the TGCU Stripper Reboiler and gradually raise the temperature in the column.
L.
When the temperature begins to rise in the TGCU Stripper overhead line, start a fan on the TGCU Stripper Reflux Condenser and place the reflux temperature controller in service with a setpoint of 54°C.
M.
When a level builds in the TGCU Stripper Reflux Accumulator, drain it to the closed drain from the drain on one of the pump cases.
N.
Open the downstream block valve at the TGCU Stripper Reflux Accumulator level control valve, then use the drain valve to blow steam from the column backwards down the reflux line to remove any debris. Continue until the steam blows clear, then close the drain valve and the block valve.
O.
Continue to circulate water and apply heat in the TGCU Stripper Reboiler, until the water drained from the TGCU Stripper Reflux Accumulator is clear. During this time, blow down the low point drains occasionally and add more condensate if necessary to maintain the levels in the columns, and switch to the other TGCU Rich Amine Pump and TGCU Lean Amine Pump.
P.
Once the reflux loop has cleared up (the drain water is clear), shut off the steam to the TGCU Stripper Reboiler, shut down the pumps, and completely drain the system. Drain the system as quickly as possible, so that the liquid velocity will help flush any remaining solids from the system.
Q.
Check the pH of the water draining from the system. If necessary, repeat Steps J through P until the pH of the drain water is about the same as the pH of the condensate makeup.
Weak Amine Wash The washing operation is completed by circulating a weak amine solution through the system. This will neutralize any citric acid left in the system, and acclimate the system to alkaline pH operation so that no further scale is removed from the equipment and piping when the normal solvent is circulated.
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SULFUR BLOCK A.
Use the condensate makeup line to reestablish the levels in the TGCU Contactor and the TGCU Stripper as before, and establish circulation of water in the system.
B.
Add enough MDEA to the circulating water to reach a concentration of about 1 wt%.
C.
Begin steam flow to the TGCU Stripper Reboiler and gradually raise the temperature in the column.
D.
When the temperature begins to rise in the TGCU Stripper overhead line, check that at least one of the fans is running on the TGCU Stripper Reflux Condenser.
E.
When a level builds in the TGCU Stripper Reflux Accumulator, open the suction valve on one of the TGCU Stripper Reflux Pumps and use its drain valve to be sure the pump is flooded with water. Start the pump, open its discharge valve, then open the bypass valve on the TGCU Stripper Reflux Accumulator level control valve to pump the water back into the TGCU Stripper. Watch the level in the TGCU Stripper Reflux Accumulator while pumping it out. Shut the pump down when the vessel is empty, then close the suction and discharge valves on the pump and close the bypass valve on the TGCU Stripper Reflux Accumulator level control valve.
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F.
Continue to circulate the solution and apply heat to the TGCU Stripper Reboiler, pumping out the TGCU Stripper Reflux Accumulator as required by alternating which pump is used. During this time, blow down the low point drains occasionally and add more condensate if necessary to maintain the levels in the columns, and switch to the other TGCU Rich Amine Pump and TGCU Lean Amine Pump.
G.
During one of the pumping cycles for the TGCU Stripper Reflux Accumulator, flush out the minimum flow spill-back line by opening the manual block valve to allow circulation through this line. Then close the manual block valve.
H.
During another pumping cycle, flush out the bleed water piping by setting the output of the bleed water flow controller to 100%
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SULFUR BLOCK to fully open the bleed water flow control valve, opening its upstream and downstream block valves, and opening its bypass valve. Then close the valves and set the output of the bleed water flow control valve back to 0%.
11.7.7.4
I.
Take a sample of the circulating solution and run a foam test on it using the procedure in Section 11.10.
J.
Once the solution drained from all the low point drain valves is clear, shut off the steam to the TGCU Stripper Reboiler, shut down the pumps, and completely drain the system. Drain the system as quickly as possible, so that the liquid velocity will help flush any remaining solids from the system.
K.
Use the condensate makeup line to reestablish the levels in the TGCU Contactor and the TGCU Stripper as before, and establish circulation of water to flush the system.
L.
Switch to the other pumps for a few minutes, then shut down the pumps and completely drain the system.
M.
If the solvent sample taken in Step I was foamy, repeat Steps A through L until the solvent is not foamy.
Initial Solvent Fill The solvent system should now be clean, ready to place in service. All that remains is to fill the system with the proper solvent charge and establish the proper operating conditions. NOTE:
A.
Issued 30 August 2011
This procedure prepares the TGCU solvent system for operation in the shortest possible time. However, it does allow the MDEA to come in contact with oxygen that is in the TGCU Contactor. If a slightly longer TGCU startup schedule can be tolerated, this deficiency can be minimized or eliminated by deferring the procedure in this section until nitrogen has been used to purge the TGCU Quench Column and TGCU Contactor as described in the following section.
Close the inlet and outlet block valves on the four TGCU solvent filters, then install the proper elements and/or carbon in the filters. Leave the block valves closed on each filter for now.
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SULFUR BLOCK
Issued 30 August 2011
B.
Use the condensate makeup line to reestablish the levels in the TGCU Contactor and the TGCU Stripper as before, and establish circulation of water in the system.
C.
Add enough MDEA to the circulating water to reach a concentration of about 45 wt%.
D.
Place in service and adjust the level controller on the TGCU Contactor to maintain its normal setpoint. Stop the condensate and/or amine makeup when the TGCU Stripper level is about 50-60%.
E.
Begin steam flow to the TGCU Stripper Reboiler and gradually raise the temperature in the column. Place the steam flow controller in the DCS on "automatic" with its setpoint set to its normal value.
F.
Open the high point vent valve on the TGCU Stripper overhead line and allow the steam to purge any air from the vessel. As the pressure builds, the vent valve can be closed.
G.
Monitor the stripper pressure, and adjust the overhead pressure controller if necessary to maintain the stripper pressure at about 0.85 kg/cm2(g) as the system is heated to operating temperatures.
H.
Ensure that the fans are running on the TGCU Lean Amine Cooler and the TGCU Stripper Condenser. Commence cooling water flow to the TGCU Lean Amine Trim Cooler.
I.
Place the lean solvent temperature controller in "automatic" and set its setpoint to its normal value.
J.
When a level builds in the TGCU Stripper Reflux Accumulator, open the suction valve on one of the TGCU Stripper Reflux Pumps and use its drain valve to be sure the pump is flooded with water. Open the block valves upstream and downstream of the reflux flow control valve, place the reflux flow controller in "automatic" with its setpoint set to its normal value, then start the pump and open its discharge valve.
K.
Open the block valves on the TGCU Stripper Reflux Accumulator level control valve and place the level controller in the DCS in "automatic" with its setpoint set to its normal value.
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SULFUR BLOCK The TGCU Stripper Reflux Accumulator level control valve will now open as needed to pump water back into the TGCU Stripper and maintain the desired level in the TGCU Stripper Reflux Accumulator.
Issued 30 August 2011
L.
If the control loops on the TGCU solvent have not already been placed in service, do so at this time. Switch the TGCU contactor level controller and the lean solvent flow controller in the DCS to "automatic" with their setpoints set to their normal values.
M.
Place each of the four TGCU solvent filters in service as follows: (1)
Open the vent valve on the top of the filter.
(2)
"Crack" the filter inlet block valve open slightly and allow the filter to fill with solvent. When the filter is full, close its vent valve.
(3)
Open the inlet and outlet block valves on the filter.
(4)
Slowly close the valve in the bypass line around the filter.
N.
Analyze a sample of the circulating solvent using the procedure in these guidelines to determine the amine concentration. Add more fresh MDEA using the solvent transfer line if needed to bring the concentration up to the design value, 45 wt %.
O.
Flush the makeup water line by setting the output from the makeup water flow controller to 100% to fully open the makeup water flow control valve, opening its upstream block valve, then opening the downstream drain valve until the water runs clear. Then set the output of the flow controller to 0% to close the makeup water flow control valve, and open the downstream block valve.
P.
Confirm that the bleed water flow controller is in "manual' with its output set at 0% and that the bleed water flow control valve is closed, then open its upstream and downstream block valves.
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SULFUR BLOCK The solvent system is now ready for service. It can remain in this operating mode indefinitely while the rest of the TGCU is prepared for startup. Check the system periodically for indications of plugging, etc. (low flow, erratic pump discharge pressure, high filter pressure drop), as solid materials may accumulate at various points in the system over time.
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SULFUR BLOCK 11.7.8
Purging the Low Pressure TGCU Columns Prior to starting up the TGCU using the procedures in Section 11.8 of these guidelines, nitrogen should be used to purge the TGCU Quench Column and the TGCU Contactor. This will displace the air introduced into the columns while washing and filling them earlier. At this point, the following conditions should exist in the TGCU:
11.7.8.1
1.
The TGCU Start-Up Blower is not in service and is bypassed.
2.
The quench water system and perhaps the amine system have been cleaned and loaded with their respective initial fills of water and amine. (The amine system may be waiting on purging of the TGCU Contactor before the system is loaded with amine.)
Establishing Nitrogen Flow To establish nitrogen flow into the TGCU, proceed as follows:
Issued 30 August 2011
A.
Confirm that the nitrogen flow controller in the DCS is set to 0% output and that the control valve in the nitrogen supply line is closed.
B.
Confirm that the Quench Column inlet hand control in the DCS is set to 0% output so that the TGCU Quench Column Bypass Valve will open later in Step F when the Startup/Run selector switch is switched to "STARTUP".
C.
Confirm that the TGCU Quench Column is isolated from the quench water circulation loop by confirming that the following valves are all closed: (1)
The bypass valve and downstream block valve at the quench water flow control valve.
(2)
The block valve downstream of the pH analyzer.
(3)
The suction valves at the TGCU Quench Water Pumps.
(4)
The drain valve on the suction line to the pumps.
(5)
The block valve in the caustic supply line at the tie-in to the suction line.
(6)
The block valve in the condensate fill line at the tie-in to the suction line.
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SULFUR BLOCK (7)
D.
The bypass valve and downstream block valve at the filtered quench water flow control valve.
Confirm that the TGCU Contactor is isolated from the solvent circulation loop by confirming that the following valves are all closed: (1)
The bypass valve and downstream block valve at the lean solvent flow control valve.
(2)
The suction valves at the TGCU Rich Amine Pumps.
(3)
The drain valve on the suction line to pumps.
(4)
The block valves in the solvent makeup line at the tie-in to the suction line.
(5)
The block valve and globe valve in the condensate makeup line at the tie-in to the suction line.
E.
Confirm that the spectacle blind in the utility air supply line is in the "closed" position.
F.
Toggle the Startup/Run selector switch, the Startup/Run selector switch, in the DCS to "STARTUP". The PLC should perform the following actions:
Issued 30 August 2011
(1)
Bypasses the SRU ESD inputs to the TGCU ESD.
(2)
Disables the Tailgas Valves transfer switches.
(3)
Opens the TGCU Quench Column Bypass Valve.
(4)
Enables the Leak Test Switch.
G.
Confirm that the SRU Tailgas Valves to the TGCU are closed.
H.
Confirm that the TGCU Start-Up Blower Bypass Valve is fully open.
I.
Confirm that the block valve(s), and the steam-jacketed block valve in the nitrogen supply line are open.
J.
Confirm that the TGCU Outlet Valve is open.
K.
Reset the TGCU ESD by toggling the push-button in the DCS to "RESET".
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SULFUR BLOCK L.
Set the output of the hand control in the DCS to 0% to close the TGCU Warmup/Bypass Valve.
M.
Toggle the Nitrogen On/Off switch in the DCS to "ON". The PLC should perform the following actions:
11.7.8.2
(1)
Opens the nitrogen block valves.
(2)
Closes the nitrogen vent valve.
N.
Use the nitrogen flow controller in the DCS to open the nitrogen flow control valve and send nitrogen to the front end of the TGCU.
O.
Allow the nitrogen to continue flowing long enough to reduce the oxygen concentration in the equipment and piping to less than 1%. Use a portable oxygen analyzer to determine the oxygen concentration.
Purging the TGCU Start-Up Blower A.
Visually confirm that the TGCU Start-Up Blower suction block valve and the discharge block valve are closed, the bypass valve is open, the nitrogen purge to the blower seal is in service, and the local "stop" control at the bloweris set to the "RUN" position.
B.
Start the TGCU Start-Up Blower using the start/stop toggle switch in the DCS. The PLC will perform the following actions:
C.
Issued 30 August 2011
(1)
The nitrogen purge valveis closed.
(2)
The TGCU Start-Up Blower Suction Valve is opened.
(3)
The TGCU Start-Up Blower Discharge Valve is opened.
(4)
After the limit switches prove these valves open, the TGCU Start-Up Blower is started.
(5)
Once the Startup Blower is started, the TGCU Start-Up Blower Bypass Valve is closed.
As this valve is closed, the blower will start to load. As it does so, the blower will begin to "pull" nitrogen through the TGCU
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SULFUR BLOCK Reactor Feed Heater and TGCU Reactor Feed Mixer and all of the associated piping. D.
Allow the blower to continue running long enough to reduce the oxygen concentration in the piping to less than 1%. Use a portable oxygen analyzer to determine the oxygen concentration.
E.
When the oxygen concentration is below 1%, shut down the TGCU Start-Up Blower using the start/stop toggle switch in the DCS. The PLC will perform the following actions:
11.7.8.3
(1)
Open the TGCU Start-Up Blower Bypass Valve.
(2)
Prove the bypass valve open using the limit switches.
(3)
Stop the TGCU Start-Up Blower
(4)
Once the blower is stopped, the nitrogen purge valve is opened, and the suction and discharge valves are closed.
Purging the Columns All that remains is to open the vent valves on the low pressure columns and allow the inert gas to displace the air in the columns.
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A.
Open all of the vent valves on the PI and PDT taps on the TGCU Quench Column and the TGCU Contactor, and the vent valves at the tops of the columns.
B.
Increase the output from the Quench Column inlet hand control in the DCS to 100% to open the TGCU Quench Column Inlet Valve and close the TGCU Quench Column Bypass Valve.
C.
Continue to vent inert gas until no measurable oxygen escapes from the vents, then close all of the vent valves.
D.
Decrease the output from the Quench Column inlet hand control in the DCS to 0% to open the TGCU Quench Column Bypass Valve and close the TGCU Quench Column Inlet Valve.
E.
Set the output from the nitrogen flow controller to 0% to close the nitrogen flow control valve.
F.
Toggle the Nitrogen On/Off switch in the DCS to "OFF".
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SULFUR BLOCK The PLC should perform the following actions: (1)
Closes the nitrogen block valves.
(2)
Opens the nitrogen vent valve.
NOTE:
Issued 30 August 2011
If the initial solvent fill was not loaded into the solvent system earlier to avoid exposing the MDEA to oxygen, this can be accomplished now. Follow the procedure given in the previous section to fill the solvent system with its initial solvent charge.
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SULFUR BLOCK
11.8 Startup Procedures The procedure used to start up the TGCU depends on whether the catalyst in the TGCU Reactor has been pre-sulfided. This first section describes the procedure for the initial startup of the plant with a fresh catalyst charge (oxidized state), or for startups after the catalyst charge has been replaced. Subsequent startups will require a different procedure and are discussed later (Section 11.8.6 of these guidelines).
11.8.1
Initial Startup of the TGCU During the initial startup, the catalyst in the TGCU Reactor is pre-sulfided by contacting it with H2S in the presence of hydrogen. Subsequent startups will probably not require this step. Once this has been accomplished, the system can be placed into operation.
11.8.1.1
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Initial Preparations A.
Confirm that the steam pressure controller in the DCS is in "manual" with its output set to 0%, and that control valve in the HP Steam supply line to the TGCU Reactor Feed Heater is closed.
B.
Place the reactor feed temperature controller in "automatic".
C.
Confirm that reducing gas flow controller in the DCS is in "manual" with its output set to 0%, and that the control valve in the reducing gas supply line to the TGCU Reactor Feed Mixer is closed.
D.
Place the hydrogen controller in "automatic".
E.
Verify that the automated shutdown valves, the upstream block valves, and the downstream steam-jacketed block valve in the reducing gas line to the TGCU Reactor Feed Mixer are all closed.
F.
Confirm that the pre-sulfiding gas flow controller in the DCS is in "manual" with its output set to 0%, and that the control valve in the pre-sulfiding gas line to the TGCU Reactor Feed Mixer is closed.
G.
Verify that the automated shutdown valve and the upstream block valve in the pre-sulfiding gas line to the TGCU Reactor Feed Mixer are both closed.
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SULFUR BLOCK
11.8.1.2
H.
Confirm that the nitrogen flow controller in the DCS is in "manual" with its output set to 0% output, and that the control valve in the nitrogen supply line is closed.
I.
Verify that the automated shutdown valves in the nitrogen supply line are both closed, then open the upstream block valves and the downstream steam-jacketed block valve.
J.
Confirm that the Quench Column hand control in the DCS is set to 0% output, so that the TGCU Quench Column inlet valve will remain fully closed and the TGCU Quench Column bypass valve will open later when the TGCU startup/run selector switch is switched to "STARTUP".
K.
Confirm that the TGCU Waste Heat Reclaimer is filled with water up to its normal liquid level.
L.
Visually confirm that the SRU 1 Tailgas Valve to the TGCU is closed.
M.
Visually confirm that the SRU 2 Tailgas Valve to the TGCU is closed.
N.
Visually confirm that the manual TGCU Outlet Valve is fully open.
O.
Confirm that the Leak Test switch in the DCS is toggled to "OFF".
P.
Confirm that the TGCU Start-Up Blower Bypass Valve is fully open.
Q.
Verify that the local stop control for the TGCU Start-Up Blower is set to the run position.
Establishing Nitrogen Flow To establish nitrogen flow into the TGCU, proceed as follows: A.
Toggle the Startup/Run selector switch in the DCS to "STARTUP". The PLC should perform the following actions:
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(1)
Bypasses the SRU ESD inputs to the TGCU ESD.
(2)
Disables the Tailgas Valve transfer switchs.
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SULFUR BLOCK (3)
Opens the TGCU Quench Column Bypass Valve.
B.
Reset the TGCU ESD by toggling the switch in the DCS to "RESET".
C.
Set the output of the TGCU Warmup/Bypass Valve hand control in the DCS to 0% to close the TGCU Warmup/Bypass Valve and visually confirm that the valve is closed.
D.
Toggle the Nitrogen On/Off switch in the DCS to "ON". The PLC should perform the following actions:
11.8.1.3
(1)
Opens the nitrogen block valves.
(2)
Closes the nitrogen vent valve.
E.
Increase the output of the flow controller to 100% in the DCS to open the control valve and send nitrogen to the front-end of the TGCU.
F.
Allow the nitrogen to purge the front-end of the TGCU for 15 minutes before proceeding to the next step.
Establishing Re-circulation Flow Prior to pre-sulfiding the catalyst in the TGCU Reactor, it is necessary to heat the reactor and catalyst up to 150-175°C. To do this, nitrogen is re-circulated through the TGCU Reactor Feed Heater with the TGCU Start-Up Blower. This re-circulating gas is heated using HP steam in the TGCU Reactor Feed Heater, then flows through the TGCU Reactor Feed Mixer, the TGCU Reactor, and the TGCU Waste Heat Reclaimer bringing the reactor, catalyst, and process heat exchange surfaces up to operating temperature. A.
Visually confirm that the TGCU Start-Up Blower suction block valve and the discharge block valve are closed, the bypass valve is open, the nitrogen purge to the blower seal is in service, and the local "stop" control at the blower is set to the run position.
B.
Start the TGCU Start-Up Blower using the start/stop toggle switch in the DCS. The PLC will perform the following actions: (1)
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The nitrogen purge valve is closed. Tailgas Cleanup
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SULFUR BLOCK (2)
The TGCU Start-Up Blower Suction Valve is opened.
(3)
The TGCU Start-Up Blower Discharge Valve is opened.
(4)
After the limit switches prove these valves open, the TGCU Start-Up Blower is started.
(5)
Once the Startup Blower is started, the TGCU Start-Up Blower Bypass Valve is closed.
As this valve is closed, the blower will start to load. As it does so, the blower will begin to "pull" nitrogen through the front-end TGCU equipment and all of the associated piping. C.
Once the blower is running, open the TGCU Warmup/Bypass Valve by increasing the output from the hand control to 100%. As the TGCU Warmup/Bypass Valve opens, the TGCU Start-Up Blower will begin re-circulating gas from the outlet of the TGCU Waste Heat Reclaimer back to the TGCU Reactor Feed Heater (via the TGCU Contactor overhead line).
D.
Once re-circulation has been established, place the nitrogen flow controller in "automatic" and reduce its setpoint to about 5-10% of maximum flow.
E.
Slowly begin to increase the setpoint of the steam pressure controller in the DCS to establish steam flow to the TGCU Reactor Feed Heater and increase the temperature of the re-circulating gas stream to 150-175°C.
F.
Open the vent valve on the TGCU Waste Heat Reclaimer to vent air from the steam section.
G.
Confirm that the BFW level controller and control valve to the TGCU Waste Heat Reclaimer are in service and functioning properly.
H.
Place the reactor feed temperature cascade control in service as follows: (1)
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Confirm that the remote setpoint that the reactor feed temperature controller is supplying to the pressure controller matches the current setting on the pressure controller.
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SULFUR BLOCK
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(2)
Confirm that the reactor feed temperature controller is in "automatic" and its setpoint is tracking its current reading.
(3)
Switch the steam pressure controller to "cascade" so that the temperature controller can now adjust the setpoint on the pressure controller.
(4)
If necessary, slowly adjust the setpoint of the reactor feed temperature controller to 175°C.
(5)
Verify that the steam pressure controller is adjusting the HP steam pressure as needed to control the desired temperature setting on the reactor feed temperature controller.
I.
As the equipment and piping heat up, inspect all of the equipment and piping for the effects of thermal expansion.
J.
As the steam pressure builds in the TGCU Waste Heat Reclaimer, close the vent valve on the steam space. The steam pressure inside the boiler will now be "floating" on the LP steam header.
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SULFUR BLOCK 11.8.2
Pre-Sulfiding the TGCU Catalyst Before introducing sulfur plant tailgas into the TGCU, the catalyst in the TGCU Reactor must be "pre-sulfided" to convert the metals (cobalt and molybdenum) from their inactive oxide state to their active sulfide state. Once the catalyst has been pre-sulfided, it will remain in its active state and will not require pre-sulfiding on subsequent startups. Only when the catalyst is replaced will this pre-sulfiding procedure have to be repeated. The catalyst is pre-sulfided by contacting it with H2S in the presence of hydrogen. The amount of H2S must be controlled at a low concentration to limit the temperature rise as the catalyst reacts with the sulfur, so that excessively high temperatures are not created that could damage the catalyst or the equipment. The catalyst will end up containing about 6 wt % sulfur at the conclusion of this procedure. Before beginning, the following conditions should exist in the TGCU: 1.
The outlet temperature from the TGCU Reactor Feed Heater is on automatic control, maintaining about 175°C.
2.
The nitrogen flow controller is in "automatic" with its set point set at 5-10% of maximum flow to add a small amount of fresh nitrogen to the system.
3.
The TGCU Start-Up Blower is in service, re-circulating nitrogen to the TGCU Reactor Feed Heater.
4.
The Amine Regeneration Unit is operating and producing acid gas. The H2S in this acid gas will be used to pre-sulfide the TGCU catalyst.
Also, ensure that there is an adequate supply on hand (one or two boxes) of gas detector tubes for measuring the H2S concentration into and out of the TGCU Reactor. Sections 9.10.8 and 11.10.7 of these guidelines describe how Dräger tubes can be used to measure the H2S concentration of a gas stream. The H2S concentration will probably be in the range of 1-2%, so Dräger Catalog No. CH 281 01 gas detector tubes are appropriate.
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SULFUR BLOCK 11.8.2.1
Establishing Reducing Gas Flow Before introducing H2S into the TGCU Reactor, reducing gas must be added to the re-circulating gas stream. A.
Confirm that the reducing gas controller in the DCS is set to 0% output and that the control valve in the reducing gas supply line is closed.
B.
Prior to placing the H2/H2S analyzer in service, be sure that its sample line does not contain any water, etc.:
C.
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(1)
Close the sample valve on the TGCU Waste Heat Reclaimer outlet channel.
(2)
Disconnect the sample line from the sample valve and from the 2-way analyzer sample switching valve. Drain any water from the line and check that it is not plugged, then reinstall the sample line.
(3)
Repeat Step (2) for the other sample line (connected to the sample valve on the TGCU Contactor overhead line).
(4)
Switch the sample selector valve in the analyzer enclosure so that the H2/H2S analyzer takes its sample from the TGCU Contactor overhead line, and use the zero and span gas to confirm the calibration of the analyzer. Make any necessary adjustments to the analyzer per the manufacturer's instructions.
(5)
Switch the sample selector valve in the analyzer enclosure so that the H2/H2S analyzer takes its sample from the outlet of the TGCU Waste Heat Reclaimer, then open the sample valve. The hydrogen analyzer will now be sampling the process gas, as indicated by the reading on the hydrogen controller in the DCS, while the other sample line on the TGCU Contactor overhead line is now being back-purged with nitrogen.
Open the upstream manual block valves and the steam-jacketed block valve in the reducing gas supply line to the TGCU Reactor Feed Mixer.
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SULFUR BLOCK D.
To begin introducing reducing gas into the circulating gas stream, toggle the Reducing Gas On/Off switch in the DCS to "ON". The PLC should perform the following actions:
E.
(1)
Opens the reducing gas block valves.
(2)
Closes the reducing gas vent valve.
Switch the reducing gas controller to "automatic" and slowly begin to increase its setpoint to open the control valve and begin introducing reducing gas into the re-circulating stream. As the reducing gas flow rate increases, the hydrogen concentration displayed on the hydrogen controller will increase.
F.
The reducing gas concentration should be 0.5-5% while pre-sulfiding. If necessary, adjust the setpoint on the reducing gas controller to control the reading in this range. NOTE:
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It is important to control the hydrogen concentration within this range while pre-sulfiding the catalyst. A hydrogen reading lower than this could mean that a reducing atmosphere is not being maintained inside the TGCU Reactor to insure that the H2S properly sulfides the catalyst. Conversely, too much hydrogen can damage the catalyst by reacting with the cobalt and molybdenum to form inactive metal hydrides.
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SULFUR BLOCK
CAUTION
DO NOT ALLOW HYDROGEN TO CONTACT THE TGCU CATALYST AT TEMPERATURES ABOVE 200°C IN THE ABSENCE OF H2S. IF THERE IS NO H2S PRESENT, THE HYDROGEN WILL REACT IRREVERSIBLY WITH THE CATALYST TO FORM INACTIVE METAL HYDRIDES. IF ANY DELAYS ARE ENCOUNTERED IN INTRODUCING H2S, STOP THE FLOW OF REDUCING GAS UNTIL READY TO RESUME. G.
H.
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As described in previous sections of these guidelines, the hydrogen controller can adjust the flow of hydrogen to the TGCU Reactor Feed Mixer to control the hydrogen concentration, via the limit relay. Place the hydrogen concentration cascade control in service as follows: (1)
Confirm that the remote setpoint that the hydrogen controller is supplying to the reducing gas flow controller in the DCS matches the current setting on the flow controller.
(2)
Confirm that the hydrogen controller is in "automatic" and its setpoint is tracking its current reading.
(3)
Switch the reducing gas controller to "cascade" so that the concentration controller can now adjust the setpoint of the flow controller.
(4)
If necessary, slowly adjust the setpoint of the hydrogen controller to 2%.
Periodically check that the hydrogen controller and the reducing gas controller maintain the hydrogen concentration in the proper range (0.5-5%) throughout the pre-sulfiding operation.
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SULFUR BLOCK 11.8.2.2
Pre-Sulfiding the Catalyst The sulfur for pre-sulfiding the TGCU catalyst comes from H2S in the amine acid gas produced by the Amine Regeneration Unit. The amount of acid gas entering the TGCU Reactor Feed Mixer is to be adjusted to give an H2S concentration of about 1-2% going into the TGCU Reactor. Gas detector tubes can be used to measure the H2S concentration in the inlet and outlet from the TGCU Reactor. When the outlet H2S concentration is essentially the same as the inlet concentration, then the catalyst has absorbed all the sulfur that it can and pre-sulfiding is complete at that temperature level. A.
Confirm that the pre-sulfiding gas flow controller in the DCS is set to 0% output, and that the control valve in the pre-sulfiding gas supply line is closed.
B.
Verify that the automated shutdown valve, and the manual block valves in the pre-sulfiding gas supply line are closed. Rotate the spectacle blind to the open position, then briefly open the drain valve to verify that there are no liquids in the line between the control valve and the shutdown valve.
C.
Open the manual block valves in the pre-sulfiding gas line.
D.
Toggle the Pre-sulfiding Gas On/Off switch in the DCS to "ON". The PLC should open the automated pre-sulfiding gas block valve.
E.
Place the pre-sulfiding gas flow controller in "automatic" and increase its setpoint to slowly open the control valve and allow a small flow of acid gas into the TGCU Reactor Feed Mixer. Adjust the setpoint as necessary to give an H2S concentration of 1-2% (measured with the gas detector tubes) in the inlet to the TGCU Reactor.
F.
Using the reactor feed temperature controller in the DCS, slowly raise the TGCU Reactor inlet temperature stepwise to 200°C while maintaining the H2S concentration in the inlet at 1-2% and the hydrogen concentration indicated on the hydrogen controller at 0.5-5%. Look for signs that the H2S has begun to react with the catalyst (i.e. the temperatures in the reactor begin to rise). If no
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SULFUR BLOCK temperature rise is seen in the TGCU Reactor, proceed to Step I.
CAUTION
IF EXCESSIVE CATALYST BED TEMPERATURES OCCUR AT ANY TIME ON THE REACTOR BED TEMPERATURE INDICATORS IN THE DCS, REDUCE THE AMOUNT OF H2S IN THE REACTOR INLET. THE TEMPERATURE RISE IN THE REACTOR IS DUE TO THE HEAT OF REACTION FROM H2S REACTING WITH THE CATALYST. REDUCING THE H2S CONCENTRATION WILL REDUCE THE REACTION RATE AND REDUCE THE TEMPERATURE RISE ACCORDINGLY. DO NOT REDUCE THE H2S CONCENTRATION TO ZERO, HOWEVER. THIS WOULD ALLOW HYDROGEN TO REACT WITH THE CATALYST AND DAMAGE IT AS DISCUSSED PREVIOUSLY.
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G.
Once the TGCU Reactor inlet temperature reaches 200°C, maintain this temperature while sampling the H2S concentration in the inlet and outlet of the reactor.
H.
When the outlet H2S concentration is approximately equal to the inlet concentration, pre-sulfiding is complete at this temperature level.
I.
Increase the inlet temperature stepwise to 230°C with the reactor feed temperature controller.
J.
Once the TGCU Reactor inlet temperature reaches 230°C, maintain this temperature while sampling the H2S concentration in the inlet and outlet of the reactor. When the outlet H2S concentration is approximately equal to the inlet concentration, pre-sulfiding is complete at this temperature level.
K.
Increase the inlet temperature stepwise to 260°C with the reactor feed temperature controller.
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SULFUR BLOCK After the entire bed reaches 260°C, hold it at this temperature for 4 hours. Monitor the catalyst bed temperatures and the TGCU Reactor outlet temperature through the temperature indicators in the DCS carefully as the reaction front moves through the bed. Do not allow any of these temperatures to exceed 340°C, by reducing the inlet temperature and/or the inlet H2S concentration as necessary. L.
At the conclusion of the 4 hour heat soak at 260°C, the H2S concentration should be the same in the outlet gas as it is in the inlet gas. If not, continue to hold the inlet at 260°C until the concentrations are equal.
M.
The catalyst is now in its active state. Discontinue the flow of pre-sulfiding gas by reducing the setpoint of the pre-sulfiding gas flow controller to 0%. Toggle the Pre-sulfiding Gas On/Off switch in the DCS to "OFF" to close the block valve and visually confirm that the valve is closed.
N.
Close the manual block valves in the pre-sulfiding gas supply line. THE PRE-SULFIDING LINE WILL NOT BE USED AGAIN UNTIL THE CATALYST IN THE TGCU REACTOR IS REPLACED AND A FRESH CHARGE CATALYST MUST BE PRE-SULFIDED. TO MINIMIZE THE CHANCE OF INADVERTENTLY SENDING AMINE ACID GAS TO THE TGCU REACTOR FEED HEATER, IT IS RECOMMENDED THAT THE SPECTACLE BLIND BE ROTATED BACK TO THE CLOSED POSITION AT THIS TIME.
O.
Slowly lower the TGCU Reactor inlet temperature to its normal value by adjusting the setpoint of the reactor feed temperature controller.
P.
Slowly adjust the setpoint of the hydrogen controller to its normal values (3%). Verify that the reducing gas flow controller is adjusting the rate accordingly. The TGCU can continue operating in this manner indefinitely until ready to bring SRU tailgas into the unit. During this time, observe the temperatures in the TGCU Reactor and the
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SULFUR BLOCK hydrogen concentration on the hydrogen controller to be sure that these control loops are operating properly. Also, continue to observe the operation of the TGCU Waste Heat Reclaimer to ensure that no problems develop in this boiler, and monitor the operation of the TGCU Start-Up Blower.
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SULFUR BLOCK 11.8.3
Routing SRU Tailgas to the TGCU The TGCU is now ready to accept tailgas from the SRUs. At first, the tailgas will be routed through just the front-end of the TGCU (TGCU Reactor Feed Heater, TGCU Reactor Feed Mixer, TGCU Reactor, and TGCU Waste Heat Reclaimer). Then, once this part of the process has “lined out”, the process gas will be switched into the TGCU Quench Column and the TGCU Contactor. Before beginning, the following conditions should exist in the TGCU: 1.
The Reactor Feed Heater is operating smoothly and the inlet temperature to the TGCU Reactor is being controlled at 230-240°C.
2.
The TGCU Reactor is up to normal operating temperature and its catalyst has been pre-sulfided.
3.
The TGCU Start-Up Blower is in service, re-circulating nitrogen to the TGCU Reactor Feed Heater.
4.
The H2/H2S analyzer has been calibrated and is sampling the process gas leaving the TGCU Waste Heat Reclaimer.
5.
The hydrogen controller is controlling the hydrogen at or above the normal setpoint
6.
One or both SRUs are operating smoothly on amine acid gas, or amine acid gas and SWS gas, and the air demand indicated on the air control is +2.0% or lower. (If the air demand is higher than this, the tailgas from the SRU contains excessive amounts of SO2 and could cause overheating of the TGCU Reactor.)
If any of these conditions are not true, do not attempt to bring SRU tailgas into the TGCU. In particular, do not attempt switching tailgas into the TGCU when the SRU(s) is(are) experiencing an upset. The result will be multiple upset units to deal with. Instead, focus your attention on stabilizing the operation of the SRU(s) first (usually by correcting a problem in the upstream Amine Regeneration and/or Sour Water Stripper units), and then use the procedure that follows to establish tailgas flow into the TGCU.
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SULFUR BLOCK 11.8.3.1
Introducing SRU Tailgas into the TGCU — Scenario 1 The first scenario to consider for introducing tailgas into the TGCU is a normal startup of the SRUs and the TGCU. Before being routed to the TGCU, the tailgas from both SRUs is sent to the TTO while the TGCU uses the TGCU Startup Blower to re-circulate gas to the TGCU Reactor Feed Heater via the TGCU Warmup/Bypass Valve. Once the TGCU is warmed up and ready to accept tailgas, the Train 1 and Train 2 SRUs can be routed to the TGCU as follows (using the Train 1 SRU for this procedure).
A.
Confirm that the hydrogen controller is in "automatic" and controlling the hydrogen concentration at or above its normal setpoint, (3%).
B.
Toggle the SRU 1 "fast" transfer switch in the DCS, to "TRANSFER TO TGCU". The PLC will perform the following actions: (1)
The SRU 1 Tailgas Valve to the TGCU is opened.
(2)
After the limit switches prove this valve open, the SRU 1 Tailgas Valve to the TTO is closed.
Visually confirm that these valves have moved to the proper positions. At this point, the tailgas from SRU 1 can flow to the TTO via either of two routes:
C.
(1)
Through the SRU 1 Tailgas Valve to the TGCU and then through the TGCU Warmup/Bypass Valve.
(2)
Through the SRU 1 Tailgas Valve to the TGCU and then through the TGCU Reactor Feed Heater, the TGCU Reactor, the TGCU Waste Heat Reclaimer, and the TGCU Start-Up Blower.
If the second SRU (Train 2) is also ready to send its tailgas to the TGCU, toggle the SRU 2 "fast" transfer switch in the DCS to repeat these actions for the other SRU. For this scenario, the opening and closing of Tailgas Valves to the TGCU and the Tailgas Valves to the TTO in Steps B and C can occur rapidly with no impact on either the SRU or the TGCU. This is because the TGCU Warmup/Bypass Valve will still be open at this
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SULFUR BLOCK time, so there will be very little differential pressure across the Tailgas Valves to the TGCU and there will not be an abrupt change in pressure when the Tailgas Valves to the TGCU are opened or when the Tailgas Valves to the TTO are closed. Note:
The “fast” transfer switches can also be used to take the Train 1 SRU and/or Train 2 SRU tailgas out of the TGCU. Every other toggle of these selector switches will take the opposite action to open the tailgas valve to the TTO and then close the tailgas valve to the TGCU.
In the next step, the TGCU Warmup/Bypass Valve is closed to force the process gas to take the second path, so that the TGCU Start-Up Blower can be shut down. D.
Slowly reduce the output from the hand control to 0% to close the TGCU Warmup/Bypass Valve. Now all of the SRU tailgas must flow through the TGCU Reactor Feed Heater, etc. as this is the only open flowpath to the TTO.
E.
With the SRU tailgas flowing through the TGCU Reactor Feed Heater, the re-circulation from the TGCU Start-Up Blower is no longer needed. Shut down the TGCU Start-Up Blower using the start/stop selector switch in the DCS. The PLC will perform the following actions: (1)
The TGCU Start-Up Blower bypass valve is opened and proved open.
(2)
The TGCU Start-Up Blower is stopped.
(3)
The nitrogen purge valve is opened.
(4)
The TGCU Start-Up Blower Suction Valve and the TGCU Start-Up Blower Discharge Valve are closed.
Confirm that these valves have moved to the proper positions and that the blower has stopped. F.
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Place the nitrogen flow controller in "manual" and set its output to 0% to close the control valve and stop the flow of nitrogen into the TGCU.
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SULFUR BLOCK G.
Toggle the Nitrogen On/Off switch in the DCS to "OFF". The PLC should perform the following actions: (1)
Closes nitrogen blocks.
(2)
Opens nitrogen vent valve.
H.
Close the downstream steam-jacketed block valve in the nitrogen supply line where it joins the tailgas line to the TGCU Reactor Feed Mixer.
I.
Allow the TGCU to operate in this fashion until all operating conditions are stable. In particular, observe the operation of the reactor feed temperature controller and the hydrogen controller to ensure that the TGCU Reactor inlet temperature remains under control and there is adequate hydrogen (2% or higher) in the TGCU Reactor outlet. At this point, all of the tailgas from both SRUs is flowing into the TGCU Reactor Feed Heater, mixing with the external reducing gas in the TGCU Reactor Feed Mixer, entering the TGCU Reactor to convert all of the sulfur compounds to H2S, being cooled in the TGCU Waste Heat Reclaimer, and flowing through the TGCU Quench Column Bypass Valve and the TGCU Start-Up Blower Bypass Valve to the Thermal Oxidizer via the TGCU Contactor overhead line and the TGCU Outlet Valve. Once the operation of the TGCU front-end has stabilized, the process gas can be introduced into the TGCU columns as described in Section 11.8.5 of these guidelines. If the columns are not ready the front-end of the TGCU can operate indefinitely in this manner until ready to switch the process gas to the columns.
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SULFUR BLOCK 11.8.3.2
Introducing SRU Tailgas into the TGCU — Scenario 2 The second startup scenario to consider is when the TGCU is already processing tailgas from one SRU, and the tailgas from the second SRU needs to be introduced into the TGCU. Assume that the Train 2 SRU is currently feeding the TGCU. Due to the back-pressure from the TGCU, the pressure downstream of SRU 1 Tailgas Valve to the TGCU will be about 0.07 kg/cm2(g), while the pressure upstream of this valve will be close to kg/cm2(g) (since the SRU 1 Tailgas Valve to the TTO will be open to the TTO at this time). If the Train 1 tailgas was quickly switched into the TGCU in the same manner as described above for the first scenario, a major upset would result in both SRUs and in the TGCU: As soon as the SRU 1 Tailgas Valve to the TGCU started to open, tailgas from the Train 2 SRU would begin to back-flow through the SRU 1 Tailgas Valve to the TGCU and flow to the TTO, since the pressure downstream of the SRU 1 Tailgas Valve to the TGCU at that moment would be higher than the pressure upstream of the SRU 1 Tailgas Valve to the TGCU. Since the SRU 1 Tailgas Valve to the TGCU is a more direct path to the TTO for the tailgas from the Train 2 SRU, most of the Train 2 tailgas would flow through the SRU 1 Tailgas Valve to the TGCU as it opens rather than flow through the TGCU. The outlet temperature from the TGCU Reactor Feed Heater in the TGCU would begin to rise (due to the drop in tailgas flow) while the controls began reducing the steam flow rate to the heater. Once the SRU 1 Tailgas Valve to the TGCU was fully open, all of the Train 1 tailgas and most of the Train 2 tailgas would be flowing directly to the TTO. The TGCU controls would continue reducing the steam flow rate to the TGCU Reactor Feed Heater to try to keep its outlet temperature under control. Then, once the SRU 1 Tailgas Valve to the TGCU was fully open, the SRU 1 Tailgas Valve to the TTO would begin to close. This would begin forcing all of the Train 1 tailgas and Train 2 tailgas into the TGCU Reactor Feed Heater. The outlet temperature from it would begin to drop while the controls began increasing the steam flow rate to the heater. Once the SRU 1 Tailgas Valve to the TTO was fully closed, all of the Train 1 and Train 2 tailgas would be flowing to the TGCU Reactor Feed Heater, causing an abrupt increase in its operating pressure from about 0.07 kg/cm2(g) to about 0.3 kg/cm2(g).
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SULFUR BLOCK This would cause the air and acid gas flow rates to the SRUs to suddenly drop, possibly causing the SRUs to flame-out. If so, the SRUs and the TGCU would shut down and the operators would have to start over again. If the SRUs and TGCU did manage to stay on-line, the TGCU Reactor Feed Heater would only be supplying about half as much heating as needed until the controls recover and bring the steam flow rate up to the new requirements. Until the controls recover, the inlet temperature to the TGCU Reactor would be low, possibly causing incomplete conversion of SO2 in the reactor and allowing SO2 to reach the quench water system and foul it. The reducing gas flow rate might also require time to adjust to the higher tailgas flow rate, further compounding the problems with conversion in the reactor. So, the best that could be expected if the second SRU is routed to the TGCU in the same manner as under the first scenario is an upset in both SRUs, the TGCU Reactor Feed Heater, the TGCU Reactor, and the quench water system. Depending on how quickly the SRUs respond to sudden changes in operating pressure, the SRU burners might flame-out. In this worst case, a complete restart of the SRUs and the TGCU would then be required. Instead of introducing the tailgas from the second SRU into the TGCU in an abrupt manner, what is needed is a slow, controlled redirection of the tailgas from the TTO to the TGCU. This can be accomplished by the DCS operator using the hand controls for the SRU 1 Tailgas Valve to the TTO and the SRU 1 Tailgas Valve to the TGCU. Under this scenario, the TGCU is already processing tailgas from the Train 2 SRU. This means that the TGCU warmup/bypass valve is already closed. This signals the PLC to disable the "fast" transfer switches in the DCS, so that the rapid switching sequence (scenario 1) cannot be activated inadvertently. A.
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Initiate the over-ride for the Train 1 tailgas valves by toggling the Train 1 "slow" transfer switch in the DCS, to "OVER-RIDE". The PLC temporarily removes the limit switches on the SRU 1 Tailgas Valve to the TTO and the SRU 1 Tailgas Valve to the TGCU from the "complete flowpath interlock" for the Train 1 SRU alarms and deactivates the "valve malfunction" alarms on these two valves, then
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SULFUR BLOCK directs the DCS to release control of the hand controls for these valves to the operator. B.
Use the hand control to slowly begin throttling the tailgas flow with the SRU 1 Tailgas Valve to the TTO, so that the pressure at the front-end of Train 1 is slightly higher than at the front-end of the Train 2 SRU. Monitor the flows and pressure in the Train 1 SRU and adjust the hand control accordingly.
C.
Once the SRU 1 Tailgas Valve to the TTO is throttling, use the other hand control to slowly open the SRU 1 Tailgas Valve to the TGCU. Some of the Train 1 tailgas may begin to flow into the TGCU at this time, but most of it will still flow through the SRU 1 Tailgas Valve directly to the TTO. Monitor the flows and pressures in the Train 1 SRU and the TGCU, and adjust the rate at which he opens the SRU 1 Tailgas Valve to the TGCU accordingly.
D.
Once the SRU 1 Tailgas Valve to the TGCU is fully open, use the hand control to slowly close the SRU 1 Tailgas Valve to the TTO the rest of the way and send all of the Train 1 tailgas to the TGCU. Monitor the flow rates and temperatures in the TGCU, and adjust the rate at which he closes the SRU 1 Tailgas Valve to the TTO as needed to allow time for the controls in the TGCU to respond.
E.
Once the SRU 1 Tailgas Valve to the TTO is fully closed, the Train 1 SRU is flowing to the TGCU along with the Train 2 SRU, and the TGCU is fully on-line. Once both valves have moved into position, the PLC will automatically restore the limit switches on the SRU 1 Tailgas Valve to the TTO and the SRU 1 Tailgas Valve to the TGCU to the "complete flowpath interlock" in the SRU alarms, restore the malfunction alarms for these valves to their normal configurations, and reset the "slow" transfer switch in the DCS, back to "NORMAL" and remove the over-ride. One further point to note is that the "slow" transfer over-ride switches can also be used to "back" tailgas out of the TGCU. If the operator wants to shut down the TGCU in a controlled fashion, this can be accomplished by using the TGCU Startup Blower to circulate gas through the TGCU Reactor Feed Heater while slowly "backing" the SRU tailgas out of the TGCU. The steps to perform this are essentially the same as those listed above (but in reverse order).
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SULFUR BLOCK 11.8.4
Quench Water and Amine Systems Before switching process gas into the TGCU Quench Column and the TGCU Contactor, the quench water and amine systems should be operating and ready to accept gas. The operating conditions described below should have been established previously at the conclusion of the washing operations, but are repeated below to serve as a "checklist" before introducing process gas to the columns as described in Section 11.8.5 that follows.
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A.
The quench water system should be charged with its initial fill of water, so that the level in the TGCU Quench Column is at the normal setpoint for the Quench Column level controller.
B.
Quench water should be circulating to the TGCU Quench Column at the normal setpoint for the quench water flow controller.
C.
Cooling water should be flowing to the TGCU Quench Water Trim Cooler and the TGCU Lean Amine Trim Cooler.
D.
The fans should be operating on the TGCU Quench Water Cooler, with the temperature controller on the quench water controlling at its normal setpoint or lower.
E.
The TGCU Quench Water Filter should be in service with the filtered quench water flow controller controlling at its normal setpoint.
F.
The quench water pH analyzer should be in service (with one pH Meter Sample Filter in service, and the other blocked-in for use as a spare) with the quench water pH analyzer in the DCS showing a pH of 11 or higher. Add caustic to the quench water if necessary to raise the pH to this level.
G.
The amine system should be charged with its initial fill of amine, with the level control in the DCS controlling the level in the TGCU Contactor at its normal setpoint.
H.
The MDEA concentration in the amine should be close to its design value (45 wt %). Add more fresh MDEA if necessary to bring the amine to this strength.
I.
Amine should be circulating through the TGCU Stripper, the TGCU Lean/Rich Exchanger, the TGCU Lean Amine Cooler, and the TGCU Lean Amine Trim Cooler to the distributor tray at the top of the TGCU Contactor at the normal setpoint for the flow controller.
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SULFUR BLOCK J.
The fans should be operating on the TGCU Lean Amine Cooler, with the temperature controller on the lean amine controlling at its normal setpoint or lower.
K.
The TGCU Rich Amine Filter should be in service.
L.
The TGCU lean amine filters should be in service.
M.
Steam should be flowing to the TGCU Stripper Reboiler at the normal setpoint for the flow control.
N.
The overhead temperature from the TGCU Stripper should be above the low temperature alarm point for the temperature indicator.
O.
The fans should be operating on the TGCU Stripper Reflux Condenser with the temperature controller on the outlet from the TGCU Stripper Reflux Condenser controlling at its normal setpoint or lower.
P.
The TGCU Stripper pressure controller to the SRU, should be in "manual" with its output set to 0% so that the pressure control valve is fully closed.
Q.
The TGCU Stripper pressure controller to the flare should be in "automatic" with its setpoint set at its normal value.
R.
The level in the TGCU Stripper Reflux Accumulator should be at the normal setpoint for the level control.
S.
A TGCU Stripper Reflux Pump should be operating with the minimum flow lined up to allow reflux to spill back into the TGCU Stripper Reflux Accumulator whenever the level valve back to the TGCU Stripper is closed.
With these operating conditions established, the back-end of the TGCU is ready to accept the process gas from the front-end of the unit and begin treating it.
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SULFUR BLOCK 11.8.5
Process Gas Flow to the TGCU Columns The last step in the startup of the TGCU is to bring the process gas from the front-end of the TGCU into the TGCU Quench Column and the TGCU Contactor. The TGCU will then remove the H2S from the gas before sending it to the TTO. The H2S removed will be stripped from the amine and sent to the flare initially. Once operation of the amine system stabilizes, this acid gas will be recycled back to the SRUs. Before introducing process gas into the TGCU columns, confirm that the following conditions are all true: 1.
The front-end of the TGCU is processing SRU tailgas and is operating smoothly on automatic control.
2.
The hydrogen controller is controlling the hydrogen concentration in the outlet of the TGCU Reactor at or above its setpoint.
3.
The proper operating conditions have been established for the quench water and amine systems (see Section 11.8.4).
If any of these conditions are not true, do not proceed until correcting the problem(s). Once all of these conditions are satisfied, complete the startup of the TGCU as follows: A.
Confirm that the Quench Column hand control in the DCS is set to 0% output with the TGCU Quench Column Inlet Valve closed and the TGCU Quench Column Bypass Valve open.
B.
Use the drain valve downstream of the TGCU Waste Heat Reclaimer to drain any liquids that may have accumulated in the TGCU Quench Column inlet line.
C.
Slowly increase the output from the Quench Column hand control to 100%, which will open the Quench Column inlet valve and admit process gas to the TGCU Quench Column, then close the TGCU Quench Column Bypass Valve to prevent gas from bypassing to the Thermal Oxidizer. Note that the pressure drop through the TGCU Quench Column and the TGCU Contactor will raise the operating pressures of the SRU and the TGCU and can affect the process gas flow rates, so allow time for the flow and flow-ratio control loops to respond.
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SULFUR BLOCK D.
When the output of the Quench Column hand control reaches 100%, the Quench Column inlet valve should be fully open and the TGCU Quench Column Bypass Valve fully closed to send all of the process gas into the TGCU Quench Column. Visually confirm that these valves are properly positioned.
E.
As process gas flows into the columns, watch the operation of the quench water system carefully. It is typical to see a slow decrease in the quench water pH as H2S in the process gas dissolves into the water, but a rapid decline in pH could indicate SO2 in the process gas from incomplete reaction in the TGCU Reactor. Be ready to add caustic if needed to keep the pH above 7. NOTE:
The quench water will probably turn black or green on this first introduction of H2S into the system (due to small particles of iron sulfide in the water). The TGCU Quench Water Filter should clear up the water in a few hours.
F.
If the quench water pH drops drastically or there is a sudden drop in the hydrogen concentration on the hydrogen controller, the process gas can be "backed" out of the columns by reducing the output of the Quench Column hand control back to 0%. This will open the TGCU Quench Column Bypass Valve to divert the gas to the TTO and close the Quench Column inlet valve to stop gas from flowing into the TGCU Quench Column. Once the operating problem is corrected and the hydrogen controller is once again showing adequate hydrogen, use the Quench Column hand control to re-initiate gas flow to the columns.
G.
Once the columns are operating stably, switch the H2/H2S analyzer to take its sample from the TGCU Contactor overhead line by checking that the sample line is clear of liquid, confirming that the sample valve on the overhead line is open, and switching the sample selector valve in the analyzer enclosure to sample from the TGCU Contactor overhead line. (Note that the sample line on the outlet from the TGCU Waste Heat Reclaimer is now being back-purged with nitrogen.) The gas stream from the TGCU Contactor is "cleaner" than the one leaving the TGCU Waste Heat Reclaimer and is less likely to cause problems in the hydrogen analyzer. However, if the Quench Column hand control is used to divert gas to the TTO during an upset as
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SULFUR BLOCK described in the previous step, the analyzer must be switched back to the outlet of the TGCU Waste Heat Reclaimer to get a good reading, as gas will no longer be flowing in the TGCU Contactor overhead line. H.
Once the operation of the TGCU Stripper has stabilized, route its acid gas, which is presently going to the flare through a pressure valve, back to the SRUs as follows: (1)
Confirm that the TGCU Stripper pressure controller to the SRUs in the DCS is in "manual" with its output set to 0%.
(2)
Confirm that the setpoint of the TGCU Stripper pressure controller to the SRUs is tracking its current reading, then place it in "automatic".
(3)
Slowly raise the setpoint of the TGCU Stripper pressure controller to the flare to 1.0 kg/cm2(g).
(4)
If, necessary, adjust the setpoint of the TGCU Stripper pressure controller to the SRU to its normal setpoint.
The TGCU Stripper pressure controller will now take over control of the TGCU Stripper pressure by opening the pressure valve to send the acid gas to the Acid Gas Knock-Out Drums in the SRUs. The TGCU Stripper pressure controller to the flare will close the acid gas pressure valve and stop the flow of acid gas to the flare. If the SRUs shut down (or some other upset causes the TGCU Stripper pressure to rise), the TGCU Stripper pressure controller to the flare will act as an over-ride and divert the acid gas to the flare. I.
If desired, the quench water and amine systems can be optimized at this time for more efficient operation, or for more capacity to handle upsets. Section 11.6 offers suggestions and guidelines for these systems. If maximizing the capacity to handle process upsets without going out of compliance is desired, consider the following suggestions: (1)
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Lower the setpoint of the temperature controller on the quench water to maximize the aerial cooling. This will cool the feed gas to the TGCU Contactor as much as possible to minimize the load on the column and improve amine selectivity and treating ability.
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SULFUR BLOCK (2)
Lower the setpoint of the temperature control on the lean amine to maximize the aerial cooling. This will cool the amine to the TGCU Contactor as much as possible to maximize the amine selectivity and treating ability.
(3)
Lower the setpoint of the temperature controller on the outlet from the TGCU Stripper Reflux Condenser as much as possible. This will minimize the water content of the TGCU acid gas returning to the sulfur plant and improve the recovery there.
The aerial coolers and trim coolers will not be able to maintain these temperatures when the ambient conditions are very warm, of course. However, setting the controllers this way will keep the fan speed high to maximize cooling at all times. J.
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The TGCU is now fully on-stream. Before directing your attention away from the TGCU, be sure that: (1)
Both SRU Tailgas Valves to the TTO and the TGCU Warmup/Bypass Valve are fully closed (to prevent leakage of SRU tailgas to the Thermal Oxidizer that would cause high SO2 emissions and the resulting permit violation).
(2)
The TGCU Quench Column Bypass Valve is fully closed (to prevent leakage of TGCU Reactor effluent to the Thermal Oxidizer that would cause high SO2 emissions and the resulting permit violation).
(3)
All controllers are functioning properly.
(4)
The steam heating systems are in service on the jacketed sulfur vapor valves and the steam traps are functioning properly.
(5)
The Thermal Oxidizer is functioning properly.
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SULFUR BLOCK 11.8.6
Normal Startup of the TGCU The procedure for startup of the TGCU after it has been shut down will be very similar to the procedure for the initial startup, Sections 11.8.1 through 11.8.5 of these guidelines, except that the catalyst will not require pre-sulfiding. For ease of reference, the steps to be performed are written in this Section to serve as a "check list" that can be easily followed on subsequent startups. Refer to the previous Sections for the reasons and details pertaining to the different steps performed. Prior to commencing TGCU startup:
11.8.6.1
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(1)
Check for the completion of all maintenance work (connecting lines, removing blinds, etc.) if such work was performed.
(2)
If any of the flanged connections in the TGCU were opened for maintenance or other purposes while the TGCU was off-line, it is good practice to leak test the TGCU before returning it to service. Refer to Section 11.7.5 of these guidelines for a suggested procedure to accomplish this.
(3)
Place all the steam heating systems on the sulfur vapor valve jackets in service. Check all steam traps for proper operation, and use the vent valves to sweep non-condensibles out of the steam spaces.
(4)
Physically check all shutdown activating devices to ensure that they activate the TGCU ESD system.
(5)
Physically check all devices activated by the TGCU ESD system to ensure that they operate properly.
Initial Preparations A.
Confirm that steam pressure controller in the DCS is in "manual" with its output set to 0%, and that control valve in the HP Steam supply line to the TGCU Reactor Feed Heater is closed.
B.
Place the reactor feed temperature controller in "automatic".
C.
Confirm that reducing gas flow controller in the DCS is in "manual" with its output set to 0%, and that the control valve in the reducing gas supply line to the TGCU Reactor Feed Mixer is closed.
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SULFUR BLOCK
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D.
Place the hydrogen controller in "automatic".
E.
Verify that the automated shutdown valves, the block valves, and the downstream steam-jacketed block valve in the reducing gas line to the TGCU Reactor Feed Mixer are all closed.
F.
Confirm that pre-sulfiding gas flow controller in the DCS is in "manual" with its output set to 0%, and that the control valve in the pre-sulfiding gas line to the TGCU Reactor Feed Mixer is closed.
G.
Verify that the automated shutdown valve and the upstream block valves in the pre-sulfiding gas line to the TGCU Reactor Feed Mixer are both closed.
H.
Confirm that the nitrogen flow controller in the DCS is in "manual" with its output set to 0% output, and that the control valve in the nitrogen supply line is closed.
I.
Verify that the shutdown valves are closed in the nitrogen supply line, and the upstream block valves are open. Open the downstream steam-jacketed block valve.
J.
Confirm that the Quench Column hand control in the DCS is set to 0% output, so that the TGCU Quench Column inlet valve will remain fully closed and the TGCU Quench Column bypass valve will open later in when the TGCU startup/run selector switch is switched to "STARTUP".
K.
Confirm that the TGCU Waste Heat Reclaimer is filled with water up to its normal liquid level.
L.
Visually confirm that both SRU Tailgas Valves to the TGCU are closed.
M.
Visually confirm that the manual TGCU Outlet Valve is fully open.
N.
Confirm that the Leak Test switch in the DCS is toggled to "OFF".
O.
Confirm that the TGCU Start-Up Blower Bypass Valve is fully open.
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SULFUR BLOCK P.
Verify that the local stop control for the TGCU Start-Up Blower is set to the "RUN" position.
Q.
Check that the sample line from the outlet of the TGCU Waste Heat Reclaimer to the hydrogen analyzer is clear of liquids. Confirm that sample valve on the outlet channel of the boiler is open, then switch the sample selector valve in the analyzer enclosure to sample from the outlet of the TGCU Waste Heat Reclaimer. Note that the other sample line on the TGCU Contactor overhead line is now being back-purged with nitrogen.
11.8.6.2
Purging the Low Pressure TGCU Columns Unless the water or the amine was drained from the low pressure TGCU columns (the TGCU Quench Column and the TGCU Contactor, respectively), or either column was opened for maintenance during the prior shutdown, the columns will not contain air and so will not require purging before proceeding with startup. However, if the activities prior to this startup did allow air to enter either or both columns, this air should be purged from the system before proceeding so that a combustible mixture cannot form in the columns as process gas is introduced. If purging of the columns is required, nitrogen can be introduced using the nitrogen flow controller to purge the air from the columns. This procedure is given in Section 11.7.8 of these guidelines. Refer to and follow this procedure to purge the columns before continuing with Section 11.8.6.3 that follows.
11.8.6.3
Establishing Nitrogen Flow To establish nitrogen flow into the TGCU, proceed as follows: A.
Toggle the Startup/Run selector switch in the DCS to "STARTUP". The PLC should perform the following actions: (a) Bypasses both SRU ESD inputs to the TGCU ESD. (b) Disables the Tailgas Valve toggle switches. (c) Opens the TGCU Quench Column Bypass Valve.
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SULFUR BLOCK B.
Reset the TGCU ESD by toggling the switch in the DCS to "RESET".
C.
Set the output of the hand control in the DCS to 0% to close the TGCU Warmup/Bypass Valve and visually confirm that the valve is closed.
D.
Toggle the Nitrogen On/Off switch in the DCS to "ON". The PLC should perform the following actions:
11.8.6.4
(1)
Opens the nitrogen block valves.
(2)
Closes the nitrogen vent valve.
E.
Increase the output of the nitrogen flow controller to 100% in the DCS to open the control valve and send nitrogen to the front-end of the TGCU.
F.
Allow the nitrogen to purge that front-end of the TGCU for 15 minutes before proceeding to the next step.
Establishing Re-circulation Flow A.
Start the TGCU Start-Up Blower using the start/stop toggle switch in the DCS. The PLC will perform the following actions: (1)
The nitrogen purge valve is closed.
(2)
The TGCU Start-Up Blower Suction Valve is opened.
(3)
The TGCU Start-Up Blower Discharge Valve is opened.
(4)
After the limit switches prove these valves open, the TGCU Start-Up Blower is started.
(5)
Once the Startup Blower is started, the TGCU Start-Up Blower Bypass Valve is closed.
As this valve is closed, the blower will start to load. As it does so, the blower will begin to "pull" nitrogen through the front-end TGCU equipment and all of the associated piping. B.
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Once the blower is running, open the TGCU Warmup/Bypass Valve by increasing the output from the hand control to 100%.
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SULFUR BLOCK As the TGCU Warmup/Bypass Valve opens, the TGCU Start-Up Blower will begin re-circulating gas from the outlet of the TGCU Waste Heat Reclaimer back to the TGCU Reactor Feed Heater (via the TGCU Contactor overhead line).
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C.
Once re-circulation has been established, place the nitrogen flow controller in "automatic" and reduce its setpoint to about 5-10% of maximum flow.
D.
Slowly begin to increase the setpoint of the steam pressure controller in the DCS to establish steam flow to the TGCU Reactor Feed Heater and increase the temperature of the re-circulating gas stream to 150-175°C.
E.
Open the vent valve on the TGCU Waste Heat Reclaimer to vent air from the steam section.
F.
Confirm that the BFW level controller and control valve to the TGCU Waste Heat Reclaimer are in service and functioning properly.
G.
Place the reactor feed temperature cascade control in service as follows: (1)
Confirm that the remote setpoint that the reactor feed temperature controller is supplying to the pressure controller matches the current setting on the pressure controller.
(2)
Confirm that the reactor feed temperature controller is in "automatic" and its setpoint is tracking its current reading.
(3)
Switch the steam pressure controller to "cascade" so that the temperature controller can now adjust the setpoint on the pressure controller.
(4)
If necessary, slowly adjust the setpoint of the reactor feed temperature controller to 175°C.
(5)
Verify that the steam pressure controller is adjusting the HP steam pressure as needed to control the desired temperature setting on the reactor feed temperature controller.
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SULFUR BLOCK 11.8.6.5
Establishing Reducing Gas Flow Before introducing SRU Tailgas into the TGCU Reactor, reducing gas must be added to the re-circulating gas stream. A.
Open the upstream manual block valves and the steam-jacketed block valve in the reducing gas supply line to the TGCU Reactor Feed Mixer.
B.
Toggle the Reducing Gas On/Off switch in the DCS to "ON". The PLC should perform the following actions:
C.
(1)
Opens reducing gas block valves.
(2)
Closes reducing gas vent valve.
Place the reducing gas controller in "automatic" and slowly begin to increase its setpoint to open the control valve and begin introducing reducing gas into the re-circulating stream. As the reducing gas flow rate increases, the hydrogen concentration displayed on the hydrogen controller will increase.
D.
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Place the hydrogen concentration cascade control in service as follows: (1)
Confirm that the remote setpoint that the hydrogen controller is supplying to the reducing gas flow controller matches the current setting on the flow controller.
(2)
Confirm that the hydrogen controller is in "automatic" and its setpoint is tracking its current reading.
(3)
Switch the reducing gas controller to "cascade" so that the concentration controller can now adjust the setpoint of the flow controller.
(4)
If necessary, slowly adjust the setpoint of the hydrogen controller to its normal value.
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SULFUR BLOCK 11.8.6.6
Routing SRU Tailgas to the TGCU The TGCU is now ready to accept tailgas from the SRUs. Before beginning, the following conditions should exist in the TGCU: 1.
The Reactor Feed Heater is operating smoothly and the inlet temperature to the TGCU Reactor is being controlled at 230-240°C.
2.
The TGCU Reactor is up to normal operating temperature and its catalyst has been pre-sulfided.
3.
The TGCU Start-Up Blower is in service, re-circulating nitrogen to the TGCU Reactor Feed Heater.
4.
The H2/H2S analyzer has been calibrated and is sampling the process gas leaving the TGCU Waste Heat Reclaimer.
5.
The hydrogen controller is controlling the hydrogen at or above the normal setpoint
6.
One or both SRUs are operating smoothly on amine acid gas, or amine acid gas and SWS gas, and the air demand indicated on the air control is +2.0% or lower. (If the air demand is higher than this, the tailgas from the SRU contains excessive amounts of SO2 and could cause overheating of the TGCU Reactor.)
If any of these conditions are not true, do not attempt to bring SRU tailgas into the TGCU. In particular, do not attempt switching tailgas into the TGCU when the SRU(s) is(are) experiencing an upset. The result will be multiple upset units to deal with. Instead, focus your attention on stabilizing the operation of the SRU(s) first (usually by correcting a problem in the upstream Amine Regeneration and/or Sour Water Stripper units), and then use the procedure that follows to establish tailgas flow into the TGCU.
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SULFUR BLOCK Introducing SRU Tailgas into the TGCU — Scenario 1 The first scenario to consider for introducing tailgas into the TGCU is a normal startup of the SRUs and the TGCU. Before being routed to the TGCU, the tailgas from both SRUs is sent to the TTO while the TGCU uses the TGCU Startup Blower to re-circulate gas to the TGCU Reactor Feed Heater via the TGCU Warmup/Bypass Valve. Once the TGCU is warmed up and ready to accept tailgas, the Train 1 and Train 2 SRUs can be routed to the TGCU as follows (using the Train 1 SRU for this procedure). A.
Confirm that the hydrogen controller is in "automatic" and controlling the hydrogen concentration at or above its normal setpoint, (3%).
B.
Toggle the SRU 1 "fast" transfer switch in the DCS, to "TRANSFER TO TGCU". The PLC will perform the following actions: (1)
The SRU 1 Tailgas Valve to the TGCU is opened.
(2)
After the limit switches prove this valve open, the SRU 1 Tailgas Valve to the TTO is closed.
Visually confirm that these valves have moved to the proper positions. C.
If the second SRU (Train 2) is also ready to send its tailgas to the TGCU, toggle the SRU 2 "fast" transfer switch in the DCS to repeat these actions for the other SRU. For this scenario, the opening and closing of Tailgas Valves to the TGCU and the Tailgas Valves to the TTO in Steps B and C can occur rapidly with no impact on either the SRU or the TGCU. This is because the TGCU Warmup/Bypass Valve will still be open at this time, so there will be very little differential pressure across the Tailgas Valves to the TGCU and there will not be an abrupt change in pressure when the Tailgas Valves to the TGCU are opened or when the Tailgas Valves to the TTO are closed. Note:
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The “fast” transfer switches can also be used to take the Train 1 SRU and/or Train 2 SRU tailgas out of the TGCU. Every other toggle of these selector switches will take the
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SULFUR BLOCK opposite action to open the tailgas valve to the TTO and then close the tailgas valve to the TGCU. D.
Slowly reduce the output from the hand control to 0% to close the TGCU Warmup/Bypass Valve. Now all of the SRU tailgas must flow through the TGCU Reactor Feed Heater, etc. as this is the only open flowpath to the TTO.
E.
Shut down the TGCU Start-Up Blower using the start/stop selector switch in the DCS. The PLC will perform the following actions: (1)
The TGCU Start-Up Blower bypass valve is opened and proved open.
(2)
The TGCU Start-Up Blower is stopped.
(3)
The nitrogen purge valve is opened.
(4)
The TGCU Start-Up Blower Suction Valve and the TGCU Start-Up Blower Discharge Valve are closed.
Confirm that these valves have moved to the proper positions and that the blower has stopped. F.
Place the nitrogen flow controller in "manual" and set its output to 0% to close the control valve and stop the flow of nitrogen into the TGCU.
G.
Toggle the Nitrogen On/Off switch in the DCS to "OFF". The PLC should perform the following actions:
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(1)
Closes nitrogen blocks.
(2)
Opens nitrogen vent valve.
H.
Close the downstream steam-jacketed block valve in the nitrogen supply line where it joins the tailgas line to the TGCU Reactor Feed Mixer.
I.
Allow the TGCU to operate in this fashion until all operating conditions are stable. In particular, observe the operation of the reactor feed temperature controller and the hydrogen controller to ensure that the TGCU Reactor inlet temperature remains under
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SULFUR BLOCK control and there is adequate hydrogen (2% or higher) in the TGCU Reactor outlet. At this point, all of the tailgas from both SRUs is flowing into the TGCU Reactor Feed Heater, mixing with the external reducing gas in the TGCU Reactor Feed Mixer, entering the TGCU Reactor to convert all of the sulfur compounds to H2S, being cooled in the TGCU Waste Heat Reclaimer, and flowing through the TGCU Quench Column Bypass Valve and the TGCU Start-Up Blower Bypass Valve to the Thermal Oxidizer via the TGCU Contactor overhead line and the TGCU Outlet Valve. Once the operation of the TGCU front-end has stabilized, the process gas can be introduced into the TGCU columns.
Introducing SRU Tailgas into the TGCU — Scenario 2 The second startup scenario to consider is when the TGCU is already processing tailgas from one SRU, and the tailgas from the second SRU needs to be introduced into the TGCU. Under this scenario, the TGCU is already processing tailgas from the Train 2 SRU. This means that the TGCU warmup/bypass valve is already closed. This signals the PLC to disable the "fast" transfer switches in the DCS, so that the rapid switching sequence (scenario 1) cannot be activated inadvertently.
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A.
Initiate the over-ride for the Train 1 tailgas valves by toggling the Train 1 "slow" transfer switch in the DCS, to "OVER-RIDE". The PLC temporarily removes the limit switches on the SRU 1 Tailgas Valve to the TTO and the SRU 1 Tailgas Valve to the TGCU from the "complete flowpath interlock" for the Train 1 SRU alarms and deactivates the "valve malfunction" alarms on these two valves, then directs the DCS to release control of the hand controls for these valves to the operator.
B.
Use the hand control to slowly begin throttling the tailgas flow with the SRU 1 Tailgas Valve to the TTO, so that the pressure at the front-end of Train 1 is slightly higher than at the front-end of the Train 2 SRU. Monitor the flows and pressure in the Train 1 SRU and adjust the hand control accordingly.
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SULFUR BLOCK C.
Once the SRU 1 Tailgas Valve to the TTO is throttling, use the other hand control to slowly open the SRU 1 Tailgas Valve to the TGCU. Some of the Train 1 tailgas may begin to flow into the TGCU at this time, but most of it will still flow through the SRU 1 Tailgas Valve directly to the TTO. Monitor the flows and pressures in the Train 1 SRU and the TGCU, and adjust the rate at which he opens the SRU 1 Tailgas Valve to the TGCU accordingly.
D.
Once the SRU 1 Tailgas Valve to the TGCU is fully open, use the hand control to slowly close the SRU 1 Tailgas Valve to the TTO the rest of the way and send all of the Train 1 tailgas to the TGCU. Monitor the flow rates and temperatures in the TGCU, and adjust the rate at which the SRU 1 Tailgas Valve to the TTO is closed to allow time for the controls in the TGCU to respond.
E.
Once the SRU 1 Tailgas Valve to the TTO is fully closed, the Train 1 SRU is flowing to the TGCU along with the Train 2 SRU, and the TGCU is fully on-line. Once both valve have moved into position, the PLC will automatically restore the limit switches on the SRU 1 Tailgas Valve to the TTO and the SRU 1 Tailgas Valve to the TGCU to the "complete flowpath interlock" in the SRU alarms, restore the malfunction alarms for these valves to their normal configurations, and reset the "slow" transfer switch in the DCS, back to "NORMAL" and remove the over-ride.
11.8.6.7
Quench Water and Amine Systems Before switching process gas into the TGCU Quench Column and the TGCU Contactor, the quench water and amine systems should be operating and ready to accept the process gas.
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A.
The quench water system should be filled with water, so that the level in the TGCU Quench Column is at the normal setpoint for the Quench Column level controller.
B.
Quench water should be circulating to the TGCU Quench Column at the normal setpoint for the quench water flow controller.
C.
Cooling water should be flowing to the TGCU Quench Water Trim Cooler and the TGCU Lean Amine Trim Cooler.
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D.
The fans should be operating on the TGCU Quench Water Cooler, with the temperature controller on the quench water controlling at its normal setpoint or lower.
E.
The TGCU Quench Water Filter should be in service with the filtered quench water flow controller controlling at its normal setpoint.
F.
The quench water pH analyzer should be in service (with one pH Meter Sample Filter in service, and the other blocked-in for use as a spare) with the quench water pH analyzer in the DCS showing a pH of 11 or higher. Add caustic to the quench water if necessary to raise the pH to this level.
G.
The amine system should be filled with amine, with the level control in the DCS controlling the level in the TGCU Contactor at its normal setpoint.
H.
The MDEA concentration in the amine should be close to its design value (45 wt %). Add more fresh MDEA if necessary to bring the amine to this strength.
I.
Amine should be circulating through the TGCU Stripper, the TGCU Lean/Rich Exchanger, the TGCU Lean Amine Cooler, and the TGCU Lean Amine Trim Cooler to the distributor tray at the top of the TGCU Contactor at the normal setpoint for the flow controller.
J.
The fans should be operating on the TGCU Lean Amine Cooler, with the temperature controller on the lean amine controlling at its normal setpoint or lower.
K.
The TGCU Rich Amine Filter should be in service.
L.
The TGCU lean amine filters should be in service, with the flow controller controlling at its normal setpoint.
M.
Steam should be flowing to the TGCU Stripper Reboiler at the normal setpoint for the flow controller.
N.
The overhead temperature from the TGCU Stripper should be above the low temperature alarm point for the temperature indicator.
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SULFUR BLOCK O.
The fans should be operating on the TGCU Stripper Reflux Condenser with the temperature controller on the outlet from the TGCU Stripper Reflux Condenser controlling at its normal setpoint or lower.
P.
The TGCU Stripper pressure controller to the SRU should be in "manual" with its output set to 0% so that the pressure valve is fully closed.
Q.
The TGCU Stripper pressure controller to the flare should be in "automatic" with its setpoint set to its normal value.
R.
The level in the TGCU Stripper Reflux Accumulator should be at the normal setpoint for the level control.
S.
A TGCU Stripper Reflux Pump should be operating with the minimum flow lined up to allow reflux to spill back into the TGCU Stripper Reflux Accumulator whenever the level valve back to the TGCU Stripper is closed.
With these operating conditions established, the back-end of the TGCU is ready to accept the process gas from the front-end of the unit and begin treating it. 11.8.6.8
Process Gas Flow to the TGCU Columns The startup of the TGCU can now be completed by switching the process gas to flow into the columns. Before introducing process gas into the TGCU columns, confirm that the following conditions are all true: 1.
The front-end of the TGCU is processing SRU tailgas and is operating smoothly on automatic control.
2.
The hydrogen controller is controlling the hydrogen concentration in the outlet of the TGCU Reactor at or above its setpoint.
3.
The proper operating conditions have been established for the quench water and amine systems.
If any of these conditions are not true, do not proceed until correcting the problem(s). Once all of these conditions are satisfied, complete the startup of the TGCU as follows:
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SULFUR BLOCK A.
Confirm that the Quench Column hand control in the DCS is set to 0% output with the TGCU Quench Column Inlet Valve closed and the TGCU Quench Column Bypass Valve open.
B.
Use the drain valve downstream of the TGCU Waste Heat Reclaimer to drain any liquids that may have accumulated in the TGCU Quench Column inlet line.
C.
Slowly increase the output from the Quench Column hand control to 100%, which will open the Quench Column inlet valve and admit process gas to the TGCU Quench Column, then close the TGCU Quench Column Bypass Valve to prevent gas from bypassing to the Thermal Oxidizer. Note that the pressure drop through the TGCU Quench Column and the TGCU Contactor will raise the operating pressures of the SRU and the TGCU and can affect the process gas flow rates, so allow time for the flow and flow-ratio control loops to respond.
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D.
When the output of the Quench Column hand control reaches 100%, the Quench Column inlet valve should be fully open and the TGCU Quench Column Bypass Valve fully closed to send all of the process gas into the TGCU Quench Column. Visually confirm that these valves are properly positioned.
E.
As process gas flows into the columns, watch the operation of the quench water system carefully. A sudden drop in pH usually indicates SO2 in the process gas from incomplete reaction in the TGCU Reactor. Be ready to add caustic if needed to keep the pH above 7.
F.
If the quench water pH drops drastically or there is a sudden drop in the hydrogen concentration on the hydrogen controller, the process gas can be "backed" out of the columns by reducing the output of the Quench Column hand control back to 0%. This will open the TGCU Quench Column Bypass Valve to divert the gas to the TTO and close the Quench Column inlet valve to stop gas from flowing into the TGCU Quench Column. Once the operating problem is corrected and the hydrogen controller is once again showing adequate hydrogen, use the Quench Column hand control to re-initiate gas flow to the columns. Tailgas Cleanup
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SULFUR BLOCK G.
Once the columns are operating stably, switch the H2/H2S analyzer to take its sample from the TGCU Contactor overhead line by checking that the sample line is clear of liquid, confirming that the sample valve on the overhead line is open, and switching the sample selector valve in the analyzer enclosure to sample from the TGCU Contactor overhead line. (Note that the sample line on the outlet from the TGCU Waste Heat Reclaimer is now being back-purged with nitrogen.)
H.
Once the operation of the TGCU Stripper has stabilized, route its acid gas, which is presently going to the flare through the pressure valve, back to the SRU as follows: (1)
Confirm that the TGCU Stripper pressure controller to the SRU in the DCS is in "manual" with its output set to 0%.
(2)
Confirm that the setpoint of the TGCU Stripper pressure controller is tracking its current reading, then place it in "automatic".
(3)
Slowly raise the setpoint of the TGCU Stripper pressure controller to the flare to 1.0 kg/cm2(g).
(4)
If necessary, adjust the setpoint of the TGCU Stripper pressure controller to its normal setpoint.
The TGCU Stripper pressure controller will now take over control of the TGCU Stripper pressure by opening the pressure valve to send the acid gas to the Acid Gas Knock-Out Drum in the SRU. The TGCU Stripper pressure controller to the flare will close the next pressure valve and stop the flow of acid gas to the flare. If the SRU shuts down (or some other upset causes the TGCU Stripper pressure to rise), the TGCU Stripper pressure controller to the flare will act as an over-ride and divert the acid gas to the flare.
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I.
If desired, the quench water and amine systems can be optimized at this time for more efficient operation, or for more capacity to handle upsets.
J.
The TGCU is now fully on-stream. Before directing your attention away from the TGCU, be sure that:
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(1)
The SRU Tailgas Valve to the TTO and the TGCU Warmup/Bypass Valve are fully closed (to prevent leakage of SRU tailgas to the Thermal Oxidizer that would cause high SO2 emissions and the resulting permit violation).
(2)
The TGCU Quench Column Bypass Valve is fully closed (to prevent leakage of TGCU Reactor effluent to the Thermal Oxidizer that would cause high SO2 emissions and the resulting permit violation).
(3)
All controllers are functioning properly.
(4)
The steam heating systems are in service on the jacketed sulfur vapor valves and the steam traps are functioning properly.
(5)
The Thermal Oxidizer is functioning properly.
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SULFUR BLOCK
11.9 Shutdown Procedures The procedures to be used in performing a planned shutdown of the TGCU will vary depending on the extent and type of work to be performed in and around the unit during the downtime period. If there are no plans for opening the TGCU such that air would be allowed entry to the catalyst bed in the TGCU Reactor, few special procedures are required in performing the shutdown. In general, unless there is a suspected problem in the TGCU Reactor or the catalyst is to be replaced, there is no benefit to be gained from opening up the TGCU Reactor. If the TGCU Reactor does not need to be opened (or exposed to significant air entry during some other maintenance procedure), there is no need to passivate the TGCU Reactor catalyst. This greatly simplifies and shortens the shutdown procedure. Section 11.9.1 that follows is an example of such a procedure. If the catalyst is to be replaced, if the TGCU Reactor must be entered, or if maintenance on some other portion of the plant will allow a significant amount of air to enter the TGCU Reactor, then more extensive and lengthy procedures must be followed to accomplish a satisfactory shutdown and minimize the time required for performance of the desired maintenance work. Section 11.9.2 that follows is an example of a procedure for this circumstance. There are a couple of special circumstances related to shutdown procedures that are also discussed. Section 11.9.3 discusses considerations for the shutdown procedure when the tubes in the TGCU Waste Heat Reclaimer are leaking. Special precautions to observe while the TGCU is shut down are discussed in Section 11.9.4. Section 11.9.5 is a discussion of emergency shutdown situations. A guide to troubleshooting the causes of unplanned shutdowns is presented to assist in quickly identifying and correcting the problem so the TGCU can be put back on-line in a minimum amount of time. The TGCU is affected directly and indirectly by shutdowns and outages that occur in other systems within the Sulfur Block. The more important aspects of the effects these other systems can have on the TGCU are discussed in Section 11.9.6. Typical shutdown procedures are outlined and discussed in the sections that follow for the more common cases. Your existing company procedures and common sense operational judgment should be used to modify these
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SULFUR BLOCK procedures as needed to serve the purpose of any given planned shutdown situation.
11.9.1
Planned Shutdown - No Reactor Entry When there are no plans to open up the TGCU Reactor, there is no need to passivate the catalyst during the shutdown procedure. Even when entry to other parts of the TGCU is planned, this can normally be accomplished without exposing the catalyst bed to significant amounts of air by using slip-blinds to isolate the TGCU Reactor prior to purging, etc. Under these circumstances, the shutdown procedure given in this section may be used as a guide. Any equipment to be opened should be properly blinded and purged with inert gas before admission of air, to avoid exposure to potentially toxic gases or the formation of flammable vapor mixtures. It is particularly important to isolate the TGCU from the reducing gas and pre-sulfiding gas supply lines. Any equipment containing amine solution that is to be opened or entered should be drained completely, then flushed with condensate or steamed out to avoid the possibility of skin or eye irritation. It is always best, but not absolutely necessary, to purge the sulfur-bearing gases from as much of the TGCU as possible prior to shutting the TGCU down. This minimizes the chance of sulfur plugging in the piping or equipment during the subsequent restart, and minimizes the purging and cleaning required prior to vessel entry. This is accomplished by diverting the SRU tailgas to the Thermal Oxidizer, then using nitrogen to purge the front-end of the TGCU to the Thermal Oxidizer. It is generally preferable to shut down the TGCU in a controlled fashion, particularly if the SRUs are to remain on-line, to minimize the impact on the other process units. If time does not allow performing a controlled shutdown, however, the unit can be shut down by simply activating the TGCU ESD system (using the manual shutdown switch). This will automatically block the feeds into the TGCU (SRU tailgas, reducing gas, pre-sulfiding gas, and nitrogen/utility air) and divert the SRU tailgas to the Thermal Oxidizer, although it results in a much bigger "bobble" to the SRUs.
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SULFUR BLOCK To shut the TGCU down in a controlled fashion and purge the sulfur-bearing gases from the front-end of the unit, proceed as follows: A.
Check that the sample line from the outlet of the TGCU Waste Heat Reclaimer to the H2/H2S analyzer is clear of liquids. Confirm that sample valve on the outlet channel of the boiler is open, then switch the sample selector valve in the analyzer enclosure to the "START-UP" position (taking sample from the outlet of the TGCU Waste Heat Reclaimer).
B.
Visually confirm that the TGCU Start-Up Blower Bypass Valve is fully open and that the DCS indicates that the valve is open.
C.
Slowly reduce the output from the Quench Column hand control in the DCS to divert the process gas from the TGCU columns and send it to the Thermal Oxidizer. The Quench Column hand control will open the TGCU Quench Column Bypass Valve, then close the TGCU Quench Column Inlet Valve.
D.
When the output of the Quench Column hand control reaches 0%, the TGCU Quench Column Bypass Valve should be fully open and the Quench Column inlet valve fully closed to send all of the process gas to the Thermal Oxidizer via the TGCU Start-Up Blower Bypass Valve. Visually confirm that these valves are properly positioned. Confirm that the DCS indicates that the TGCU Quench Column Bypass Valve is open, and that the TGCU Quench Column Inlet Valve is closed.
E.
Toggle the Nitrogen On/Off switch in the DCS to "ON". The PLC should perform the following actions:
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(1)
Opens nitrogen block.
(2)
Closes nitrogen vent valve.
F.
Open the downstream steam-jacketed block valve in the nitrogen supply line where it joins the tailgas line to the TGCU Reactor Feed Mixer.
G.
Increase the output of the nitrogen flow controller to 100% in the DCS to fully open the control valve and send nitrogen to the front-end of the TGCU.
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SULFUR BLOCK H.
Slowly increase the output from the TGCU Warmup/Bypass Valve hand control in the DCS to 100% to fully open the TGCU Warmup/Bypass Valve. Some of the SRU tailgas will continue to flow through the TGCU Reactor Feed Heater, etc. to the TTO through the TGCU Start-Up Blower Bypass Valve, but most of the tailgas will flow instead through the TGCU Warmup/Bypass Valve to the TTO.
I.
Toggle the fast transfer switch for SRU 1 in the DCS to "CLOSE". The PLC will open the SRU 1 Tailgas Valve to the TTO then close the SRU 1 Tailgas Valve to the TGCU. All of the SRU 1 tailgas is now flowing directly to the TTO via the SRU 1 Tailgas Valve, and none of the tailgas is entering the TGCU. Visually confirm that these valves have moved to the proper positions. Verify that the DCS indicates that the SRU 1 Tailgas Valve to the TTO is open and that the SRU 1 Tailgas Valve to the TGCU is closed.
J.
Toggle the fast transfer switch for SRU 2 in the DCS to "CLOSE". The PLC will open the SRU 2 Tailgas Valve to the TTO then close the SRU 2 Tailgas Valve to the TGCU. All of the SRU 2 tailgas is now flowing directly to the TTO via the SRU 2 Tailgas Valve, and none of the tailgas is entering the TGCU. Visually confirm that these valves have moved to the proper positions. Verify that the DCS indicates that the SRU 2 Tailgas Valve to the TTO is open and that the SRU 2 Tailgas Valve to the TGCU is closed. NOTE: If a status does not change, or if a valve malfunction alarm is activated, it means that the limit switches on the associated valve never confirmed that the valve moved to the proper position. If this problem cannot be corrected, it will not be possible to continue with this procedure to shut down the TGCU in a controlled fashion. Instead, use the S/D button to activated the TGCU ESD system and shut down the TGCU immediately.
K.
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Toggle the Reducing Gas On/Off switch in the DCS to "OFF".
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SULFUR BLOCK The PLC will close the reducing gas block valves, open the vent valve, and force the control valve to "manual" and 0% output. Confirm that the DCS indicates that these valves have moved to the proper position. L.
Close the steam-jacketed block valve in the reducing gas supply line.
M.
Reduce the output from the hand control in the DCS to 0% to close the TGCU Warmup/Bypass Valve. Visually confirm that the valve is closed.
N.
Now that the reducing gas has been isolated and the tailgas from the SRU has been switched to the Thermal Oxidizer, allow the front-end of the TGCU to operate in this fashion for about 15 minutes to purge the process gas out to the Thermal Oxidizer.
O.
Place the HP steam pressure controller for the TGCU Reactor Feed Heater in "manual" and set its output to 0% to close control valve.
P.
Activate the TGCU ESD system using the S/D button.
Q.
Close the steam-jacketed valve in the nitrogen supply line where it joins the tailgas line to the TGCU Reactor Feed Mixer.
R.
Close the manual TGCU Outlet Valve.
WARNING
THE OVER-PRESSURE PROTECTION FOR THE TGCU IS THROUGH THE THERMAL OXIDIZER VENT STACK. HOWEVER, IF THE TGCU OUTLET VALVE IS CLOSED WHILE THE TGCU IS SHUT DOWN, STEPS MUST BE TAKEN TO ENSURE THAT THE TGCU IS NOT COMPLETELY BLOCKED-IN BY CREATING ANOTHER OPENING FROM THE TGCU TO THE ATMOSPHERE SO THAT THE TGCU CANNOT BE OVER-PRESSURED. S.
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Visually confirm that: (1)
The SRU 1 Tailgas Valve to the TGCU is closed.
(2)
The SRU 2 Tailgas Valve to the TGCU is closed.
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T.
(3)
The TGCU Outlet Valve is closed.
(4)
The nitrogen/utility air to the TGCU Reactor Feed Heater is blocked-in and bled.
(5)
The reducing gas to the TGCU Reactor Feed Mixer is blocked-in and bled.
(6)
The pre-sulfiding gas shutdown valve is closed.
(7)
The suction and discharge valves for the TGCU Startup Blower are closed and the nitrogen purge is in service.
(8)
The TGCU Quench Column inlet valve and the TGCU Quench Column Bypass valve are closed.
(9)
All steam heating services on the sulfur vapor valve jackets are still functioning and the steam traps are operating properly.
All temperatures in the front-end of the TGCU should be monitored to confirm that no air leaks into the system (due to "drafting" from the Thermal Oxidizer, for instance) and causes a fire in the catalyst bed. If desired, a small flow of nitrogen can be introduced into the front-end of the TGCU by using the Leak Test switch in the DCS to allow opening the block valves on the nitrogen supply line, then opening the control valve to establish a small flow of nitrogen. "Crack" the TGCU Outlet Valve to allow the nitrogen to escape to the Thermal Oxidizer and prevent over-pressuring the TGCU.
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U.
Allow the TGCU amine to continue to circulate with steam flowing to the TGCU Stripper Reboiler, until the all of the H2S and CO2 have been stripped from the amine. Once the H2S/CO2 content of the "rich" amine is essentially the same as the "lean" amine, the steam can be shut off to the TGCU Stripper Reboiler.
V.
Continue to circulate the TGCU amine and operate the TGCU Lean Amine Cooler, the TGCU Lean Amine Trim Cooler, and the TGCU Stripper Reflux Condenser until the amine is cool.
W.
Once the amine is cool (60°C or less throughout the system), shut down the equipment in the following order: (1)
The TGCU Quench Water Pump.
(2)
The TGCU Rich Amine Pump.
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X.
(3)
The TGCU Lean Amine Pump.
(4)
The TGCU Stripper Reflux Pump.
(5)
The fans on the TGCU Quench Water Cooler, TGCU Lean Amine Cooler, and TGCU Stripper Reflux Condenser.
If the TGCU will be down for an extended period, special precautions should be taken to prevent the TGCU Waste Heat Reclaimer tubes from cooling to the point where water can condense inside them. Most of the corrosion that occurs in TGCUs is due to the acidic water that can form if the plant is allowed to get cold. Close the steam outlet valve on the boiler and open the vent valves on the boiler to de-pressure it. Make sure that the boiler level control continues to operate properly so that the water level does not drop below the tubes until they have cooled and the boiler is fully de-pressured. Once the boiler is de-pressured, block-in its BFW supply and drain the water from it. Then use a temporary "jumper" to supply LP steam to the boiler shell. Drain the condensate from the boiler occasionally to keep the tubes safely above the water condensation temperature (100-110°C).
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SULFUR BLOCK 11.9.2
Planned Shutdown for Reactor Entry When the TGCU Reactor must be opened for maintenance or to replace the catalyst, it is normally necessary to passivate the catalyst as a part of the shutdown procedure. After the TGCU has been operating for a period of time, the catalyst becomes pyrophoric due to the presence of iron sulfide, FeS. Exposing catalyst containing pyrophoric FeS to air may result in uncontrolled burning of the FeS to form H2S and/or SO2, which obviously will prevent the entrance of personnel into the vessel. For this reason, controlled oxidation ("passivation") of the FeS in the catalyst is carried out at low temperature (~150°C) by admitting a small air flow into the circulating gas. This converts the FeS into non-pyrophoric iron oxide, Fe2O3, while leaving the catalyst in its sulfided state. The only SO2 produced during passivation should come from the FeS present. Pre-sulfiding of the catalyst will not be required during the next startup (assuming the catalyst is not replaced). This procedure requires an ample supply of a suitable inert gas (nitrogen, etc.) to circulate through the TGCU Reactor and cool it. Make sure a supply of inert gas is available and ready to use before beginning this procedure. Utility air is used for passivating the catalyst. In an emergency, or if the catalyst is to be replaced, it can be handled in a pyrophoric state if it is kept under water or nitrogen. Soaking the catalyst in water will, however, weaken the catalyst substrate and make the catalyst more susceptible to crumbling and attrition. For this reason, and due to the corrosive nature of liquid water on the TGCU Reactor vessel and piping, this practice is not recommended. There are service companies, however, that can unload the TGCU catalyst bed after it has been cooled to near ambient temperature using nitrogen. The service company then performs all necessary work relating to removing and replacing the catalyst under a nitrogen "blanket". This eliminates the need to passivate the catalyst, reducing the time required to replace the TGCU catalyst. Some refineries and gas plants also purchase pre-sulfided replacement catalyst, resulting in less time for the subsequent startup. The procedure in this section is used to make the TGCU catalyst safe for atmospheric air replacement.
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SULFUR BLOCK A.
Follow the procedure given previously in Section 11.9.1 to purge the front-end of the TGCU, to shut down the quench water system, and to strip, cool, and shut down the amine system, but do not Activate the TGCU ESD system using the S/D button, or isolate the nitrogen supply, or close the TGCU outlet Valve (Steps P-R) in Section 11.9.1). NOTE:
B.
Do not drain the water from the TGCU Waste Heat Reclaimer (Step X in Section 11.9.1). The boiler and its BFW controls must remain in service until the completion of the catalyst passivation procedure.
Confirm that the TGCU Outlet Valve is open and start a small nitrogen purge into the bottom of the TGCU Quench Column. (This is typically done by hooking up a temporary jumper to a connection on one of the level bridles.) This will purge through both the TGCU Quench Column and the TGCU Contactor and ensure that the SO2 formed during passivation does not contaminate the quench water or the amine.
C.
If the H2/H2S analyzer is not already switched to sample from the outlet of the TGCU Waste Heat Reclaimer, check that the sample line from the outlet of the TGCU Waste Heat Reclaimer to the analyzer is clear of liquids, confirm that the sample valve on the outlet channel of the boiler is open, then switch the sample selector valve in the analyzer enclosure to the "STARTUP" position.
D.
Visually confirm that the TGCU Start-Up Blower suction block valve and discharge block valve are closed, the bypass valve is open, the nitrogen purge to the blower seal is in service, and the local "stop" control at the blower is set to the run position.
E.
Start the TGCU Start-Up Blower using the start/stop toggle switch in the DCS. The PLC will perform the following actions:
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(1)
The nitrogen purge valve is closed.
(2)
The TGCU Start-Up Blower Suction Valve is opened.
(3)
The TGCU Start-Up Blower Discharge Valve is opened.
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SULFUR BLOCK (4)
After the limit switches prove these valves open, the TGCU Start-Up Blower is started.
(5)
Once the Startup Blower is started, the TGCU Start-Up Blower Bypass Valve is closed.
As this valve is closed, the blower will start to load. As it does so, the blower will begin to "pull" nitrogen through the TGCU Reactor Feed Heater and TGCU Reactor Feed Mixer and all of the associated piping. F.
Once the blower operation has stabilized, open the TGCU Warmup/Bypass Valve by increasing the output from its hand control to 100%. As the TGCU Warmup/Bypass Valve opens, the TGCU Start-Up Blower will begin re-circulating gas from the outlet of the TGCU Waste Heat Reclaimer back to the TGCU Reactor Feed Heater (via the TGCU Contactor overhead line).
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G.
Once re-circulation has been established, place nitrogen flow controller in "automatic" and adjust its setpoint to 5-10% of maximum flow.
H.
Allow the front-end of the TGCU to operate in this manner until the following conditions are both satisfied: (1)
The hydrogen controller shows 0.5% or less hydrogen concentration in the circulating gas.
(2)
The catalyst bed in the TGCU Reactor has been cooled below 150°C per the temperatures indicated in the DCS for the catalyst bed and for the reactor outlet.
I.
Verify that the utility air flow controller is in "manual" and set to 0% output.
J.
Verify that flow control valve, the upstream block valve, and the downstream block valve are all closed in the utility air supply line.
K.
Rotate the spectacle blind in the utility air line to the "open" position, then open the upstream block valve and the downstream block valve.
L.
Slowly increase the output from the flow controller to open the flow valve and admit a small amount of utility air into the circulating gas and begin passivating the catalyst. A maximum oxygen
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SULFUR BLOCK concentration in the range of 0.5-1.0% will probably be required during the initial stages of passivation.
CAUTION THE AMOUNT OF AIR ADDED MUST BE LIMITED INITIALLY TO AVOID EXCESSIVE TEMPERATURE RISE ACROSS THE TGCU REACTOR AS THE FeS IN THE CATALYST IS OXIDIZED. TEMPERATURES IN EXCESS OF 175°C MAY CAUSE THE SULFIDED CATALYST TO REACT WITH THE OXYGEN. IF THIS OCCURS, THE CATALYST WILL HAVE TO BE PRE-SULFIDED DURING THE NEXT STARTUP. ALSO, CATALYST DAMAGE MAY OCCUR IF LOCAL CATALYST TEMPERATURES BECOME EXCESSIVE. DO NOT ALLOW THE CATALYST BED TEMPERATURES TO EXCEED 150°C. REDUCE THE UTILITY AIR FLOW AS NECESSARY TO KEEP THE REACTOR BED TEMPERATURES AND THE OUTLET TEMPERATURE AT 150°C OR BELOW. M.
As the temperature rise across the reactor starts to decrease, the oxygen concentration in the circulating gas may be increased by using the flow controller to open the flow valve further and increase the air flow into the circulating stream.
N.
When there is no longer any temperature rise across the reactor, the passivation of the catalyst is complete. Discontinue the flow of nitrogen to the front-end of the TGCU by placing the nitrogen flow controller in "manual" and setting its output to 0% to close the control valve. Observe the TGCU Reactor temperatures to ensure that no further reaction occurs (leave the nitrogen flowing to the TGCU Quench Column). If the catalyst bed temperatures start to rise when the nitrogen flow is discontinued, re-establish nitrogen flow until the bed cools again, then stop the nitrogen flow. Repeat this step as necessary until there is no temperature rise in the reactor with the nitrogen flow shut off.
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SULFUR BLOCK O.
Once the nitrogen flow has been discontinued, the TGCU Start-Up Blower is no longer needed for re-circulation. Shut down the blower as follows: (1)
Reduce the output from the hand control to 0% to close the TGCU Warmup/Bypass Valve and stop the recycle flow to the TGCU Reactor Feed Heater. Verify that the valve has closed, and that the DCS indicates that this valve has closed.
(2)
Shut down the blower using the start/stop selector switch in the DCS. The PLC will open the TGCU Blower Bypass Valve, stop the blower, turn on the nitrogen purge, and close its suction and discharge valves. Verify that the DCS indicates each valve has moved to the proper position.
P.
Use the flow controller to raise the utility air flow to 80% or more and allow air to cool the TGCU Reactor. Continue the air flow until the temperature leaving the TGCU Reactor is about the same temperature as the air entering the TGCU Reactor.
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Q.
At the completion of the cooling operation, activate the TGCU ESD using the S/D button to shut down and isolate the utility air.
R.
Close the upstream block valve and the downstream block valve in the utility air supply line, then rotate the spectacle blind to the "closed" position. Close the steam-jacketed block valve at the junction with the tailgas line to the TGCU Reactor Feed Heater.
S.
Discontinue the flow of nitrogen to the TGCU Quench Column, then close the TGCU Outlet Valve.
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SULFUR BLOCK
WARNING
THE OVER-PRESSURE PROTECTION FOR THE TGCU IS THROUGH THE THERMAL OXIDIZER VENT STACK. HOWEVER, IF THE TGCU OUTLET VALVE IS CLOSED WHILE THE TGCU IS SHUT DOWN, STEPS MUST BE TAKEN TO ENSURE THAT THE TGCU IS NOT COMPLETELY BLOCKED-IN BY CREATING ANOTHER OPENING FROM THE TGCU TO THE ATMOSPHERE SO THAT THE TGCU CANNOT BE OVER-PRESSURED. T.
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Visually confirm that: (1)
The SRU 1 Tailgas Valve to the TGCU is closed.
(2)
The SRU 2 Tailgas Valve to the TGCU is closed.
(3)
The TGCU Outlet Valve is closed.
(4)
The nitrogen to the TGCU Reactor and the TGCU Quench Column is positively isolated from the TGCU.
(5)
The pre-sulfiding gas shutdown valve is closed.
(6)
The TGCU Start-Up Blower is shut down, with its suction and discharge valves closed and the nitrogen purge in service.
(7)
The TGCU Quench Column inlet valve and the TGCU Quench Column bypass valve are closed.
(8)
All steam heating services on the sulfur vapor valve jackets are still functioning and the steam traps are operating properly.
U.
The TGCU catalyst is now passivated and cooled, and can be safely handled. The TGCU is now ready to be isolated and made safe for entry.
V.
If the TGCU will be down for an extended period, special precautions should be taken to prevent the TGCU Waste Heat Reclaimer tubes from cooling to the point where water can condense inside them. Most of the corrosion that occurs in TGCUs is due to the acidic water that can form if the plant is allowed to get cold.
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SULFUR BLOCK Close the steam outlet valve on the boiler and open the vent valves on the boiler to de-pressure it. Make sure that the boiler level control continues to operate properly so that the water level does not drop below the tubes until they have cooled and the boiler is fully de-pressured. Once the boiler is de-pressured, block-in its BFW supply and drain the water from it. Then use a temporary "jumper" to supply LP steam to the boiler shell. Drain the condensate from the boiler occasionally to keep the tubes safely above the water condensation temperature (100-110°C).
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SULFUR BLOCK 11.9.3
Shutting Down When Boiler Tubes Are Leaking One special circumstance that merits discussion is shutting down the TGCU when there are tube leaks in the TGCU Waste Heat Reclaimer. While the plant is running, minor tube leaks usually cause little damage because the hot process gas vaporizes the boiler feed water before it has a chance to form acid and cause rapid corrosion. When the TGCU is shut down, however, several problems can develop: 1.
Liquid water may accumulate in the equipment or piping and form a variety of acids (sulfurous, polythionic, etc.) that will rapidly corrode the steel.
2.
Water and/or steam may reach the TGCU Reactor catalyst and weaken or damage it.
If a boiler tube leak is suspected, a shutdown procedure similar to the following may be appropriate:
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A.
Switch the SRU tailgas from the TGCU to the Thermal Oxidizer.
B.
Activate the TGCU ESD system using the S/D button.
C.
Close the TGCU Outlet Valve.
D.
De-pressure the TGCU Waste Heat Reclaimer, taking care to reduce the pressure slowly enough to avoid over-stressing the boiler.
E.
Maintain a visible water level in the boiler. Water must remain in the boiler until it is de-pressured to prevent overheating damage to the tubes.
F.
Once the boiler is fully de-pressured, drain the water from the boiler to prevent any further leakage into the process side of the equipment.
G.
The TGCU is now ready to be isolated and made safe for entry.
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SULFUR BLOCK 11.9.4
Special Precaution During Shutdowns
CAUTION
THE FOLLOWING PROCEDURE IS VERY IMPORTANT TO PROTECT THE TGCU DURING SHUTDOWNS. FAILURE TO OBSERVE THESE PRECAUTIONS CAN LEAD TO "STUCK" VALVES IN THE PROCESS GAS LINES, RESULTING IN AN EXTENSIVE (AND EXPENSIVE) SHUTDOWN TO REPAIR THE VALVE(S). When a TGCU is shut down for any appreciable length of time, water vapor in the process gas can condense and accumulate in the low spots. Since the process gas contains CO2, H2S, SO2, and other compounds, the condensed water can be quite acidic. As this acid water trickles over the piping, it corrodes the metal. If this water then reaches a steam-jacketed valve or pipe, the water will boil away and deposit the corrosion products on the heated surface. This occurrence can quickly cause a steam-jacketed valve to become "stuck", which usually results in an extended shutdown to repair the valve before that TGCU can be restarted. This problem can be prevented, by keeping water from accumulating near these valves during shutdowns. The valves to be protected are: TGCU Warmup/Bypass Valve TGCU Outlet Valve The most positive means for preventing condensation of water in the unit is to purge it with inert gas (nitrogen, etc.). One way to accomplish this is as follows:
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A.
Confirm that the Quench Column hand control in the DCS is set to 0% output.
B.
Confirm that the SRU Tailgas Valve to the TGCU is closed.
C.
Confirm that the Leak Test switch in the DCS is toggled to "OFF".
D.
Switch the Startup/Run selector switch in the DCS to "STARTUP".
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SULFUR BLOCK The PLC will open the TGCU Quench Column Bypass Valve. Verify that the DCS indicates that the Quench Column Bypass Valve is open. E.
Toggle the Leak Test switch to "ON".
F.
Close the TGCU Warmup/Bypass Valve by reducing the output of the hand control to 0%. Verify that the DCS indicates that the valve has closed.
G.
Verify that the TGCU Start-Up Blower Bypass Valve is open and that the DCS indicates that the valve is fully open.
H.
Open the steam-jacketed block valve in the nitrogen supply line.
I.
Toggle the Nitrogen On/Off switch in the DCS to "ON".
J.
Place the nitrogen flow controller in "manual" and adjust its output to open the control valve slightly and establish a small flow of nitrogen into the front-end of the TGCU.
K.
"Crack" the TGCU Outlet Valve open slightly to allow the nitrogen to flow to the Thermal Oxidizer. Adjust the TGCU Outlet Valve to "pinch" so that the pressure in the TGCU is slightly positive (about 0.07-0.15 kg/cm2(g)) on the pressure indicator in the DCS.
L.
With the valves arranged in this manner, the purge gas will proceed as follows: (1)
Through the TGCU Rector Feed Heater, TGCU Reactor Feed Mixer, TGCU Reactor, and TGCU Waste Heat Reclaimer.
(2)
Through the TGCU Quench Column Bypass Valve.
(3)
Through the TGCU Start-Up Blower Bypass Valve.
(4)
Through the TGCU Contactor overhead line, flowing past the TGCU Warmup/Bypass Valve.
(5)
Through the TGCU Outlet Valve and out to the Thermal Oxidizer.
This will keep purge gas sweeping through or past all of the steam-jacketed process gas valves so that condensed water will not accumulate and cause problems.
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SULFUR BLOCK If it is not possible to purge the TGCU with inert gas while it is shut down, it is possible to protect these valves by using drain valves to prevent the accumulation of water near the steam-jacketed valves. In order to accomplish this, drain valves in the following locations are used: (1)
In the bottom of the TGCU Contactor overhead line, between the TGCU Warmup/Bypass Valve and the TGCU Warmup/Bypass Valve.
(2)
In the bottom of the outlet line from the TGCU Waste Heat Reclaimer.
With these drain valves open, there should not be significant accumulation of condensed water near any of the steam-jacketed process gas block valves.
WARNING BE CERTAIN THAT THE SRU TAILGAS VALVES TO THE TGCU, AND THE TGCU OUTLET VALVE ARE CLOSED IF THE SRU IS OPERATING WHEN THE TGCU IS SHUT DOWN. LEAVING EITHER OF THESE VALVES OPEN WHILE THE SRU IS OPERATING WILL ALLOW SRU TAILGAS TO ENTER THE TGCU, RESULTING IN SOLVENT CONTAMINATION, CORROSION DAMAGE, AND POSSIBLE PERSONNEL EXPOSURE TO H2S AND SO2. MAKE CERTAIN ALL THESE DRAIN VALVES ARE CLOSED BEFORE ATTEMPTING TO RESTART THE TGCU. To use these drain valves, proceed as follows:
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A.
Confirm that the SRU Tailgas Valves to the TGCU are closed.
B.
Close the TGCU Outlet Valve. Make sure that this valve is closed tightly.
C.
Open the two special drain valves. Observe appropriate precautions to prevent personnel exposure to H2S and/or SO2 that may still be contained in the unit, or that may leak into the
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SULFUR BLOCK unit later. It is recommended that warning signs be posted to identify the hazard that exists near these drain valves.
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D.
Check the drain valves periodically to be sure that process gas is not escaping to the surroundings.
E.
Close the drain valves before attempting to restart the TGCU.
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SULFUR BLOCK 11.9.5
Emergency Shutdown The TGCU ESD system can be initiated by any of the actuating devices outlined in Section 11.5 of these guidelines. The operator must determine and correct the condition causing the shutdown before the TGCU can be restarted. The problems outlined below should be investigated first by the operator in his troubleshooting procedure.
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S/D Actuation Device TGCU Reactor High-High Outlet Temperature
Possible Causes 1. The sulfur plant(s) is(are) off-ratio causing the SRU tailgas stream to contain large amounts of SO2, resulting in excessive heat release in the catalyst bed. 2. Malfunction of the reactor feed heater temperature control system or control valve. 3. The utility air normally used during shutdown operations to passivate the catalyst has been left open.
TGCU Waste Heat Reclaimer Low-Low Level
1. Loss of make-up water supply pressure. 2. Make-up water line plugged, or manual block valve closed or pinched. 3. Malfunction of the level control system. 4. Manual blowdown valve left open.
Complete Flowpath Interlock
1. The TGCU outlet block valve is not fully open. 2. An automated process gas valve in the TGCU has failed to open fully as directed by the PLC. 3. Malfunction of the limit switch is causing a false indication that the valve is not open.
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SULFUR BLOCK 11.9.6
Effects of Shutdowns and Outages in Other Systems The Tailgas Cleanup system is directly or indirectly affected by shutdowns and/or outages in five other systems in the complex. These effects are described below.
11.9.6.1
Amine Regeneration Unit Outages Amine acid gas flow from the Amine Regeneration Unit(s) can be interrupted for a variety of reasons. For instance, the gas flow to the absorber in the complex can be blocked manually or automatically, the amine flow from the flash tank to the stripper can be interrupted, etc. When these events occur, the acid gas flow will not cease immediately due to the residence time in the amine distribution piping, the flash tank, and the stripper. If processing in the affected Amine Regeneration Unit is restarted within the time frame of this system residence time, the amine acid gas flow to the SRUs upstream of the TGCU will probably dip, but should not stop completely. If the interruption in the Amine Regeneration Unit is long enough, though, the amine acid gas flow can fall far enough to cause the acid gas flame(s) in the SRU(s) to become unstable, at which point the SRU ESD system will be activated by "flame failure". Section 11.9.6.3 below describes the effect of this on the TGCU.
11.9.6.2
Sour Water Stripper Outages SWS gas flow from the Sour Water Stripper can also be interrupted for a variety of reasons. However, since the loss of SWS gas flow to the SRUs generally has minimal impact, outages in this system are usually of little consequence to the SRUs or the TGCU.
11.9.6.3
Sulfur Recovery Unit ESD System The SRU ESD systems stop the flow of acid gas to the affected SRU. As a result, the tailgas flow from that SRU ceases almost immediately. If only a single SRU shuts down, the TGCU will stay online processing SRU tailgas from the remaining SRU. However, if both SRUs shutdown, then there would be no SRU tailgas flowing through the front-end of the TGCU, and consequently nothing to process. So, the TGCU is shut down whenever the both of the sulfur plants shut down.
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SULFUR BLOCK However, if the TGCU is not yet processing tailgas from either SRU, there is no reason to shut it down if the SRUs are not running. This simplifies startup of the TGCU by allowing its ESD system to be independent of the SRU ESD systems until tailgas is introduced into the TGCU. 11.9.6.4
Thermal Oxidizer ESD System A TTO ESD has no direct effect on the TGCU, as the flow of TGCU effluent to the Thermal Oxidizer will not be interrupted. However, when the TTO ESD shuts down the Thermal Oxidizer Burner, the sulfur compounds in the Thermal Oxidizer feed gas will no longer be oxidized to sulfur dioxide. This means that hydrogen sulfide will be vented to the atmosphere from the top of the Thermal Oxidizer Vent Stack. Under normal circumstances, this is not a cause for concern because the TGCU is processing the SRU tailgas. Since the H2S content of the TGCU effluent should be low and the stack is tall, dangerous ground level concentrations of H2S should not develop. However, note the warning that appears in Section 12.6.2 of these guidelines regarding high temperature in the Thermal Oxidizer if the SRU tailgas and/or TGCU effluent gas contains excessive amounts of H2S. Also, note that the operating permit for this plant may not allow venting un-incinerated gases for extended periods. Review the permit before operating in this mode for a lengthy period. If the H2S concentration in the TTO feed gas is high (above 3.0%), do not attempt to restart the Thermal Oxidizer. Instead, direct your attention to the amine or SWS unit upstream of the SRUs that is probably causing the problem and bring the SRUs back on-ratio. This will allow the TGCU to reduce the H2S concentration in the Thermal Oxidizer feed gas to an acceptable level, so that restart of the Thermal Oxidizer can proceed smoothly. Failure to correct the upstream problem(s) first will likely lead to the TTO shutting down again on high-high temperature, requiring another restart of the TTO.
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SULFUR BLOCK 11.9.6.5
Steam System Outage There are three impacts on the TGCU if the complex steam system is shut down. One of these will only create problems if the steam supply to the TGCU is unavailable for a long period of time - the heating for the steam-jacketed process gas valves will be lost, possibly leading to solid sulfur freezing in these valves. The most immediate impact on the TGCU will be the loss of LP steam to the TGCU Stripper Reboiler if the steam outage lasts long enough. As the heat input to the reboiler declines, stripping of the acid gas from the amine will decline and the H2S in the TGCU effluent gas leaving the TGCU Contactor will begin to increase. This will quickly lead to high SO2 emissions from the Thermal Oxidizer Vent Stacks as indicated in the DCS. A third impact on the TGCU will be the loss of LP steam to the stripper reboilers in the Amine Regeneration Unit if the steam outage lasts long enough. As the heat input to the reboilers declines, stripping of the acid gas from the amine will decline and the amine acid gas flow rate to the SRUs will gradually diminish. If the amine acid gas flow falls far enough to cause an acid gas flame to become unstable, the SRU ESD system will be activated by "flame failure" as described previously in the discussion about the Amine Regeneration Unit outages, with the resulting impact on the TGCU as previously described in Section 11.9.6.3.
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SULFUR BLOCK
11.10 Analytical Procedures This Section contains analytical procedures for determining: 1.
The concentrations of total amine in the TGCU solvent (Section 11.10.2).
2.
The concentrations of H2S and CO2 in the TGCU solvent (Sections 11.10.3 and 11.10.4).
3.
The foaming tendency of TGCU solvent (Section 11.10.5).
4.
The H2S content of the TGCU Contactor overhead gas (Sections 11.10.6 and 11.10.7).
5.
The performance level of the TGCU Reactor catalyst (Section 11.10.8).
11.10.1 General Procedures for Analyzing TGCU Solvent1,2 An amine solution which is to be analyzed should first be inspected visually. If conducted by an experienced person, such an inspection will often yield important clues to the identity of a number of contaminants. For example, a green color in an amine solution usually indicates finely divided iron sulfide in sub-colloidal particle size (<1 micron), whereas a finely divided black suspension indicates the presence of larger (>3 micron) iron sulfide particles. A green or blue solution can indicate the possibility of either copper or nickel, while an amber colored solution may contain suspended or dissolved iron oxide. Iron may complex with the amine an give the solution an amber or dark red color. Thermal degradation of the amine may give the solution a dark red to brown color. Amines sometimes display a red or dark brown color resulting from oxidation, particularly when combined with thermal degradation. An oil slick on the solution or an oil-like odor is indicative of hydrocarbon contamination. The presence of these contaminants, however, must be proven by analysis. The next step in analyzing an amine solution is the determination of the percent amine and the acid gas content (H2S and CO2). Both rich and lean solutions may be analyzed for these constituents, and from the analyses the extent of acid gas loading and efficiency of stripping can be ascertained. Procedures for these analyses are given in Sections 11.10.2 through 11.10.4 that follow. 1 2
The Dow Chemical Company, Gas Conditioning Fact Book, 1962, pp. 310-311. Dow Chemical U.S.A., Gas Treating from Dow, 1987, pp. 8-1-1 – 8-1-2.
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SULFUR BLOCK In addition to the procedure in Section 11.10.2, the amine concentration of the solvent can be determined by performing Kjeldahl and Van Slyke nitrogen analyses. The Kjeldahl determination indicates the total nitrogen content of the solution, including nitrogen from the amine and from amine degradation products. The Van Slyke method, on the other hand, shows amine content, but does not reveal the extent to which the original amine has been degraded or tied up as heat stable salts. The difference between the results obtained through Kjeldahl and Van Slyke analyses usually indicates the degree of amine degradation. As would be expected, little difference is obtained with initial or unused solution. These analyses are not commonly performed in plant laboratories, but are generally left to the chemical solvent supplier. Heat stable salts can also be determined by a total anion assay. The amine solution is passed through an ion exchange column containing ion exchange resin in the hydrogen form. Acid salts are thus broken down and the acids recovered in the column effluent, while the amine is absorbed in the column. The acid in the effluent is determined by potentiometric titration, and from these results plus the original amine concentration the amount of amine in the form of heat stable salts is calculated. Again, this type of analysis is commonly left for the chemical solvent supplier to perform. The foaming characteristics of an amine solution are determined empirically in a simple apparatus consisting of an air (or gas) supply, pressure regulator or gas manometer, graduated glass cylinder, and a gas dispersion tube. The amine solution is poured into the graduated cylinder and air passed through at a constant rate. After five minutes, the height of the foam is recorded, the air flow is interrupted, and the time for the foam to break is determined. The results thus obtained will indicate whether or not evaluation of anti-foam agents is desirable. Section 11.10.5 describes this procedure more completely. A water analysis can be conducted on the amine solution to obtain a material balance and serve as an approximate check on the amine concentration. This is typically determined using the Karl Fischer method of analysis, but most plant laboratories leave this procedure to the chemical solvent supplier. Ordinarily, the above analyses will provide an accurate picture of the condition of the amine plant solution. At times, however, unusual operational difficulties may be encountered in amine sweetening units
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SULFUR BLOCK because of contaminants which are not revealed by the usual analytical methods. When this occurs, infrared spectroscopic analysis may often be utilized to good advantage. Infrared spectroscopy is based on the principle that each molecule or functional group exhibits its own particular absorption characteristics when exposed to infrared light of a definite wavelength. A wide variety of functional groups can be readily detected and identified by infrared techniques. For example, it has been found that degraded or oxidized amine solutions may contain ammonia, formic acid, a di-functional acid, a carbonyl compound yielding a glyoxal dinitrophenylhydrazone derivative, and a high molecular weight material that exhibits the characteristics of a Jones polymer. Also, both mono- and di-substituted amines have been identified. Each component exhibits its own particular effects on corrosion, foaming, and acid gas absorption, effects which can be determined only by the separate evaluation of each contaminant. Once these effects are determined, a knowledge of functional groups present and their relative concentration makes it possible to anticipate which types of contaminants may be causing difficulties. The chemical solvent supplier can usually perform this type of analysis more easily than the plant laboratory. Steps should be taken to ensure that the amine solution samples taken are representative of the circulating solvent. Samples should be taken in glass or plastic containers. Metal containers will cause low results for H2S because sulfides will react with the metal walls of the container. Do not use copper tubing to withdraw the samples; the copper will contaminate the amine solution, and H2S will react with the copper and give low results. Special care should be exercised when taking samples of the rich amine solution to avoid personnel exposure to H2S. Hot, fully loaded amine solution can flash acid gas when released to atmospheric pressure, causing low acid gas loading results in addition to the dispersion of H2S to the surroundings. Take samples of the rich solution from the coolest point in the process (the TGCU Contactor outlet, usually), and cool the samples in a stainless steel coil immersed in an ice bath or cold water to prevent flashing. The solution should be allowed to flow to a drain in this fashion for several minutes before taking the sample to be sure that circulating amine is being taken.
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SULFUR BLOCK In the laboratory procedures that follow, several different reagents are used that can be harmful if proper care is not exercised. Acids, bases, and flammable substances are utilized in these procedures, so adherence to proper laboratory safety practices is necessary to ensure the safety of all personnel.
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SULFUR BLOCK 11.10.2 Determination of Amine Concentration in TGCU Solvent The amine concentration in the TGCU solvent can be determined by acid titration of the lean solution. This technique is not specific for free amine, however, as amine present in the solution as an amine-acid salt will also react during the titration. This technique will also give erroneous results if there are other basic materials in the solution, such as caustic or soda ash (sometimes used to "neutralize" heat stable salts). 1.
Reagents:
2.
Procedure:
3.
Distilled or Deionized Water 0.5 N Hydrochloric Acid (HCl) Bromophenol Blue Indicator (3',3'',5',5''-tetrabromophenolsulfonephthalein)
a.
Place about 95 ml of distilled or deionized water in a 250 ml beaker or Erlenmeyer flask.
b.
Add about 5 ml of lean amine solution to the water in the beaker via pipette, recording the actual quantity.
c.
Add 5 drops of Bromophenol Blue indicator to the solution in the beaker and stir well.
d.
Titrate the solution in the beaker with 0.5 N HCl to a faint yellow color. Alternatively, if a pH meter is available, titrate to a pH of 4.5. Record the amount of HCl used in the titration.
Chemical reaction involved: R2HN + HCl
+
R2HNH + Cl
–
where R2HN = CH3-N-(CH2-CH2-OH)2 = MDEA (methyldiethanolamine) As the hydrochloric acid is added to the solution, it reacts with the amine to form a chloride salt. Once all the amine has reacted, the continued addition of acid causes the pH of the solution to drop, until the Bromophenol Blue indicator changes from blue to yellow. Note that HCl reacts with the amine on a 1:1 molar basis.
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SULFUR BLOCK 4.
Calculation of Weight Percent Amine:
ml HCl Normality of Amine 100% Used HCl Solution Weight % Mole Amine Weight 1000 ml / l ml of Sp. Gravity of Sample Amine Sample The molecular weight of MDEA is 119.17, and the specific gravity of the solution at room temperature (20°C) is about 1.059, assuming the solution is about 45 wt% MDEA. The equation can then be simplified to:
ml HCl Normality of Used HCl Solution Weight % Amine 11.253 ml of Sample
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SULFUR BLOCK 11.10.3 Determination of Total Acid Gas Loading in TGCU Solvent The total acid gas (H2S + CO2) loading, relative to the amine concentration, in either the lean or rich TGCU solvent can be determined by base titration of the solution. This procedure does not distinguish between H2S and CO2. However, together with the procedure in Section 11.10.4, the individual concentrations of H2S and CO2 can be determined. 1.
Reagents:
2.
Procedure:
3.
Methanol (CH3OH), Anhydrous 0.5 N Potassium Hydroxide (KOH) Solution in Methanol Thymolphthalein Indicator in Methanol
a.
Place about 125 ml of methanol in a 250 ml beaker or Erlenmeyer flask.
b.
If a pH meter is available, insert the pH meter probe into the methanol in the beaker and adjust the pH of the methanol to 11.2 by titrating the methanol in the beaker with the 0.5 N KOH.
c.
If a pH meter is not available, add 5 drops of Thymolphthalein indicator to the methanol in the beaker. Titrate the solution in the beaker with 0.5 N KOH until the solution turns a faint blue color, indicating a pH of 11.2. The change to faint blue will be sudden, so add the KOH slowly (one drop at a time).
d.
Add about 20 ml of lean amine solution to the methanol in the beaker via pipette, recording the actual quantity. If rich amine solution is being tested, use about 10 ml of solution instead.
e.
Titrate the solution in the beaker with 0.5 N KOH back to a pH of 11.2 (or until the solution again turns a faint blue color when using Thymolphthalein indicator). Record the amount of KOH used in this titration.
Chemical reactions involved: +
–
H2S + KOH
K + HS + H2O
CO2 + KOH
K + HCO3
+
–
As the potassium hydroxide is added to the solution, it reacts with the H2S and CO2 to form potassium hydrosulfide and potassium
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SULFUR BLOCK hydrogen carbonate salts. Once all of the acid gas has reacted, the continued addition of base causes the pH of the solution to rise, until the Thymolphthalein indicator changes from colorless to blue. Note that KOH reacts with H2S and CO2 on a 1:1 molar basis. 4.
Calculation of Acid Gas Loading (molar basis): ml KOH Normality of Used KOH Solution Moles Acid Gas Amine 100% Mole Mole Amine Weight 1000 ml / l ml of S.G. of Wt % Amine Sample Sample in Solvent
Note that "ml KOH used" refers to the amount used in the second titration, step 2.e. The "wt % amine in solvent" can be determined using the procedure in Section 11.10.2. The molecular weight of MDEA is 119.17, and the specific gravity of the solution at room temperature (20°C) is about 1.059, assuming the solution is about 45 wt% MDEA. The equation can then be simplified to:
ml KOH Normality of Used KOH Solution Moles Acid Gas 11.253 ml of Wt % Amine Mole Amine Sample in Solvent 5.
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Special Considerations: a.
Excess moisture in the equipment will give false readings. Water may be used to clean the equipment if the equipment is thoroughly dried prior to use with the anhydrous methanol.
b.
The faint blue titration endpoint using Thymolphthalein indicator is not definite. It may best be determined by comparing the color of the solution against a reference prepared by titrating a second sample of methanol-Thymolphthalein to the same color.
c.
The KOH solution and Thymolphthalein indicator solution should be kept tightly closed to prevent loss of methanol by vaporization. Any vaporization of methanol from the KOH solution will change the normality of the solution.
d.
The Thymolphthalein indicator solution can be prepared by dissolving 5 grams of thymolphthalein in 100 ml of anhydrous methanol.
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SULFUR BLOCK 11.10.4 Determination of H2S and CO2 Loading in TGCU Solvent The H2S loading, relative to the amine concentration, in either the lean or rich TGCU solvent can be determined by titration of the solution with iodine. Since CO2 does not react with iodine, this procedure is specific for H2S. Together with the total acid gas loading determined using the procedure in Section 11.10.3, the individual concentrations of H2S and CO2 can be determined. 1.
Reagents:
Distilled or Deionized Water Concentrated Hydrochloric Acid (HCl) or Sulfuric Acid (H2SO4) Standard Starch Solution - 1% 0.1 N Iodine Solution (I2) 0.1 N Sodium Thiosulfate Solution (Na2S2O3)
2.
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Procedure: a.
Measure about 25 ml of chilled iodine solution and place it in a 250 ml beaker or Erlenmeyer flask. Record the amount of iodine solution used.
b.
Carefully add about 25 ml of concentrated acid to the beaker.
c.
Add about 5 ml of standard starch solution to the beaker, then re-chill the beaker in an ice batch for 2-3 minutes.
d.
Slowly add 10-20 ml of lean amine solution to the solution in the beaker via pipette, recording the actual quantity. If rich amine solution is being tested, use 1-2 ml of solution instead.
e.
Use about 25 ml of distilled or deionized water to rinse the inside of the beaker, then swirl the contents gently to mix the solution without splashing it.
f.
Titrate the excess iodine in the sample with the sodium thiosulfate solution until the blue color disappears. The end point is a pale yellow or clear color. The approach of the endpoint is usually indicated by a milky brown tint at the top of the liquid surface. As the endpoint nears, slow the rate of titration and use a small amount of distilled or deionized water to wash the flask. Record the amount of sodium thiosulfate solution used in this titration.
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SULFUR BLOCK g.
3.
Check the pH of the titrated solution with pH paper to be sure the solution is acidic. If the solution is not acidic, repeat the procedure but use more acid in step 2.b.
Chemical reactions involved: H2S + I2
S + 2 HI
I2 + Na2S2O3
2 S + NaI + NaIO3
When the solvent is added to the iodine solution, the H2S in the solvent reacts with the iodine to form hydrogen iodide and elemental sulfur. The solution contains an excess of iodine to ensure that all of the H2S reacts. The iodine solution is chilled prior to adding the solvent to eliminate or minimize the evolution of H2S gas. Note that H2S reacts with iodine on a 1:1 molar basis. When the sodium thiosulfate solution is added to the solution, it reacts with the remaining iodine to form sodium iodide and sodium iodate, along with more elemental sulfur. (It is this elemental sulfur that may cause the titrated solution to appear pale yellow.) Once the last bit of iodine is consumed, the starch solution loses its characteristic blue color. The amount of H2S in the solvent sample is then calculated from the difference between the total iodine and the iodine that reacts with the sodium thiosulfate. Note that sodium thiosulfate reacts with iodine on a 1:1 molar basis. The purpose of the concentrated acid is to neutralize the amine so that it will release the H2S (a weaker acid) so it can react with the iodine. If the titrated solution is not acidic in step 2.g, then the amine was not fully neutralized and the H2S determination will not be correct. 4.
Calculation of H2S Loading (Molar Basis): g - moles ml I2 Normality of 1 liter 1 g - mole I2 Used used I2 Solution 1000 ml 2 g - equivalent
g - moles ml Normality of 1 liter 1 g - mole Na2S2O3 Na2S2O3 Na2S2O3 used Solution 1000 ml 2 g - equivalent Used
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SULFUR BLOCK g - moles g - moles Amine I2 Used Na2S2O3 Used Moles H2S Mole 100 % Mole Amine Weight ml of S.G. of Wt % Amine Sample Sample in Solvent
The "wt % amine in solvent" can be determined using the procedure in Section 11.10.2. The molecular weight of MDEA is 119.17, and the specific gravity of the solution at room temperature (20°C) is about 1.059, assuming the solution is about 45 wt% MDEA. Using these values and substituting the first and second equations into the third, these equations can be simplified to: Normality Normality of ml I2 of I ml Na2S2O3 Na S O 2 2 3 2 Used Used Solution Solution Moles H2S 5.626 Mole Amine ml of Wt % Amine Sample in Solvent
5.
Calculation of CO2 Loading (Molar Basis): Using the total acid gas loading determined with the procedure in Section 11.10.3, the CO2 loading of the solvent is determined by difference:
Moles CO2 Moles Acid Gas Moles H2S Mole Amine Mole Amine Mole Amine 6.
Other Common Units: The loadings calculated above can be easily converted to other units commonly used within the industry:
Grains H2S Moles H2S Wt % Amine S.G. of 166.7 Gallon Solvent Mole Amine in Sample Sample Moles H2S Wt % Amine Wt % H2S 0.2858 in Sample Mole Amine
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SULFUR BLOCK SCF CO2 Moles CO2 Wt % Amine S.G. of 0.2653 Gallon Solvent Mole Amine in Sample Sample
Moles CO2 Wt % Amine Wt % CO2 0.3693 in Sample Mole Amine Note that these conversions are specifically for MDEA. amines require different conversion factors.
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SULFUR BLOCK 11.10.5 Determination of Foaming Tendency of TGCU Solvent The procedure described in this section is an empirical method for measuring the foaming tendency of aqueous amine solvents, universally accepted within the industry. 1.
Principle: Air is bubbled through a solvent sample at a fixed rate for five minutes, at which time the foam height is measured. The air flow is stopped and the time for the foam to disappear is measured. The foam height and "break" time are indicative of how high the foaming tendency of the solvent is.
2.
Equipment:
3.
Procedure:
4.
1000 ml Graduated Cylinder Aquarium Air Pump (or laboratory air supply) with Bubble Stone Stop Watch (or regular watch with a second hand)
a.
Pour about 200 ml of the sample solution into the graduated cylinder and insert the bubble stone into the bottom of the cylinder.
b.
Record the level of sample in the cylinder (in ml).
c.
Start the air pump or air supply to agitate the sample with oil-free air at 4 liters per minute (0.2 Nm3/H).
d.
After five minutes, record the height of the foam in the cylinder (in ml). Then turn off the air supply and measure the time in seconds for the foam to "break". For consistency, foam "break" is defined as the first clear "fish eye" in the surface of the liquid in the cylinder.
Calculation: Foam Height = Height of Foam - Initial Height of Sample (in ml)
5.
Interpretation: Considerable experience with this test has shown that if the foam height exceeds 200 ml or the "break" time exceeds 5 seconds, the plant may be experiencing a foaming problem. The higher the foam
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SULFUR BLOCK height and/or the longer it takes to "break", the more severe the problem. 6.
Issued 30 August 2011
Other Considerations: a.
A nitrogen cylinder with the pressure regulated to about 0.35 kg/cm2(g), equipped with a flow rotameter, may be used instead of air. Be sure to keep the tubing and fittings oil-free.
b.
This procedure can be used to evaluate the effects of anti-foam agents on the solvent. However, care must be exercised in cleaning the equipment between tests since a very small quantity of residual anti-foam agent will affect the test.
c.
Foaming is sometimes caused by contaminants in the solvent that can be removed by activated carbon treatment. The effect of activated carbon filtration can be evaluated by running foam tests on treated and untreated samples. The sample is treated by mixing it with a quantity of carbon (12-20 mesh) to remove the contaminant, then filtering the mixture through Whatman No. 41 filter paper.
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SULFUR BLOCK 11.10.6 H2S Conc. in TGCU Contactor Ovhd by the Tutweiler Method The overhead gas from the TGCU Contactor can be sampled from the sample connection near the sample line for the H2/H2S analyzer. 1.
Using a 500 ml Tutweiler apparatus, sample and titrate the treated gas leaving the TGCU Contactor as outlined in Section 7.10.1 of these guidelines.
2.
Chemical reaction involved: H2S + I2
2 HI + S
The hydrogen sulfide (H2S) is converted to small particles of elemental sulfur by the iodine during the shaking. Good shaking is required to get good contact between the hydrogen sulfide in the gas and the iodine in the liquid. When all of the hydrogen sulfide is converted, the excess iodine causes the characteristic blue color in the presence of starch. This is a universal test for starch. (Iodine causes a blue color when it contacts starchy foods, such as potato for example.) 3.
Calculation of Mole (or Volume) percent H2S (dry basis): ml Iodine Normality of 273 T 760 Mole % H2S Iodine Solution (11.85) Solution Used 289 P - V.P.
Where
T P
= =
sample temperature, °C atmospheric pressure at particular location, mm Hg
V.P
=
vapor pressure of water at sample temperature, mm Hg
The Normality of the standard iodine solution will be 0.1 N. The last three factors (which correct the actual H2S content to compensate for expansion due to temperature, pressure, and water content) can be combined and calculated as a function of temperature only. This has been done for the 500-ml gas sample and is included as the Tutweiler Factor Chart in Section 9.10 of these guidelines (Chart 2). Therefore, the equation above can be simplified to:
ml Iodine Normality Factor from PPM H2S 10,000 Solution of Iodine Tutweiler Used Solution Factor Chart
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SULFUR BLOCK 11.10.7 H2S Conc. in TGCU Contactor Ovhd Using Gas Detector Tubes As an alternative to the traditional wet-chemistry method described in the preceding Section 11.10.6 for determining the concentration of H2S in the TGCU Contactor overhead gas, gas detector tubes can be used to quickly and easily make this determination. Although the discussion that follows specifically addresses using gas detector tubes manufactured by Drägerwerk AG of West Germany, there may be suitable detector tubes available from other manufacturers. Dräger tubes can be purchased from most safety equipment supply companies. The following Dräger tubes can be used with this procedure:
11.10.7.1
H2S 5/b
Dräger Cat. No. CH 298 01
H2S 100/a
Dräger Cat. No. CH 291 01
Operating Principles
Dräger tubes and other gas detector tubes measure gas concentrations by using a sample pump to draw a specific volume of the gas to be sampled into a glass tube containing a suitable reagent. The gaseous compound of interest chemically reacts with the reagent to produce a color change. The length of the "stain" line is a direct function of the concentration of the compound in the sample gas. Some detector tubes are calibrated with measured lines to allow reading the concentration directly on the tube. Others, such as the two listed above, have reference marks on the tube that can be multiplied by a factor to compute the concentration. Dräger tubes are designed to be used with a Dräger Model 31 gas detector pump. This is a hand-operated bellows pump that will draw a 100 cc sample volume for each pump stroke. Some tubes are designed for a single sample stroke, while others may use 5, 10, or even 20 strokes. In some cases, a tube may be used for measuring different concentration ranges by using a different number of strokes. a.
Dräger Cat. No. CH 298 01, H2S 5/b This tube will measure H2S concentrations in the range of 50 PPM to 600 PPM when one sample stroke is used. If desired, the range can be reduced to 5 PPM to 60 PPM by using 10 sample strokes. Each tube contains a substrate of a white lead compound. When exposed to H2S, the lead
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SULFUR BLOCK compound is converted to brown lead sulfide. The H2S concentration in PPM can be read directly from the marks on the tube according to the length of the brown stain when using 10 sample strokes. If only one sample stroke is used, the tube reading is multiplied by 10 to give the PPM of H2S. This lead sulfide reaction is not affected by any of the other compounds normally found in the overhead gas from the TGCU Contactor. b.
Dräger Cat. No. CH 291 01, H2S 100/a This tube will measure H2S concentrations in the range of 100 PPM to 2,000 PPM when one sample stroke is used. Each tube contains a substrate of a white lead compound. When exposed to H2S, the lead compound is converted to brown lead sulfide. The H2S concentration in PPM can be read directly from the marks on the tube according to the length of the brown stain. This lead sulfide reaction is not affected by any of the other compounds normally found in the overhead gas from the TGCU Contactor.
11.10.7.2
Sampling the TGCU Contactor Overhead Gas
The overhead gas from the TGCU Contactor can be sampled from the sample connection near the sample line for the H2/H2S analyzer.
Issued 30 August 2011
1.
Before beginning, check the Dräger pump for leaks by inserting an unopened tube into the pump and stroking the pump. Confirm that the bellows does not re-expand. If it does, either the pump or its seal around the tube is leaking, and the test results will not be accurate.
2.
Attach a short piece of rubber tubing to the process sample valve.
3.
Break off the tips at each end of a Dräger tube and insert it into the sample pump (with the arrow on the side of the tube pointing toward the pump).
4.
Purge the rubber tubing by venting gas to the atmosphere for a few seconds. Pinch the rubber tubing closed at the end, close the gas sample valve, slip the end of the rubber tubing onto the end of the Dräger tube, and reopen the sample valve.
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SULFUR BLOCK
11.10.7.3
5.
Stroke the sample pump one time (be sure to compress the bellows until reaching the stops) and allow the pump to draw the gas sample into the detector tube. The sample stroke is complete when the metal chain on the bellows is taut.
6.
Close the sample valve and remove the rubber tubing from the end of the Dräger tube and from the sample valve.
7.
Read the length of the brown stain using the marks on the tube and record the reading.
Calculations
Mole (or Volume) PPM H2S (wet basis):
1013 Stain Tube PPM H2S Factor Length Baro. Pres., mbar The last factor corrects the measurement for pressure effects when samples are taken at elevations above sea level. Note that the average barometric pressure at the complex is 14.7 PSIA = 1013 mbar. The "Tube Factor" depends on the type of Dräger tube used and the number of sample strokes:
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Dräger Tube
Catalog No.
Sample Strokes
Tube Factor
H2S 5/b H2S 5/b H2S 100/a
CH 298 01 CH 298 01 CH 291 01
1 10 1
10 1 1
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SULFUR BLOCK 11.10.8 Monitoring the Performance Level of TGCU Catalyst The activity of the cobalt-molybdenum catalyst in the TGCU Reactor should remain adequate for years. For trouble-shooting purposes, however, its activity should be monitored at regular intervals, beginning at the initial startup, to establish its baseline performance. Two of the reactions that occur in the TGCU Reactor (refer to Section 11.6.3 of these guidelines for a complete discussion) are: CO + H2O
H2 + CO2
COS + H2O
H2S + CO2
The first reaction is the classic "water gas shift" reaction. Since this is an equilibrium reaction, an equilibrium constant for the reaction can be expressed in terms of the reactant and product concentrations: Keq
H2CO2 COH2O
This equilibrium constant is mainly a function of temperature. Since the TGCU Reactor outlet temperature for a given plant is fairly constant, as are the concentrations of CO2 and H2O in the process gas, then the ratio of CO to H2 in the TGCU Reactor effluent should remain fairly constant as long as the catalyst activity does not change. Similarly, the hydrolysis of COS to convert it to H2S is an equilibrium reaction. Its equilibrium constant can be expressed as: Keq
H2SCO2 COSH2O
Since the temperature, H2S concentration, H2O concentration, and CO2 concentration of the TGCU Reactor outlet should all be fairly constant, then the COS concentration of the gas leaving the TGCU Reactor should be fairly constant. It is for these reasons that Shell recommends using a gas chromatograph to analyze the TGCU Reactor effluent gas for H2, CO, and COS on a regular basis (once per month, for instance). Using the results of the chromatograph analyses, the CO/H2 ratio and the COS concentration can be plotted over time and allow trends to be detected in the catalyst activity.
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SULFUR BLOCK The CO/H2 ratio is usually plotted as PPM CO divided by % H2, and the COS is usually plotted as PPM. From the discussions above, it is clear that a trend upward in either value, CO/H2 ratio or COS concentration, indicates lower catalyst activity. Shell suggests planning to replace the catalyst within a few months once either value begins to rise rapidly. Note that the sample for the chromatograph can be taken from the gas leaving the TGCU Quench Column, since the H2, CO, and COS concentrations (on a dry basis) will be the same there as those leaving the TGCU Reactor. Because this gas stream is cooler and contains less water, it is often easier to sample and analyze than the TGCU Reactor effluent. As discussed in Section 11.6.3, it is also typical to find methane and/or methyl mercaptan in the TGCU Reactor effluent gas resulting from side reactions between hydrogen and the COS and CS2 produced in the Reactor Furnace in the sulfur plant. It can be informative to record the concentrations of CH4 and/or CH3SH from the chromatographic analyses as well. An increase in either component may indicate a loss in TGCU catalyst activity. However, higher CH4 and/or CH3SH concentrations leaving the TGCU Reactor may also be due to higher COS/CS2 concentrations entering the TGCU Unit due to lower catalyst activity in the sulfur plant. In order to allow determining whether such an increase is due to loss of activity in the sulfur plant or the TGCU Unit, it is helpful to analyze the TGCU Reactor inlet gas periodically with the gas chromatograph and record the amount of COS, CS2, and CO in the TGCU Reactor feed. Collecting samples of this gas is somewhat more difficult because the gas contains sulfur vapor, but the additional information provided by analyzing this stream can be extremely helpful for monitoring plant operations.
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Table of Contents 12.
TAILGAS THERMAL OXIDIZER ............................................................................ 12-2
12.1 PURPOSE OF SYSTEM ..................................................................................... 12-2 12.2 SAFETY ............................................................................................................... 12-2 12.3 PROCESS DESCRIPTION.................................................................................. 12-3 12.4 EQUIPMENT DESCRIPTION .............................................................................. 12-4 12.4.1 Thermal Oxidizer, A2-BA1570 ...................................................................... 12-4 12.4.2 Thermal Oxidizer Burner, A2-BA1571 .......................................................... 12-4 12.4.3 Steam Knock-out Drum, A2-FA1570 ............................................................ 12-4 12.4.4 Thermal Oxidizer Air Blower, A2-GB1570A/B .............................................. 12-4 12.4.5 Thermal Oxidizer Vent Stack, A2-ME1570 ................................................... 12-5 12.4.6 Refractory for Thermal Oxidizer, A2-MR1570 .............................................. 12-5 12.4.7 Thermal Oxidizer Waste Heat Boiler, A2-BF1570 ........................................ 12-5 12.5 INSTRUMENTATION AND CONTROL SYSTEMS ............................................. 12-7 12.5.1 Thermal Oxidizer Burner Management System ........................................... 12-7 12.5.2 Thermal Oxidizer Temperature Control ...................................................... 12-10 12.5.3 Thermal Oxidizer Excess Oxygen Control.................................................. 12-10 12.5.4 Boiler Low-Low Level S/D Transmitter Testing .......................................... 12-11 12.5.5 Thermal Oxidizer Shutdown System .......................................................... 12-13 12.6 PROCESS PRINCIPLES AND OPERATING TECHNIQUES ........................... 12-18 12.6.1 Equipment Damage .................................................................................... 12-18 12.6.2 Effect of Upstream Operations on the Thermal Oxidizer ............................ 12-21 12.6.3 "Swapping" Air Blowers During Operation .................................................. 12-23 12.6.4 Boiler Water Treatment .............................................................................. 12-24 12.7 PRECOMMISSIONING PROCEDURES ........................................................... 12-26 12.7.1 Preliminary Check-out ................................................................................ 12-26 12.7.2 Shutdown System Check-out ..................................................................... 12-27 12.7.3 Commissioning Fuel Gas, Pilot Gas, and I/A to the Process ..................... 12-28 12.8 STARTUP PROCEDURES................................................................................ 12-33 12.8.1 Initial Firing / Refractory Cure-out............................................................... 12-33 12.8.2 Normal Startup ........................................................................................... 12-48 12.9 SHUTDOWN PROCEDURES ........................................................................... 12-58 12.9.1 Planned Shutdown - No Entry .................................................................... 12-59 12.9.2 Planned Shutdown for Entry ....................................................................... 12-61 12.9.3 Shutting Down When Boiler Tubes Are Leaking ........................................ 12-65 12.9.4 Emergency Shutdown ................................................................................ 12-66 12.9.5 Effects of Shutdowns and Outages in Other Systems................................ 12-69
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12. TAILGAS THERMAL OXIDIZER 12.1 Purpose of System The purpose of the Tailgas Thermal Oxidation (TTO) system is to receive the tailgas from Sulfur Recovery Units (SRUs) or the Tailgas Cleanup Unit (TGCU), the vapors from the Sulfur Surge Tanks, and the spent degassing air from the Sulfur Degassing Unit (SDU), thermally incinerate all the sulfur compounds to sulfur dioxide (SO2), and disperse the effluent safely to the atmosphere. The effluent will normally contain less than 200 PPMV of SO2 on a dry, 0% oxygen basis. High-pressure superheated steam is produced by waste heat recovery from the thermal oxidation process.
12.2 Safety
WARNING ALL PIPING AND VESSELS INCLUDED IN THIS UNIT EITHER CONTAIN OR HAVE THE POTENTIAL FOR CONTAINING HAZARDOUS GASES THAT MAY CAUSE SERIOUS INJURY OR DEATH. THE TWO GASES THAT ARE MOST COMMON AND HAZARDOUS IN A TOXIC WAY ARE HYDROGEN SULFIDE AND SULFUR DIOXIDE. CLOSE ATTENTION SHOULD BE PAID TO THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES AS TO THE NATURE AND ABILITY OF THESE GASES TO CONTAMINATE OTHER ELEMENTS IN THIS UNIT. AN EMPLOYEE'S KNOWLEDGE OF THE HAZARDOUS CHEMICALS AND COMPOUNDS WITH WHICH HE WILL BE WORKING IS ONE OF THE MOST BASIC PREREQUISITES FOR HIS OWN SAFETY, THE SAFETY OF OTHERS, AND THE PROTECTION OF EQUIPMENT. ALL EMPLOYEES SHOULD REVIEW THE "GENERAL SAFETY" SECTION OCCASIONALLY TO REFRESH THEIR MEMORIES. NEW EMPLOYEES SHOULD STUDY IT UNTIL THE INFORMATION IS THOROUGHLY UNDERSTOOD. PEOPLE WHO HAVE NOT BEEN PROPERLY TRAINED SHOULD NOT BE ALLOWED TO OPERATE OR WORK IN AND AROUND THIS PLANT.
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12.3 Process Description The Systems Diagram, Material Balance and Process Flow Diagram, Dwg. Nos. 507000-7000-01, and 507000-7000-10 through -11, are contained in the "Process Flow Diagrams" Section of the Basic Engineering Package. Please refer to these drawings to follow this description of the process. When the TGCU is operating, the TGCU effluent containing H2S and COS flows to the Thermal Oxidizer, A2-BA1570, at about 39°C [102°F]. When the TGCU Unit is not in service, tailgas from each SRU containing H2S, SO2, COS, CS2, and elemental sulfur flows directly to the Thermal Oxidizer at about 156°C [313°F]. The spent degassing air from the Sulfur Degassing Unit and the sweep air streams from each Sulfur Surge Tank (both containing traces of H2S and sulfur vapor) are also routed to the Thermal Oxidizer. In the Thermal Oxidizer, essentially all of the sulfur compounds are incinerated to SO2 by the high-temperature oxidizing atmosphere created inside the Thermal Oxidizer. In addition, most of the carbon monoxide (CO) in the feed stream is oxidized to carbon dioxide, resulting in very low CO emissions from the Tailgas Thermal Oxidation system. Heat is provided to the Thermal Oxidizer by combustion of fuel gas in the Thermal Oxidizer Burner, A2-BA1571. Combustion air for the burner is supplied by the Thermal Oxidizer Air Blower, A2-GB1570A/B. The fuel gas flow rate is adjusted to maintain the furnace temperature at 816°C [1500°F] to ensure complete incineration of the sulfur compounds and carbon monoxide in the feed to the Thermal Oxidizer. The effluent from the Thermal Oxidizer flows to the Thermal Oxidizer Waste Heat Boiler, A2-BF1570. The gas is cooled to about 288°C [550°F] as it generates and superheats steam at 45.0 kg/cm2(g) [640 PSIG], which is exported to the HP steam header at about 400°C [752°F] for use as motive steam to the Sulfur Pit Ejector and for use elsewhere in the refinery. (Note that the HP steam produced in each SRU is also superheated in this boiler by combining it with the steam this boiler generates.) The cooled effluent is then dispersed to the atmosphere from the top of the Thermal Oxidizer Vent Stack, A2-ME1570.
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12.4 Equipment Description 12.4.1
Thermal Oxidizer, A2-BA1570 The Thermal Oxidizer is a non-catalytic thermal incineration chamber. The furnace shell is internally lined with refractory insulation to protect it against the extreme process temperatures inside. The maximum operating temperature is about 1000°C. Although the furnace can withstand short excursions above this temperature, prolonged operation above this temperature can damage the refractory or the downstream boiler.
12.4.2
Thermal Oxidizer Burner, A2-BA1571 This burner is specifically designed to burn fuel gas to provide the heat input for the Thermal Oxidizer. The burner assembly consists of the main fuel gas burner tip, a pilot, two flame scanners, two viewports, and specially designed air distribution baffles to effect proper combustion. This complete unit is installed in the front of the Thermal Oxidizer. The StackMatch® ignitor/pilot assembly is designed to be retracted or extracted after the main burner has been lit. If it is extracted, the block valve can be closed to isolate it from the furnace atmosphere. The assembly includes filters for the incoming fuel gas and air, which should be checked (and cleaned, if necessary) after each use so that there is no chance of a plugged filter causing delays during the next startup.
12.4.3
Steam Knock-out Drum, A2-FA1570 This vertical vessel is installed in the common HP steam line from the Waste Heat Boilers in the SRUs and the steam drum on the Thermal Oxidizer Waste Heat Boiler. Its purpose is to remove any water droplets (condensed or entrained) from the steam before it is routed to the superheater pass in the Thermal Oxidizer Waste Heat Boiler, so that the superheated steam exported to the refinery does not contain excessive amounts of solids. The water collected in this vessel is routed to the high pressure condensate header via a steam trap.
12.4.4
Thermal Oxidizer Air Blower, A2-GB1570A/B These single-stage centrifugal fans provide the combustion air required to burn fuel gas in the Thermal Oxidizer Burner. The air flow rate is controlled by throttling a valve in the common blower discharge line. The
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fans are connected to the discharge piping through flexible connectors to allow the necessary freedom for the expansion and movement that occurs during normal operation. Each blower is equipped with an inlet filter and silencer.
12.4.5
Thermal Oxidizer Vent Stack, A2-ME1570 The Thermal Oxidizer Vent Stack disperses the effluent from the Thermal Oxidizer Waste Heat Boiler safely to the atmosphere. It is a free-standing stack typically constructed of carbon steel and externally insulated to keep its metal shell safely above the acid dewpoint of the process gas flowing inside the stack.
12.4.6
Refractory for Thermal Oxidizer, A2-MR1570 The refractory lining in the firing chamber of the Thermal Oxidizer consists of a layer of fireclay firebrick, installed with high temperature air-setting mortar. The inlet plenum of the Thermal Oxidizer, exposed to the high temperatures produced by the Thermal Oxidizer Burner, is covered with a layer of castable refractory. The refractory lining inside the furnace includes a "choke ring" located about two-thirds of the way down the length of the furnace. The purpose of the choke ring is to promote mixing between the TGCU effluent gas (or SRU tailgas) and the hot combustion products from the Thermal Oxidizer Burner, ensuring efficient oxidation of the sulfur compounds and carbon monoxide that are present in the tailgas.
12.4.7
Thermal Oxidizer Waste Heat Boiler, A2-BF1570 The Thermal Oxidizer Waste Heat Boiler is a water-tube style boiler. It includes a superheater pass for the steam produced in this boiler, plus steam produced in the SRUs. The superheater consists of two sections with a desuperheater between the two sections and a desuperheater on the steam outlet. There are also two sections of boiler tubes, the screen section and the main section. Hot gas entering the boiler flows first across the screen section tubes, then across the two superheater sections, then lastly across the main section of boiler tubes. The main boiler tube section contains tubes connecting the steam drum on top of the boiler to the mud drum on the bottom of the boiler, as well as side wall tubes. The screen section contains rows of tubes also connected to the mud and steam drums. The hot gas entering the boiler
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casing boils water as it circulates in the screen and main boiler tubes, generating 48.5 kg/cm2(g) saturated steam. The saturated steam generated in the boiler tubes exits the steam drum at and is combined with saturated HP steam generated by the Waste Heat Boilers in the SRUs. The combined steam is routed to the first superheater section, then to the first desuperheater, and then to the second superheater section. The resulting superheated steam is routed to the second desuperheater and then to the HP steam header at about 45 kg/cm2(g) and 400°C.
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12.5 Instrumentation and Control Systems 12.5.1
Thermal Oxidizer Burner Management System The Thermal Oxidizer Burner Management System (BMS), controlled by a programmable logic controller (PLC), has been designed to ensure a safe firing order. It requires a certain sequence of steps before permitting ignition. The function of the various system components is described below.
12.5.1.1
Startup/Run Interlocks The "startup" and "run" interlock logic is shown on the Logic Flow Diagrams contained in the Instrumentation and Controls Diagrams section of the Basic Engineering Package. The purpose of this logic is to simplify lighting the Thermal Oxidizer Burner by automatically positioning the process gas switching valves in the proper sequence for safe operation: (1)
Before attempting ignition of the burner, any process gas from the SRUs and/or TGCU Unit should be blocked from flowing into the Thermal Oxidizer in case the process gas is combustible. Setting selector switch A2-HS15785 on the local TTO control panel to "STARTUP" will open the bypass valve, A2-HV15741, prove the valve open, then close the inlet valve, A2-HV15740, so that the process gas is diverted directly to the Thermal Oxidizer Vent Stack.
(2)
Once the pilot burner in the Thermal Oxidizer Burner has been lit, process gas can then be directed into the Thermal Oxidizer. Setting selector switch A2-HS15785 to "RUN" will automatically open the inlet valve, prove the valve open, then close the bypass valve.
These two process gas valves constitute the Complete Flowpath Interlock for the TTO. Although this interlock is not part of the TTO ESD system (since the TTO always has a direct path to its vent stack), it is a part of the Complete Flowpath Interlocks that are included in the SRU Complete Flowpath alarms and TGCU ESD system. By automating the valve switching steps and including checks of the limit switches in the logic, the chance of accidentally causing an SRU or a TGCU shutdown due to an incomplete flowpath
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK (or over-pressure resulting from an incomplete flowpath) while starting up the Thermal Oxidizer is greatly reduced. If either of the switching valves does not move to the proper position, the corresponding status light on the local TTO control panel should continue to blink. This will alert the operators to investigate the problem and take any required corrective action so that the BMS allows proceeding.
12.5.1.2
Flame Scanners The flame scanners, A2-BE15763A and A2-BE15763B, monitor the pilot and main fuel gas burners. If a scanner detects a flame, the associated flame proven signal will indicate. If neither scanner detects a flame, the TTO ESD system is activated. Since a "flame proven" signal from either scanner satisfies the system, maintenance may be performed on one flame scanner while the other remains in service. Note that a third flame scanner, A2-BE15758, is furnished with the pilot to detect its flame, but it is used only to activate its status light (A2-GL15758) on the local TTO control panel and a status indicator (A2-BL15758) in the DCS.
12.5.1.3
Purge Cycle To ensure the unit is safe for firing, a purge cycle must be completed before the pilot can be ignited. To purge the Thermal Oxidizer, a Thermal Oxidizer Air Blower is used to send a high rate of air through the Thermal Oxidizer for 45 seconds. The air flow must then be reduced to a low rate to allow ignition of the pilot.
12.5.1.4
Ignition Cycle After the purge cycle is complete, pressing the "IGNITION" push-button (A2-HPB15765) causes the BMS to initiate an attempt to ignite the pilot. The BMS closes the pilot burner purge air valve (A2-HV15782), opens the pilot air block valve (A2-NV15753), closes the vent valve in the fuel gas to the pilot (A2-NV15756), opens the pilot fuel gas block valves (A2-NV15755 and A2-NV15757), and energizes the ignition system (A2-BX15758). After a 15 second ignition trial, the ignition system is de-energized. If a pilot flame is established, one or both flame scanners will indicate "flame proven" and the block valves in the air and fuel gas supplies
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12.5.1.5
Main Fuel Gas Firing After the pilot burner is lit, the main fuel gas supply is enabled. Pressing the "MAIN FUEL ON" push-button (A2-HPB15767) on the local TTO control panel will close the vent valve in the fuel gas to the main burner (A2-NV15747) and open the main fuel gas block valves (A2-NV15746 and A2-NV15748). The main fuel gas control valve (A2-TV15749) can then be adjusted using either A2-HIC15745 on the local TTO control panel or A2-TIC15749 in the DCS to control the firing rate of the main burner. DCS control of the firing rate of the Thermal Oxidizer is accomplished by switching A2-HS15749 from "local" to "remote" so that A2-TIC15749 in the DCS can then control the temperature in the Thermal Oxidizer. The fuel gas flow rate can be increased as necessary to heat the refractory in the Thermal Oxidizer according to the refractory warmup schedule, and to heat the water in the Thermal Oxidizer Waste Heat Boiler. Note that the main fuel gas control valve has a minimum firing rate, as set by the "minimum fire" relay in the DCS, A2-TY15749. The proper setting for A2-TY15749 will be determined during startup by finding the minimum firing rate to maintain a stable flame on the main fuel gas burner.
12.5.1.6
Pilot On/Off Switch Push-button A2-HPB15774 on the local TTO control panel is used to turn the pilot burner on and off. If the pilot burner is "on", pressing this push-button will extinguish the burner by closing the two block valves and opening the vent valve in its fuel gas supply, closing the block valve in its air supply, de-energizing its ignition system, and opening the valve to begin purging the burner with air. If the burner is "off " (and the "flame proven" is already satisfied by the main burner tip), pressing this push-button will ignite the burner by closing the valve to cease purging the burner with air, closing the vent valve and opening the two block valves in its fuel gas supply, opening the block valve in its air supply, and energizing A2-BX15758 for 15 seconds.
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12.5.2
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
Thermal Oxidizer Temperature Control The Thermal Oxidizer is designed to cause thermal incineration of all the sulfur compounds that enter with the sulfur plant tailgas stream, converting them into sulfur dioxide, SO2. This is accomplished by providing a high-temperature oxidizing atmosphere inside the Thermal Oxidizer, so that free oxygen can react with the sulfur compounds to form SO2. The Thermal Oxidizer has also been designed to provide near complete oxidation of the carbon monoxide (CO) normally found in TGCU effluent gas and sulfur plant tailgas, converting the carbon monoxide into carbon dioxide, CO2. Although a temperature of 550°C is usually adequate to ensure complete oxidation of the sulfur compounds, a temperature in excess of 760°C is normally required to achieve significant oxidation of CO. This temperature is achieved in the Thermal Oxidizer by combusting fuel gas in the Thermal Oxidizer Burner. The amount of fuel gas fed to the burner is controlled by A2-TIC15749 in the DCS, which senses the Thermal Oxidizer outlet temperature and adjusts the fuel gas flow accordingly. Since the TGCU effluent gas and/or the SRU tailgas streams contains variable amounts of combustible gases (H2S, H2, CO, etc.), the controller must respond quickly to accommodate fluctuations caused by SRU and/or TGCU operations. The design setpoint for this controller is 816°C. Actual operations may determine that a lower temperature gives satisfactory CO destruction, which would reduce the amount of fuel gas consumed by the Thermal Oxidizer Burner (but would also reduce the steam production from the Thermal Oxidizer Waste Heat Boiler).
12.5.3
Thermal Oxidizer Excess Oxygen Control As discussed earlier, the Thermal Oxidizer must maintain an oxidizing atmosphere so that there is free oxygen in the furnace to react with the sulfur compounds and the carbon monoxide. Operating the Thermal Oxidizer Burner with excess air provides this free oxygen, so that after combusting the fuel gas supplied to the burner sufficient oxygen remains to oxidize the sulfur compounds entering the Thermal Oxidizer. Sulfur plant Thermal Oxidizers are normally designed to supply at least 25% more air than stoichiometric requirements to ensure complete conversion of the sulfur compounds. There are no provisions in this plant at present for automatically controlling the amount of excess air in the Thermal Oxidizer. If optimum
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operation is desired, the oxygen analyzer that is part of the CEMS, A2-AE15153, on the Thermal Oxidizer Vent Stack can be used to measure the amount of oxygen in the stack gas, and the setpoint of the air flow controller, A2-FIC15760, can be adjusted as necessary to give the desired oxygen concentration in the Thermal Oxidizer effluent.
12.5.4
Boiler Low-Low Level S/D Transmitter Testing The Thermal Oxidizer Waste Heat Boiler has independent level transmitters, A2-LT15150A/B/C, connected to the PLC that activate the TTO ESD system before the water level can get low enough to cause boiler damage. The shutdown is activated when two out of three transmitters show a low-low level. These transmitters should be tested periodically to determine that they are functioning properly. Consider A2-LT15150A on the Thermal Oxidizer Waste Heat Boiler, for example. The procedure for testing A2-LT15150B and A2-LT15150C will be similar. The procedure for testing A2-LT15150A is as follows: (1)
The outside operator notifies the DCS operator that he is preparing to test shutdown level transmitter A2-LT15150A on the Thermal Oxidizer Waste Heat Boiler.
(2)
The DCS operator confirms that A2-LI15150B and A2-LI15150C are both indicating adequate level in the boiler, then notifies the outside operator to proceed.
CAUTION
DO NOT PROCEED UNLESS THE OTHER TWO LEVEL INDICATORS SHOW ADEQUATE LEVEL IN THE BOILER. OTHERWISE THE LOW-LOW LEVEL SHUTDOWN IN THE TTO ESD WILL BE ACTIVATED AS SOON AS THE OUTSIDE OPERATOR BEGINS DRAINING THE LEVEL TRANSMITTER IN THE NEXT STEP. (3)
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After being notified to proceed by the DCS operator, the outside operator blocks-in A2-LT15150A by closing its block valves, then
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(4)
If the transmitter is operating properly, the DCS will alarm that there is a low level in the Thermal Oxidizer Waste Heat Boiler on A2-LI15150A. The DCS operator acknowledges the alarm on the DCS and reports it to the outside operator.
(5)
After being notified of the alarm, the outside operator closes the drain valve on A2-LT15150A, slowly opens its bottom block valve to allow the transmitter to fill with water then opens its top block valve. This should clear the low level alarm on A2-LI15150A in the DCS.
(6)
After confirming that the low level alarm has cleared, the other level transmitters can be tested in a similar fashion.
NOTE:
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The DCS operator must not begin another task until confirming that the low level alarm has cleared. This is to guard against having a level transmitter malfunction that causes a TTO ESD when the other transmitters are tested.
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12.5.5
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
Thermal Oxidizer Shutdown System The purpose of the Tailgas Thermal Oxidation Emergency Shutdown system (TTO ESD) is to shut off the flow of fuel gas, fuel gas, and combustion air to the Thermal Oxidizer when serious problems occur. The Cause and Effect Diagram, contained in the Instrumentation and Controls Diagrams section of the Basic Engineering Package, describes the TTO ESD system in block format. For reference, the causes and effects of the ESD system shown on this diagram are explained below. As noted on the Cause and Effect Diagram, it is recommended that a 5 second delay be used for most of the process parameters included in the causes of the ESD system. This is to prevent the "nuisance" shutdowns that are sometimes caused by momentary fluctuations in the process or the sensing elements.
12.5.5.1
Causes Any one of the causes listed below will activate the TTO ESD system: a.
Manual Shutdown Switches, A2-HS15783 and A2-HS15784 An operator can activate the TTO ESD system using either of two manual shutdown switches:
b.
(1)
A2-HS15783 is a NORMAL / ESD selector switch in the DCS.
(2)
A2-HS15784 is a NORMAL / ESD selector switch mounted on the local TTO control panel.
No Thermal Oxidizer Air Blower Running, A2-GB1570A/B starter contacts If neither Thermal Oxidizer Air Blower is running, TGCU effluent and/or SRU tailgas could flow backwards down the combustion air line and escape from the blowers. The motor starter contacts are used to determine whether a blower is running, and will activate the TTO ESD system if neither is running.
c.
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Thermal Oxidizer A2-FT15760A/B/C
Combustion
Tailgas Thermal Oxidation
Air
Low-Low
Flow,
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK Loss of air flow from the Thermal Oxidizer Air Blower could cause the Thermal Oxidizer Burner flame to become unstable, or allow TGCU effluent and/or SRU tailgas to flow backwards down the combustion air line and escape from the blowers. These devices will activate the TTO ESD to block the air line before this can occur. The shutdown setpoint is 20% of normal flow. Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD (i.e., at least two transmitters must show low-low flow) to avoid spurious "trips" due to the malfunction of a single transmitter. d.
Burner Fuel Gas Supply Low-Low Pressure, A2-PT15744A/B/C Loss of the fuel gas supply would cause the fuel gas pressure to drop at the burner. This device will shut down the TTO before flame instability creates the potential for an explosion. The setpoint for these transmitters is 0.35 kg/cm2(g). Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD.
e.
Burner Fuel Gas A2-PT15751A/B/C
High-High
Burner
Pressure,
A malfunction of the fuel gas pressure control could cause excessive firing of the main burner in the Thermal Oxidizer Burner. These devices will prevent this unsafe condition by shutting down the Thermal Oxidizer. The setpoint for the Note that there are three transmitters is 3.5 kg/cm2(g). independent transmitters and 2oo3 voting logic is used for the ESD. f.
Thermal Oxidizer Burner Flame Failure, A2-BY15763A and A2-BY15763B Dual flame scanners are aimed to observe the flames from both the pilot burner and the main gas burner. If the neither scanner detects a flame (2oo2), a "flame failure" occurs and activates the TTO ESD system. If only one scanner detects a flame (1oo2), a malfunction alarm is activated in the DCS, but the TTO ESD system is not activated. A third flame scanner, A2-BY15758, is furnished with the pilot to detect its flame, but it is used only to activate its status light (A2-GL15758) on the
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Thermal Oxidizer High-High Temperature, A2-TT15749A/B/C These devices activate the TTO ESD system and shut down the Thermal Oxidizer Burner if a temperature of 1000°C or higher is measured in the Thermal Oxidizer. Temperatures higher than this can overheat the refractory inside the Thermal Oxidizer to the point that it weakens and fails, causing heat damage to the Thermal Oxidizer shell. Excessive temperatures in this furnace can also lead to damage of the tubes or casing of the Thermal Oxidizer Waste Heat Boiler installed downstream. Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD.
h.
Superheated Steam High-High Temperature, A2-TT15142AB/C These devices activate the TTO ESD system and shut down the Thermal Oxidizer Burner if the temperature of the superheated steam leaving the second superheater pass of the Thermal Oxidizer Waste Heat Boiler reaches 420°C. Steam temperatures higher than this can lead to damage of the superheater tubes, or damage the piping and equipment downstream in the steam header and its users.
i.
Steam Separator High-High Liquid Level, A2-LT15148A/B/C If the steam trap that drains the Steam Scrubber, A2-FA1570, should fail, a level of condensate could begin to build inside the vessel. These devices activate the TTO ESD system to shut down the Thermal Oxidizer Burner before this condensate can carry-over into the hot tubes in the superheater passes of the Thermal Oxidizer Waste Heat Boiler and cause damage to the tubes. They are set to actuate if the liquid level reaches 1280 mm above the bottom seam of the vessel. Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD.
j.
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Thermal Oxidizer Waste Heat Boiler Low-Low Water Level, A2-LT15150A/B/C
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK These devices prevent the water level from dropping too low in the steam drum of the boiler. Hot combustion gas flows outside the boiler tubes and will destroy these tubes if they are not cooled by water boiling inside the tubes. The setpoint for these devices will be specified by the boiler vendor. Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD. k.
Thermal Oxidizer A2-TT15155A/B/C
Vent
Stack
High-High
Temperature,
During periods when the Thermal Oxidizer is shut down, if the sulfur plants continue to run but the TGCU is not on-line, elemental sulfur in the SRU tailgas may condense inside the Thermal Oxidizer, the Thermal Oxidizer Waste Heat Boiler, and/or the Thermal Oxidizer Vent Stack. If the plant is operated in this manner for extended periods, a considerable amount of liquid sulfur may accumulate. This liquid sulfur may ignite once the Thermal Oxidizer is restarted and air is flowing through the system. The heat from the sulfur fire could damage the non-refractory lined surfaces of the boiler casing and stack if allowed to continue burning. These devices detect the high temperature from the fire and shut the Thermal Oxidizer back down before equipment damage occurs. The setpoint for the transmitters is 400°C. Note that there are three independent transmitters and 2oo3 voting logic is used for the ESD. l.
Pilot Ignition Safety Interlock Timer Expired, BMS logic Once the pre-ignition steps have been completed and the BMS gives a "PERMIT TO IGNITE" for the pilot burner in the Thermal Oxidizer Burner (signaled by illuminating status indicator light A2-AL15773 on the local TTO control panel), an ignition safety interlock timer is started in the BMS. If an ignition attempt is not made within 5 minutes, the TTO ESD system will be activated to shut down the Thermal Oxidizer. This prevents a potentially unsafe condition from persisting, where a leaking fuel gas valve could cause an explosive mixture to form in the Thermal Oxidizer, since the air flow is low at this point in the startup procedure.
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12.5.5.2
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK Effects A Thermal Oxidizer shutdown, activated either manually or automatically, has the following effects on the Tailgas Thermal Oxidation system: a.
Shuts down the Thermal Oxidizer Air Blower, A2-GB1570A/B.
b.
Closes the air flow control valve, A2-FV15760, to prevent back-flow and venting of any hazardous gases to the atmosphere.
c.
Initiates the Thermal Oxidizer Burner Shutdown system, which performs the following actions:
d.
Issued 30 August 2011
(1)
Shuts off and depressurizes the main fuel gas supply by closing block valves A2-NV15746 and A2-NV15748 and opening vent valve A2-NV15747.
(2)
Shuts off the pilot air supply by closing block valve A2-NV15753.
(3)
Shuts off and depressurizes the pilot gas supply by closing block valves A2-NV15755 and A2-NV15757 and opening vent valve A2-NV15756.
(4)
De-energizes the ignition system, A2-BX15758.
(5)
Begins purging the pilot burner with air by opening block valve A2-HV15782.
Initiates back-purging of the stack gas analyzer, A2-AE15152, to prevent any un-oxidized sulfur leaving the TTO from fouling the analyzer.
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12.6 Process Principles and Operating Techniques The more important considerations involved in startup, operation, shutdown, maintenance, and emergency procedures of the Tailgas Thermal Oxidation system are discussed in the remaining sections of this portion of the operating guidelines. The operator should also be thoroughly acquainted with the equipment and the "Process Description" section in these guidelines before attempting to operate the plant in accordance with the operating techniques that follow. If the function of each portion of the plant equipment is understood, the sequence of steps outlined in the "procedures" sections will be more easily understood. In addition, the following general discussion of principles and techniques will clarify the reasons for some of the procedures.
12.6.1
Equipment Damage During periods when the TTO is shut down, if either SRU continues to run and the TGCU Unit is not on-line, elemental sulfur in the SRU tailgas may condense inside the Thermal Oxidizer, the Thermal Oxidizer Waste Heat Boiler, and/or the Thermal Oxidizer Vent Stack. If the plant is operated in this manner for extended periods, a considerable amount of liquid sulfur may accumulate. This liquid sulfur will ignite once the TTO is restarted and air is flowing through the system. The heat from the sulfur fire will damage the tubes in the boiler and/or the non-refractory lined surfaces of the boiler, outlet line, and stack if allowed to continue burning. If this situation develops, connect a steam trap to the bottom connection on the steam-jacketed nozzle in the bottom of the Thermal Oxidizer Waste Heat Boiler casing and supply LP steam to the top connection. Then remove the blind flange from the nozzle and allow the liquid sulfur to drain from the casing. Once the sulfur has been removed, a safe restart of the TTO should then be possible.
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WARNING IF EITHER SRU IS ON-LINE WHILE DRAINING SULFUR FROM THE BOILER CASING, TGCU EFFLUENT OR SRU TAILGAS MAY BE RELEASED TO THE SURROUNDINGS FROM THE DRAIN NOZZLE. THIS PROCESS GAS CONTAINS TOXIC GASES (H2S AND PERHAPS SO2). ALWAYS OBSERVE PROPER PROCEDURES AND PRECAUTIONS WHEN USING THIS DRAIN CONNECTION. THE "GENERAL SAFETY" SECTION OF THESE GUIDELINES SHOULD BE CONSULTED IF THERE IS ANY DOUBT ABOUT HOW TO WORK SAFELY WHEN H2S OR SO2 MAY BE PRESENT. Too rapid heating or cooling can damage the refractory installed in the Thermal Oxidizer. The Initial Cure and Normal Warmup schedules for the refractory are provided by the refractory vendor. These schedules should be adhered to quite closely. Explosive mixtures of air and gases in the equipment are a potential danger. During an automatic shutdown, all air, pilot gas, and fuel gas flows are shut off simultaneously. Any malfunction of these devices could leak an explosive mixture into the unit. For this reason, the PLC requires purging of the Thermal Oxidizer before attempting pilot ignition, and requires re-purging the furnace if the burner does not light but fuel gas was admitted.
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CAUTION
NEVER "HYDROBLAST" THE TUBES (OR ANY OTHER STEEL SURFACES) IN TTO EQUIPMENT. NOT ONLY DOES THIS REMOVE THE PROTECTIVE SULFIDE FILM THAT FORMS ON CARBON STEEL AND PREVENTS CORROSION, THE WATER WILL REACT WITH THE SULFUR COMPOUNDS PRESENT IN THE EQUIPMENT TO FORM A VARIETY OF ACIDS (SULFUROUS, POLYTHIONIC, ETC.) THAT RAPIDLY CORRODE THE STEEL. THERE HAVE BEEN NUMEROUS INSTANCES OF SULFUR PLANT BOILERS BEING BLASTED DURING A TURNAROUND TO CLEAN THEM UP, THEN HAVING THE TUBES BEGIN LEAKING AS SOON AS THE BOILER IS RETURNED TO SERVICE. IF THE FINNED BOILER TUBES HAVE BECOME FOULED, THE BEST WAY TO CLEAN THE TUBES IS TO BLAST THEM WITH COMPRESSED AIR. IF SULFUR OR SULFUR COMPOUNDS HAVE FOULED THE TUBES, IT MAY BE HELPFUL TO APPLY HEAT TO THE TUBES, AS THIS WILL MELT ANY SULFUR THAT MAY BE PART OF WHAT HAS FOULED THE TUBES. ONE WAY TO DO THIS IS TO DRAIN THE WATER FROM THE BOILER AND PUT STEAM IN THE STEAM DRUM. DRAIN THE CONDENSATE PERIODICALLY FROM THE MUD DRUM TO KEEP LIVE STEAM ON THE TUBES.
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12.6.2
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
Effect of Upstream Operations on the Thermal Oxidizer The process gases to be incinerated in the Thermal Oxidizer can have a widely varying content of combustible gases, such as hydrogen, carbon monoxide, hydrogen sulfide, and even hydrocarbons on occasion. As a result, the temperature control system for the Thermal Oxidizer can be subjected to sudden swings in fuel gas demand, leading to temperature excursions if the changes occur more rapidly than the control system can accommodate. Sudden drops in combustible content are most often caused by low H2S in the TTO feed gas. This will usually only occur when SRU tailgas is being routed directly to the TTO because the TGCU Unit is not in service. Under these circumstances, if too much process air is fed to either SRU, nearly all of the H2S will be consumed in the sulfur plant and the tailgas from that SRU will contain only SO2. This will be indicated by high air demand on the air demand controller in the SRU in question. However, the sudden drop in the Thermal Oxidizer temperature is usually of no consequence since the TTO feed contains very little H2S under these circumstances, meaning that the potential loss of H2S oxidation efficiency in the Thermal Oxidizer is not really of concern. The low furnace temperature alarms in the DCS will alert the operator when this condition occurs, as will the high air demand alarm on the air demand controller in the DCS. The more serious problem is when the combustible content of the TTO feed gas suddenly increases and causes high temperature in the furnace. The most common cause of this is high hydrocarbon content in the sulfur plant feed stream(s). Hydrocarbons require 3-15 times more combustion air per mole than H2S does. A sudden increase in the hydrocarbon concentration of the acid gas (due to upsets in the upstream units) will "starve" the sulfur plant(s) for air because the air demand controller(s) cannot adjust the air:acid gas ratio enough to keep the SRU(s) on-ratio. The available oxygen will burn the hydrocarbons preferentially over H2S, with the result that insufficient H2S is reacted to form SO2. The SO2 that does form will be completely consumed by the Claus reaction in the furnace(s) and the catalyst beds, allowing large quantities of unreacted H2S to leave the sulfur plant(s). Even if the TGCU is in service at the time, H2S in these quantities will overwhelm the capability of the TGCU solvent to absorb H2S. Thus,
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regardless of whether the TGCU is in service or not, these large quantities of H2S will reach the Thermal Oxidizer and cause high furnace temperature there. Even though the TTO temperature control system will begin to cut back the fuel gas to the Thermal Oxidizer Burner, it is possible that the TTO feed gas will contain so much H2S that the temperature can be excessive even with the fuel gas valve at its "minimum fire" position. If the H2S concentration is high enough, or the change is sudden enough, the high-high furnace temperature shutdownwill be tripped and the TTO ESD system will be activated to shut down the Thermal Oxidizer. However, the high-H2S gas will still be flowing into the Thermal Oxidizer, since the TTO feed gas is not interrupted by a TTO ESD. This means that large amounts of H2S may be vented un-incinerated from the Thermal Oxidizer Vent Stack.
WARNING
IF THIS SITUATION OCCURS, DIRECT YOUR ATTENTION IMMEDIATELY TO CORRECTING THE UPSET IN THE UPSTREAM UNIT THAT IS CAUSING THE PROBLEM IN THE SULFUR PLANT(S). IN EXTREME CASES, IT MAY BE NECESSARY TO SHUT DOWN THE SRUS AND THE TGCU UNIT UNTIL THE UPSTREAM PROBLEMS HAVE BEEN CORRECTED, SO THAT EXCESSIVE AMOUNTS OF H2S DO NOT CONTINUE TO BE VENTED FROM THE THERMAL OXIDIZER VENT STACK. DO NOT ATTEMPT TO RESTART THE THERMAL OXIDIZER UNTIL THE PROBLEM HAS BEEN CORRECTED AND THE H2S CONTENT OF THE TTO FEED GAS IS BACK TO ACCEPTABLE LEVELS. ATTEMPTING TO RESTART THE THERMAL OXIDIZER WHEN ITS FEED GAS CONTAINS EXCESSIVE H2S WILL SIMPLY LEAD TO THE THERMAL OXIDIZER GOING DOWN AGAIN ON HIGH-HIGH TEMPERATURE.
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12.6.3
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
"Swapping" Air Blowers During Operation While the TTO is running, it is often necessary to "swap" air blowers to bring the off-line blower on-line so that the other blower can be shut down. This can usually be accomplished with minimal impact on the process by starting and stopping the blowers in the proper sequence. The procedure given below is one technique for swapping blowers. One of the complicated aspects associated with swapping blowers is the impact that bringing the off-line blower on-line can have on the air flow. When the second blower is brought on-line, there is a potential to suddenly double the air flow to the TTO. This would not only disturb the process, it could possibly blow out the flame in the burner. For this reason, the switch from one blower to the other must be made in a controlled fashion. The procedure below describes how to switch from the "A" blower to the "B" blower, for example. That is, the "A" blower is running to the TTO and the "B" blower is not currently running. The procedure to switch from the "B" blower to the "A" blower in the TTO is similar. Make sure the SRUs, TGCU, and TTO are operating stably before proceeding.
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A.
Confirm that the manual discharge valve on the off-line blower, the "B" blower, is closed.
B.
Start the "B" blower using its local start/stop control station.
C.
Once the blower starts, slowly open its discharge valve, allowing time for the air flow controller to adjust the air flow control valve to keep the combustion air flow rate at the proper value.
D.
Once the discharge valve on the "B" blower is fully open, slowly close the discharge valve on the "A" blower, again allowing time for air flow controller to adjust the air flow control valve.
E.
Once the discharge valve on the "A" blower is fully closed, shut down the "A" blower using its local start/stop control station.
F.
The blower swap is now complete. Before leaving the area, visually confirm that: (1)
The off-line blower is stopped.
(2)
The discharge valve on the off-line blower is closed.
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12.6.4
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK (3)
The on-line blower is running smoothly.
(4)
The process has returned to steady operation.
Boiler Water Treatment SAMSUNG TOTAL PETROCHEMICALS CO., LTD. IS RESPONSIBLE FOR ESTABLISHING AND MONITORING THE BOILER AND WATER CHEMICAL TREATMENT PROGRAM. Proper boiler water chemical treatment is essential to achieving long service life for the Thermal Oxidizer Waste Heat Boiler. Without good day-to-day control of the water quality, solids buildup, corrosion, and attack by the treating chemicals themselves can occur. It is Samsung Total Petrochemicals Co., Ltd.'s responsibility to see that a proper chemical treating program is initiated prior to startup and that the program is properly monitored and refined throughout the service life of the plant. There are many qualified boiler and water treatment companies that can advise the owner/operator on chemical treatment testing and controls. It is recommended that only those companies that have local technicians with extensive experience specifically in boiler water treatment be selected to assist with Samsung Total Petrochemicals Co., Ltd.’s program. The design details incorporated in the Thermal Oxidizer Waste Heat Boiler have proven to be very reliable when combined with good operator practice regarding water treatment. However, even properly designed equipment can be severely damaged during a short period of operation if the water treatment program is inadequate or improper. The Thermal Oxidizer Waste Heat Boiler is equipped with a continuous blowdown on the steam drum to remove suspended and dissolved solids from the water inside the boiler. In addition, the boiler is equipped with an intermittent blowdown connection on the bottom of its mud drum. This intermittent blowdown valve should be used on a regular basis to give the boiler a good "blow" to prevent sludge from accumulating in the bottom of the drum. Sludge must not be allowed to coat the boiler tubes. The consequence of fouling the inside of the boiler tubes is tube failure from overheating, as the fouling will impair the heat transfer and allow the hot combustion gases to destroy the tubes.
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Prior to using the intermittent blowdown valve, use the level controller in the DCS to raise the water level in the boiler up to the high level alarm point. Then open the intermittent blowdown valve until the level drops back to the normal liquid level. Watch the boiler level in the sight glasses throughout this operation to ensure that the level is not lost (which would activate the TTO ESD and shut the Thermal Oxidizer down). Remember to reset the level controller at the conclusion of this procedure.
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12.7 Precommissioning Procedures Prior to the initial startup, there are a number of precommissioning activities that are necessary to ensure that the newly constructed plant is ready to be placed in service. The activities outlined below should serve as a guide, but there may be others required as a part of your normal plant procedures.
12.7.1
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Preliminary Check-out A.
Check all equipment to ensure that it is properly installed. This will probably require consulting Manufacturer's literature as well as construction drawings.
B.
Check and lubricate all equipment, in accordance with the Manufacturer's recommendations.
C.
Check the rotation of the Thermal Oxidizer Air Blowers by operating each blower for a short period with its discharge valve closed.
D.
Check all piping and equipment to be sure that all blinds have been removed and that no valves are vented to atmosphere.
E.
Place the Instrument Air System in service to all instruments and check the action of controllers and control valves.
F.
Place all of the instrument air purges in service.
G.
Turn on the steam supplies to all of the steam-jacketed sulfur vapor valves and use the vent valves on each jacket section to vent the air from the jackets. Manually "stroke" each valve and check to be sure it moves freely.
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12.7.2
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
Shutdown System Check-out A.
Fill the Thermal Oxidizer Waste Heat Boiler with treated boiler feed water up to the high level alarm point. As the level is rising, check the level transmitters and the high level alarms for proper operation.
B.
Use the quick-opening blowdown valve to lower the water level in the boiler and check for proper operation of the level transmitters, the low level alarms, and the low-low level shutdowns.
C.
Fill the boiler with treated boiler feed water back up to the normal liquid level. NOTE:
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The Thermal Oxidizer Waste Heat Boiler vendor recommends performing a "boil-out" with an aqueous alkaline solution during the initial startup to remove oil, grease, dirt, and biological material from the boiler drums and tubes. For this "boil-out" during the initial startup, the recommended chemical solution can be added to the boiler drum at this time as boiler feed water is added to bring the level back to the normal level points. Refer to the vendor's literature for the chemicals to be used. The "boil-out" can be performed during the refractory cure-out.
D.
Physically check all shutdown activating devices to ensure that they activate the TTO ESD system.
E.
Check all devices activated by the TTO ESD system to ensure that they operate properly.
F.
Check all relief valves to ensure that they are installed in the proper locations and set for the correct relieving pressures.
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12.7.3
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
Commissioning Fuel Gas, Pilot Gas, and I/A to the Process The fuel gas, pilot gas (vaporized C4 LPG), and instrument air supplies to the process side of the Thermal Oxidizer must be made ready for use prior to starting up the Thermal Oxidizer using the procedures in these guidelines. This requires blowing down each section of piping to ensure that there are no liquids and/or construction debris in the headers and supply lines. The procedure below can be used to make sure that these gas utility systems are ready for service.
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A.
Select local manual control for the main fuel gas control valve by switching the hand switch in the DCS to "local".
B.
Set the manual fuel gas control on the local TTO control panel to 0% output.
C.
Confirm that the following fuel gas, pilot gas, and instrument air valves are closed: (1)
The manual block valve(s) in the main fuel gas supply line.
(2)
The manual block valve(s) in the main pilot gas supply line.
(3)
The main fuel gas automated block valves, the fuel gas control valve, and the block valve at the burner in the main fuel gas line to the Thermal Oxidizer Burner.
(4)
The manual block valve(s), and the two automated block valves in the pilot gas supply line to the pilot.
(5)
The block valve(s) in the main instrument air supply line.
(6)
The manual block valves and the automated block valve in the air supply line to the pilot.
(7)
The manual block valve in the air supply line to the purges for the burner instruments.
(8)
The block valves in the purge lines to the burner instruments.
D.
Confirm that all of the manual vent/drain valves in the main fuel gas, pilot gas, pilot air, and purge air piping are closed.
E.
If the orifice plate has already been installed in the fuel gas flow meter, remove it for now.
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F.
G.
H.
I.
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK Disconnect the fuel gas, pilot gas, and instrument air from the burner system by performing the following steps: (1)
Unbolt the flanged connection at the burner in the main fuel gas supply line.
(2)
Disconnect the pilot gas supply tubing where it connects to the pilot.
(3)
Disconnect the instrument air supply tubing where it connects to the pilot.
(4)
Cover the open ends of these connections on the burner to prevent debris from entering when the upstream piping is blown down.
Remove the following pressure regulators, then cover the downstream piping to prevent debris from entering when the upstream piping is blown down: (1)
The main fuel gas supply regulator.
(2)
The pilot instrument air supply regulator.
(3)
The pilot gas supply regulator.
(4)
The purge instrument air supply regulator.
"Force" the PLC to open the following valves, then confirm they are open: (1)
The automated block valves in the main fuel gas supply line to the burner.
(2)
The automated block valves in the pilot gas supply line to the pilot.
(3)
The automated block valve in the instrument air supply line to the pilot.
"Force" the PLC to close the following valves, then confirm they are closed: (1)
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The automated vent valve on the main fuel gas supply line to the burner.
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The automated vent valve on the pilot gas supply line to the pilot.
J.
"Crack" the manual block valve in the main fuel gas supply line (upstream of the pressure regulator) and allow fuel gas to blow through the piping until it is clear. Then close the block valve, reinstall the main fuel gas supply pressure regulator, and reopen the gate valve.
K.
Using the pressure gauge and the vent valve downstream of the main fuel gas supply regulator, adjust the main fuel gas regulator to its specified setpoint.
L.
Use the manual fuel gas controller on the local control panel to fully open the control valve in the main fuel gas line, then use the downstream drain valve to blow out this section of piping. Close the drain valve when the piping is clear, then close the control valve.
M.
Open the bypass valve around the main fuel gas control valve. "Crack" the block valve at the burner and allow fuel gas to blow through the piping until it is clear. Then close the block valve and bypass valve.
N.
"Crack" the block valve in the main pilot gas supply line to the pilot (upstream of the pressure regulator) and allow pilot gas to blow through the piping until it is clear. Then close the block valve, reinstall the pilot gas supply pressure regulator, and reopen the block valve.
O.
Using the pressure gauge and the vent valve downstream of the pilot gas supply regulator, adjust the regulator to its specified setpoint.
P.
"Crack" the block valve downstream of two automated block valves and allow pilot gas to blow through the piping until it is clear. Then close the block valve.
Q.
"Crack" the block valve in the instrument air supply line to the pilot and blow air through the piping until it is clear. Then close the block valve, reinstall the pilot instrument air supply pressure regulator, and reopen the block valve.
R.
Using the pressure gauge and the vent valve downstream of the pilot instrument air supply regulator, adjust the regulator to its specified setpoint.
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
S.
"Crack" the block valve downstream of the pilot air supply automated block valve and allow instrument air to blow through the piping until it is clear. Then close the block valve.
T.
Remove the "forces" from the PLC and confirm that all of the automated block valves close and all of the automated vent valves open.
U.
Close the block valve in the main fuel gas supply line (upstream of the regulator), the block valve in the pilot gas supply to the pilot (upstream of the regulator), and the block valve in the instrument air supply to the pilot (upstream of the regulator) until the TTO is ready for startup.
V.
Reconnect the fuel gas, pilot gas, and instrument air to the burner systems by performing the following steps: (1)
Bolt the flanged connection at the burner in the main fuel gas supply line back together.
(2)
Reinstall the pilot gas supply tubing where it connects to the pilot.
(3)
Reinstall the instrument air supply tubing where it connects to the pilot.
(4)
Reinstall the orifice plate in the fuel gas flow meter.
W.
"Crack" the block valve in the instrument air supply line to the purge rotameters (upstream of the purge pressure regulator) and blow air through the piping until it is clear. Then close the block valve, reinstall the purge instrument air supply pressure regulator, and reopen the block valve.
X.
Using the pressure gauge and the downstream drain valve, adjust the purge instrument air regulator to its specified setpoint.
Y.
Open the drain valve to blow out this section of piping until it is clear, then close the drain valve.
Z.
Each of the low pressure purges for the burner instruments has a rotameter near where it connects to the process. Disconnect the upstream fitting at each rotameter and open its upstream ball valve briefly to blow any liquids or debris from the purge line. Reconnect each rotameter, disconnect the fitting where each purge enters the
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12.8 Startup Procedures The procedure used to start up the Thermal Oxidizer depends on whether the refractory in the Thermal Oxidizer is up to operating temperature. This first section describes the procedure for the initial startup of a new plant, and subsequent startups when the refractory is cold (less than 500°C in the Thermal Oxidizer). Subsequent startups with the refractory already up to operating temperature can use a different procedure, discussed later in Section 12.8.2 of these guidelines.
12.8.1
Initial Firing / Refractory Cure-out During the initial startup, the Thermal Oxidizer and downstream equipment will be warmed up to operating conditions following the initial refractory cure-out schedule for the Thermal Oxidizer. This cure-out schedule should be provided by the refractory vendor.
CAUTION
IT IS CRITICAL THAT THE WARMUP PROCEDURES BE FOLLOWED VERY CLOSELY. THE REFRACTORY MATERIAL MUST BE HEATED SLOWLY TO ALLOW THE CONTAINED WATER TO VAPORIZE AND ESCAPE FROM THE REFRACTORY LINING, WITHOUT EXERTING EXCESSIVE INTERNAL PRESSURE AND CAUSING LINING DAMAGE.
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12.8.1.1
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK Initial Preparations A.
Check that all devices in the TTO ESD have been satisfied, except for the following: (1)
Low-low air flow.
(2)
Neither blower running.
(3)
Flame failure.
The PLC logic provides bypasses for these three conditions so that the system can be started up.
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B.
Select local manual control for the air flow control valve by switching the hand switch in the DCS to "local".
C.
Place the air flow controller in "automatic".
D.
Select local manual control for the fuel gas control valve by switching the hand switch in the DCS to "local".
E.
Place the Thermal "automatic".
F.
"Toggle" the superheated steam hand switch in the DCS to give the blow-off pressure controller control of the superheater pressure via the steam blow-off control valve.
G.
Place the blow-off pressure controller in "manual" and set its output to 100% to fully open the steam blow-off control valve.
H.
Place the Thermal Oxidizer Waste Heat Boiler steam pressure controller in "automatic" and adjust its setpoint to 0.7 kg/cm2(g) (or whatever value the boiler manufacturer recommends) in preparation for "boil-out".
I.
Adjust the output from the temperature controller for the interstage desuperheater, to 0%. Switch the controller to "automatic" and adjust its setpoint to its normal value.
J.
Adjust the output from the temperature controller for the discharge desuperheater, to 0%. Switch the controller to "automatic" and adjust its setpoint to its normal value.
K.
Confirm that the Thermal Oxidizer Waste Heat Boiler is filled with water up to its normal liquid level.
Oxidizer
Tailgas Thermal Oxidation
temperature
controller
in
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Confirm that the superheated steam blow-off control valve is fully open.
M.
Confirm that the two desuperheater BFW supply control valves, and their bypass valves are closed. Confirm that the upstream and downstream block valves around the control valves are open.
N.
Open the vent valves on the boiler to vent air from the steam section.
O.
Set the manual fuel gas control on the local TTO control panel to 0% output. Visually confirm that the main fuel gas valve, its bypass valve, and the two main fuel gas shutdown valves are closed.
P.
Set the manual air control on the local TTO control panel to 0% output. Visually confirm that the air flow control valve is closed.
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Operating Guidelines Fall 2011
12.8.1.2
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK Igniting the Pilot Burner A.
Switch the Startup/Run selector switch on the local TTO control panel to "STARTUP". The PLC should perform the following actions: (1)
The TTO bypass valve is opened. The "BYPASS OPEN" status light on the local TTO control panel will flash until the valve has moved to the proper position, then remain steadily illuminated.
(2)
The TTO inlet valve is closed. The "INLET OPEN" status light will flash until the valve has moved to the proper position, then will be extinguished.
NOTE:
If a status light continues to flash, it means that the limit switches on the associated valve never confirmed that the valve moved to the proper position. If this occurs, the startup sequence will not be allowed to proceed until the problem is corrected and the valve moves to the proper position. Note that the valve may have actually moved to the proper position, but a faulty limit switch may not be detecting that the valve is in the proper position.
Confirm that these valves have moved to the proper positions. Confirm that the "BYPASS OPEN" light on the panel is illuminated, and that the "INLET OPEN" light on the panel is extinguished.
Issued 30 August 2011
B.
Verify that both of the local start/stop controls for the Thermal Oxidizer Air Blower have their selector switches turned to the "STOP" position.
C.
Verify that the discharge valves are closed on both air blowers.
D.
Start a Thermal Oxidizer Air Blower: (1)
Use the local start/stop control station to start the desired blower.
(2)
Once the blower comes up to speed, open its discharge valve.
Tailgas Thermal Oxidation
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK E.
Once an air blower is running, press the "ESD RESET" push-button on the local TTO control panel to reset the TTO ESD and extinguish the "RESET REQUIRED" light. This will illuminate the "PURGE REQUIRED" light.
F.
Verify that the "LIMITS SATISFIED" light is glowing steadily (not flashing) on the local TTO control panel. NOTE: If the "LIMITS SATISFIED" light is flashing, this means that a limit switch is not satisfied. The limit switches on the main fuel gas valves and the TTO inlet valve must all indicate that their valves are closed. For safety reasons, the PLC will not allow the light-off sequence to proceed until these valves are proven closed. Once the problem with the valves or their limit switches has been corrected, the "LIMITS SATISFIED" light will stop flashing and glow steadily, and the light-off sequence can proceed.
G.
Adjust the output of the local manual air control to open the air flow control valve and allow a large air flow, 80% or more on the flow indicator, to purge the furnace and downstream equipment for 5 minutes. The "PURGE REQUIRED" light will be extinguished and the "PURGE COMPLETE" light will be illuminated after about 40 seconds, but continue to purge the system for a full 5 minutes prior to this first time ignition attempt.
H.
Open the following manual block valves:
I.
(1)
The block valves in the pilot gas to the ignitor/pilot.
(2)
The block valves in the air supply to the ignitor/pilot.
Adjust the output of the local manual air control to reduce the air flow on the flow indicator to 10-20%. This will extinguish the "PURGE COMPLETE" light and illuminate the "PERMIT TO IGNITE" light, and the PLC will "enable" the ignition circuit. NOTE: Once the "PERMIT TO IGNITE" light is illuminated, an ignition safety interlock timer starts. If an ignition attempt is not made within 5 minutes, the TTO ESD system will be activated to shut down the Thermal Oxidizer. This prevents a potentially unsafe condition
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Tailgas Thermal Oxidation
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK from persisting, where a leaking fuel gas valve could cause an explosive mixture to form in the Thermal Oxidizer, since the air flow is low at this point in the startup procedure. If either scanner detects a flame before the "PILOT ON" push-button is pressed, this will activate the TTO ESD system and the "flame scanner malfunction" alarm in the DCS. This will stop the air blower and extinguish the flame (unless of course, a flame scanner is giving a false indication). A flame prior to ignition usually indicates a leaking fuel gas valve. If this occurs, check these valves before proceeding with startup, as a leaking valve can allow an explosive mixture to form in the Thermal Oxidizer without warning. J.
Issued 30 August 2011
Press the "PILOT ON" push-button to initiate an ignition attempt. The PLC will do the following: (1)
The air purge valve for the pilot burner is closed.
(2)
The ignitor/pilot air block valve is opened.
(3)
The ignitor/pilot gas vent valve is closed and the block valves are opened.
(4)
The ignition system is energized to begin sparking the ignitor inside the pilot in a series of pulses.
(5)
The "PILOT ON" light is illuminated.
K.
The air and pilot gas pressure regulators for the ignitor may require some adjustment when first put in service before the ignitor will light the pilot. However, once set properly, the ignitor should ignite the pilot readily on subsequent startups. Refer to the SRU Section of these guidelines for a suggested procedure to adjust these regulators.
L.
If neither flame scanner detects a flame after 15 seconds of sparking the ignitor, the ignition try is aborted, the TTO Burner Shutdown system is activated, and the PLC causes the sequence to return to Step G.
Tailgas Thermal Oxidation
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK M.
Issued 30 August 2011
When either of the flame scanners detects a flame from the pilot burner, the appropriate "FLAME PROVEN" light(s) are illuminated. The pilot air and pilot gas valves will remain open after the ignition trial, and the PLC will perform the following activities: (1)
The "LIMITS SATISFIED" and "PERMIT TO IGNITE" lights are extinguished.
(2)
The "PILOT ON" light remains illuminated.
(3)
The ignition system is de-energized.
(4)
The startup bypass in the PLC for the "flame failure" S/D is disabled.
(5)
The "MAIN FUEL START" push-button on the local TTO control panel is enabled.
(6)
The "RUN" position on the Startup/Run selector switch on the local TTO control panel is enabled.
N.
After the pilot is lit, use the local manual air control to increase the air flow rate to about 50%, or as high a rate as can be maintained without blowing the pilot out. When curing refractory, it is best to keep the air flow as high as possible to help distribute the heat more evenly and to heat the downstream equipment more quickly.
O.
The heat input from the pilot should be sufficient to reach the first "hold" point in the refractory warmup schedule, 100-150°C. If the temperature is too high, increase the air flow rate. If the temperature is too low, decrease the air flow rate.
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Operating Guidelines Fall 2011
12.8.1.3
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK Thermal Oxidizer Waste Heat Boiler "Boil-Out" The Thermal Oxidizer WHB vendor recommends performing a "boil-out" with an aqueous alkaline solution during the initial startup to remove oil, grease, dirt, and biological material from the boiler drum and tubes. This boiler "boil-out" can be performed in conjunction with the refractory cure-out of the Thermal Oxidizer. Refer to the vendor's literature for the specific procedure to be used. During "boil-out", the steam produced in the steam drum of the Thermal Oxidizer Waste Heat Boiler will flow through the superheater pass of the boiler and then be vented to atmosphere through the steam blow-off valve. Note that if the SRU(s) is being warmed up at the same time, any high pressure steam being produced by its Waste Heat Boiler will also be flowing through the superheater pass of the Thermal Oxidizer Waste Heat Boiler. Depending on the firing rate in the SRU(s), the steam flow may become too high to maintain the desired pressure in the Thermal Oxidizer Waste Heat Boiler steam drum (usually 0.7-1.0 kg/cm2(g)) even with the blow-off valve fully open. If this is the case, the firing rate will have to be reduced in the SRU(s) to reduce the steam production until "boil-out" of the Thermal Oxidizer Waste Heat Boiler is completed. Once "boil-out" has been completed, the steam pressure in the steam drum can be raised to its normal operating pressure. Confirm that WHB steam pressure control is in "automatic", then adjust its setpoint to its normal setting. Then place the steam pressure controller in control by confirming that its setpoint is tracking the current reading and switching the controller to "automatic". Slowly adjust its setpoint to its normal setting.
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Tailgas Thermal Oxidation
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Operating Guidelines Fall 2011
12.8.1.4
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK Igniting the Main Gas Burner, Refractory Cure-out and Warmup When the firing rate needs to be increased to raise the furnace temperature, the main gas burner can be placed in service. The local manual control has control of the main fuel gas valve at this time because the hand switch in the DCS is switched to "local". The fuel gas flow rate can be monitored using the flow indicator on the local TTO control panel and the flow indicator in the DCS. A.
Verify that the hand switch in the DCS is set to "local" to give local manual control of the fuel gas control valve.
B.
Confirm that the output from the manual fuel gas control on the local TTO control panel is set to 0%, that the fuel gas control valve and its bypass valve are closed, and that the two block valves at the control station are both open.
C.
Open the manual block valve in the main fuel gas line and the manual block valve at the burner.
D.
If the air flow rate is not at least 50%, use the local manual air control to set the air flow at 50% as indicated by the flow indicator.
E.
Press the "MAIN FUEL START" push-button on the local TTO control panel, to commission the main fuel gas. The PLC performs the following actions: (1)
The main fuel gas vent valve is closed.
(2)
The main fuel gas automated block valves are opened.
(3)
The fuel gas control valve is released to operator control.
(4)
The "MAIN FUEL ON" light on the local TTO control panel is illuminated.
(5)
A 2-minute low-low air flow S/D bypass timer is started.
NOTE: Be sure the air flow is above the low-low flow shutdown point, about 20% on the flow indicator, or the TTO ESD will be activated when the bypass timer expires and the Thermal Oxidizer will shut down. F.
Issued 30 August 2011
Use the manual fuel gas control on the local TTO control panel to slowly open the fuel gas control valve until the burner lights
Tailgas Thermal Oxidation
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK and has a stable flame. The "minimum fire" setting required for this particular burner at the normal air flow will be determined later. G.
The manual fuel gas control may now be used to manually control the furnace temperature. Make adjustments to the output as needed to follow the appropriate refractory cure-out or warmup schedule (from the refractory vendor), either the chart for the initial cure-out or the chart for normal warmup. The temperature of the Thermal Oxidizer is indicated on the local panel by a temperature indicator. The temperature is also indicated by the temperature control in the DCS, which can be used to monitor or control the warmup of the Thermal Oxidizer in the DCS. It is often helpful to maintain a log of air flow using the flow indicator on the local panel or the air flow controller in the DCS, fuel gas flow using the flow indicator on the local panel or the flow indicator in the DCS, and furnace temperature using a temperature indicator on the local panel or the temperature control in the DCS during the cure-out for future reference. NOTE: During the early stages of warmup when the furnace temperature is supposed to be low, the fuel gas flow rate may be too high with the control valve at its "minimum fire" position. If this is the case, use the local manual air control to raise the air flow in order to control the furnace temperature at the proper value.
H.
As the firing rate increases, raise the air flow rate with the local manual air control to 75%-80% as indicated by the flow indicator.
I.
Once the main fuel gas burner in the Thermal Oxidizer Burner is operating smoothly, the pilot burner can be shut down and retracted or extracted. For the initial startup of the Thermal Oxidizer, this step should be performed after the "minimum fire" setting for DCS the fuel gas control valve relay has been determined. Press the "PILOT STOP" push-button on the local TTO control panel. The PLC performs the following actions to block the pilot air and "double block and bleed" the pilot gas:
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Tailgas Thermal Oxidation
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK (1)
The automated block valve in the air supply to the ignitor/pilot is closed.
(2)
The ignitor/pilot pilot gas automated block valves are closed.
(3)
The pilot gas vent valve is opened.
(4)
The air purge valve for the pilot burner is opened.
(5)
The "PILOT ON" light is extinguished.
Verify that the air and pilot gas valves have moved to their proper positions and that the pilot burner is being purged with air as indicated by the rotameter. J.
K.
Close the following manual block valves: (1)
The manual block valves in the pilot gas supply to the ignitor/pilot.
(2)
The manual block valves in the air supply to the ignitor/pilot.
Loosen the packing gland on the pilot and retract or extract the pilot assembly: (1)
(2)
Issued 30 August 2011
If the pilot is just to be retracted: (a)
Retract it until it reaches the limit of the retraction bar.
(b)
Tighten the packing gland on the pilot.
(c)
Confirm that the pilot is still being purged with air as indicated by the air flow rotameter.
If the pilot is to be completely extracted: (a)
Retract it until the retaining chain is taut.
(b)
Close the block valve at the burner to isolate the pilot from the furnace.
(c)
Close the block valve in the purge air to the pilot burner.
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK CAUTION: THE PILOT ASSEMBLY WILL BE VERY HOT. HANDLE IT CAREFULLY TO AVOID BURNS AND TO AVOID DAMAGING IT. (d)
(3)
Disconnect the chain and remove the pilot assembly and store it in a safe place.
Verify that the pilot burner mounting nozzle is still being purged with air as indicated by the rotameter.
L.
Frequently confirm that the proper water level is maintained in the Thermal Oxidizer Waste Heat Boiler. Confirm that the level control system is functioning properly.
M.
As steam pressure starts to build in the Thermal Oxidizer Waste Heat Boiler, confirm that the boiler pressure controller in the DCS is in "automatic" and controlling the steam pressure at its setpoint. Allow the vent valves to sweep non-condensibles out of the steam spaces on the boiler.
N.
Confirm that the superheater pass pressure controller in the DCS is in "automatic" with the proper setpoint. At this time, the steam pressure "toggle" switch in the DCS has not yet been reset, so the steam leaving the superheater pass is still being vented to atmosphere through the silencer.
Issued 30 August 2011
O.
Confirm that the interstage desuperheater temperature controller and the discharge despuerheater temperature controller in the DCS are in "automatic".
P.
As the equipment and piping heat up, inspect all of the equipment and piping for the effects of thermal expansion. Ensure that all slide plates, rollers, spring hangers, etc. are functioning properly.
Q.
As the steam pressure builds in the boiler, the vent valves on the steam sections may be closed.
R.
As the superheated steam temperature begins to increase, confirm that the temperature controllers on the desuperheaters
Tailgas Thermal Oxidation
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK are adding BFW as needed to prevent excessive temperatures around the superheat passes of the boiler. S.
T.
Issued 30 August 2011
Switch the combustion air flow control from the local TTO control panel to the DCS as follows: (1)
Confirm that the air flow controller in the DCS is in "automatic", its output is tracking the output from the manual air control on the local TTO control panel as indicated by the hand indicator in the DCS, and its setpoint is tracking its current reading.
(2)
Switch the air flow control hand switch from "local" to "remote". The air flow controller now has control of the air flow control valve, and will be controlling the air flow rate with its last value as the setpoint.
(3)
Slowly adjust the setpoint of the air flow controller to its normal value.
Switch the temperature control of the Thermal Oxidizer from the local TTO control panel to the DCS as follows: (1)
Confirm that the temperature control in the DCS is in "automatic", its output is tracking the output of the manual fuel gas control on the local TTO control panel as indicated by the hand indicator in the DCS, and its setpoint is tracking its current reading.
(2)
Switch the temperature hand switch from "local" to "remote". The temperature control now has control of the fuel gas control valve, and will be controlling the temperature with its last value as the setpoint.
U.
Adjust the setpoint of the temperature controller as necessary so that the Thermal Oxidizer continues to follow the appropriate refractory cure-out or warmup schedule.
V.
When the temperature of the superheated steam leaving the superheater pass of the Thermal Oxidizer Waste Heat Boiler reaches the proper value and is under control, the high pressure steam can be directed to the export header. After confirming that the steam header is ready to accept steam, "toggle" the reset permit switch in the DCS.
Tailgas Thermal Oxidation
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK The relay in the DCS will begin ramping down the output to the steam blow-off valve. As the valve closes, the pressure in the steam header will begin to increase until it is high enough to open the check valve and the steam begins flowing to the export header. Confirm that the blow-off valve closes fully. W.
Issued 30 August 2011
At the conclusion of the refractory cure-out during the initial startup, the "minimum fire" setting for the burner needs to be determined: (1)
Adjust the output of the manual fuel gas flow control on the local TTO control panel so that the reading displayed on the hand indicator in the DCS matches the current output from the temperature control.
(2)
Switch the hand switch in the DCS from "remote" to "local".
(3)
While observing the flame through one of the viewports on the burner, slowly reduce the fuel gas flowrate by reducing the output of the manual fuel gas control until the flame starts to become unstable.
(4)
Raise the fuel gas flowrate back up slightly using the manual fuel gas control until the flame is stable again.
(5)
This is the actual "minimum fire" setting required for this particular burner. Record the fuel gas flowrate on the flow indicator in the DCS and the output on the manual fuel gas control on the local TTO control panel.
(6)
Use the manual fuel gas control to raise the fuel gas flowrate back up to the value before starting this step. Confirm that the temperature control is still in "automatic" and its output is tracking the manual fuel gas control, then switch the hand switch back to "remote" and adjust the setpoint of the temperature control to its normal setpoint.
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Operating Guidelines Fall 2011
12.8.1.5
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK Routing SRU/TGCU Tailgas to the Thermal Oxidizer A.
When the Thermal Oxidizer temperature reaches 816°C, the TTO is ready to be placed in service. Switch the Startup/Run selector switch on the local TTO control panel to "RUN". The PLC will perform the following actions: (1)
The TTO inlet valve is opened.
(2)
After the limit switches prove this valve open, the TTO bypass valve is closed.
Confirm that these valves have moved to the proper positions. Confirm that the "INLET OPEN" light on the panel is illuminated, and the "BYPASS OPEN" light on the panel is extinguished. B.
Issued 30 August 2011
The Thermal Oxidizer is now on-stream, ready to incinerate SRU tailgas or TGCU effluent. Before directing your attention away from the Thermal Oxidizer, be sure that: (1)
The Thermal Oxidizer is operating smoothly, with both the combustion air and fuel gas on automatic control.
(2)
The Thermal Oxidizer Waste Heat Boiler level, pressure, and steam temperature controls are functioning properly.
(3)
The stack gas analyzers are performing satisfactorily.
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Operating Guidelines Fall 2011
12.8.2
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
Normal Startup The procedure for startup of the unit after it has been shut down for a short period, not long enough to get cold (less than about 500°C in the Thermal Oxidizer), will be very similar to the procedure for the initial startup, Section 12.8.1 of these guidelines. However, the steps to be performed are written in this Section to serve as a "check list" that can be easily followed on subsequent startups. Refer to the previous Section for the reasons and details pertaining to the different steps performed.
WARNING THE THERMAL OXIDIZER MAY BE SAFELY RESTARTED WHILE THE SRUS ARE RUNNING (WITH OR WITHOUT THE TGCU ON-LINE) BECAUSE THE TTO FEED GAS IS BYPASSED AROUND THE THERMAL OXIDIZER DURING STARTUP. HOWEVER, IF THE FEED GAS TO THE TTO CONTAINS AN EXCESSIVE AMOUNT OF COMBUSTIBLES, THE THERMAL OXIDIZER WILL SHUT DOWN ON HIGH-HIGH FURNACE TEMPERATURE WHEN THE TTO INLET VALVE IS OPENED. THE MAJOR COMBUSTIBLE THAT MAY EXIST IN THE TTO FEED GAS IS H2S, ESPECIALLY IF THE SULFUR PLANT IS UPSET AND RUNNING WITH DEFICIENT AIR, OR THE TGCU IS UPSET AND ALLOWING H2S TO "SLIP". THIS WOULD BE INDICATED BY LOW AIR DEMAND ON THE AIR DEMAND CONTROLLER IN THE DCS, AND/OR HIGH H2S ON THE TGCU H2S ANALYZER IF THE TGCU IS OPERATING. HOWEVER, IF EITHER ANALYZER IS OUT OF SERVICE OR IF THERE IS ANY REASON TO SUSPECT HIGH H2S IN THE TTO FEED GAS, THE FEED GAS SHOULD BE TESTED FOR H2S TO DETERMINE WHETHER IT IS SAFE TO RESTART THE TTO. GAS DETECTOR TUBES (DRÄGER TUBES, ETC.) MAY BE USED TO SAMPLE THE TTO FEED GAS. REFER TO THE LABORATORY PROCEDURES GIVEN IN THESE GUIDELINES.
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
IF THE AIR DEMAND IN THE SRU(S) IS LOW (BELOW –3.0%) OR THE H2S CONCENTRATION IN THE FEED GAS TO THE THERMAL OXIDIZER IS HIGH (ABOVE 3%), DO NOT ATTEMPT TO RESTART THE TTO. INSTEAD, DIRECT YOUR ATTENTION TO THE AMINE OR SWS UNIT(S) UPSTREAM OF THE SRUS (WHICH ARE PROBABLY CAUSING THE PROBLEM) AND BRING THE SRU(S) BACK ON-RATIO, OR CORRECT THE OPERATING PROBLEM IN THE TGCU. THIS WILL REDUCE THE CONCENTRATION OF H2S IN THE TTO FEED GAS TO AN ACCEPTABLE LEVEL, SO THAT RESTARTING THE THERMAL OXIDIZER PROCEEDS SMOOTHLY. FAILURE TO CORRECT THE UPSTREAM PROBLEM(S) FIRST WILL LIKELY LEAD TO THE THERMAL OXIDIZER SHUTTING DOWN AGAIN, REQUIRING ANOTHER RESTART OF THE TTO. Prior to commencing Thermal Oxidizer startup:
Issued 30 August 2011
1.
Check for the completion of all maintenance work (connecting lines, removing blinds, etc.) if such work was performed.
2.
Place all steam heating systems in service. Check all steam traps for proper operation, and use the vent valves to sweep non-condensibles out of the steam spaces.
3.
Physically check all shutdown-activating devices to ensure that they activate the TTO ESD system.
4.
Physically check all devices activated by the TTO ESD system to ensure that they operate properly.
5.
Confirm that the Thermal Oxidizer Waste Heat Boiler is filled with water up to its normal liquid level.
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Operating Guidelines Fall 2011
12.8.2.1
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK Initial Preparations A.
Check that all devices on the TTO ESD have been satisfied, except for the following: (1)
Low-low air flow.
(2)
Neither blower running.
(3)
Flame failure.
B.
Select local manual control for the air flow control valve by switching the hand switch in the DCS to "local".
C.
Place the air flow controller in "automatic".
D.
Select local manual control for the fuel gas control valve by switching the hand switch in the DCS to "local".
E.
Place the Thermal "automatic".
F.
Confirm that the following controllers are in "automatic" with their setpoints:
G.
Oxidizer
temperature
controller
in
(1)
The Thermal Oxidizer Waste Heat Boiler steam pressure controller.
(2)
The Thermal Oxidizer Waste Heat Boiler superheater pressure controller.
(3)
The interstage desuperheater temperature controller.
(4)
The export steam temperature controller.
Set the manual fuel gas control on the local TTO control panel to 0% output. Visually confirm that the main fuel gas valve and its bypass valve are closed.
H.
Set the manual air control on the local control panel to 0% output. Visually confirm that the air flow control valve is closed.
I.
Prepare the pilot burner for service: (1)
Issued 30 August 2011
If the pilot is in the retracted position:
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
(2)
Issued 30 August 2011
(a)
Loosen the packing gland on the pilot.
(b)
Slide the pilot forward until it reaches the limit of the retraction bar.
If the pilot was extracted earlier: (a)
Insert the pilot assembly into its packing gland and open the block valve at the furnace.
(b)
Slide the pilot assembly forward until it reaches the limit of the retraction bar.
(c)
Reconnect the retaining chain.
(d)
Open the block valve in the purge air to the pilot and confirm that the pilot is now being purged with air.
(3)
Tighten the packing gland on the pilot.
(4)
Verify that the pilot burner mounting nozzle is still being purged with air.
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12.8.2.2
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK Igniting the Pilot Burner A.
Switch the Startup/Run selector switch on the local TTO control panel to "STARTUP". The PLC will open the TTO bypass valve and close the TTO inlet valve. Verify that the "BYPASS OPEN" light on the panel is now illuminated and the "INLET OPEN" light on the panel is extinguished. NOTE:
If a status light continues to flash, it means that the limit switches on the associated valve never confirmed that the valve moved to the proper position. If this occurs, the startup sequence will not be allowed to proceed until the problem is corrected and the valve moves to the proper position.
B.
Verify that the local start/stop controls for the blowers have their selector switches turned to the "STOP" position.
C.
Verify that the discharge valves are closed on both air blowers.
D.
Start a Thermal Oxidizer Air Blower: (1)
Use the local start/stop control station to start the desired blower.
(2)
Once the blower comes up to speed, open its discharge valve.
E.
Once an air blower is running, press the "ESD RESET" push-button on the local TTO control panel to reset the TTO ESD and extinguish the "RESET REQUIRED" light. This will illuminate the "PURGE REQUIRED" light.
F.
Verify that the "LIMITS SATISFIED" light is glowing steadily (not flashing) on the local TTO control panel. NOTE:
If the "LIMITS SATISFIED" light is flashing, this means that a limit switch is not indicating that the fuel gas valves and the TTO inlet valve are all closed. For safety reasons, the PLC will not allow the light-off sequence to proceed until these valves are proven closed. Once the problem with the valves or their
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK limit switches has been corrected, the "LIMITS SATISFIED" light will stop flashing and glow steadily, and the light-off sequence can proceed. G.
Open the following manual block valves: (1)
The manual block valves in the pilot gas to the ignitor/pilot.
(2)
The block valves in the air supply to the ignitor/pilot.
H.
Adjust the output of the local manual air control to open the air flow control valve and allow a large air flow, 80% or more on the flow indicator, to purge the furnace for 40 seconds and extinguish the "PURGE REQUIRED" light. The "PURGE COMPLETE" light will then be illuminated.
I.
Adjust the output of the local manual air control to reduce the air flow on the flow indicator to 10-20%. This will extinguish the "PURGE COMPLETE" light and illuminate the "PERMIT TO IGNITE" light. NOTE: Remember that the ignition safety timer will shut down the Thermal Oxidizer if an ignition attempt is not made within 5 minutes of receiving the "PERMIT TO IGNITE".
Issued 30 August 2011
J.
Press the "PILOT ON" push-button to initiate an ignition attempt.
K.
If neither flame scanner detects a flame after 15 seconds of sparking the ignitor, the ignition try is aborted, the TTO Burner Shutdown system is activated, and the PLC causes the sequence to return to Step H.
L.
When either of the flame scanners detects a flame from the pilot burner, the pilot air and natural gas valves will remain open and the PLC will enable the "MAIN FUEL START" switch on the local TTO control panel.
M.
Adjust the output of the local manual air control to increase the air flow on the flow indicator to at least 50%.
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12.8.2.3
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK Igniting the Main Gas Burner A.
Confirm that the output from the manual fuel gas control on the local TTO control panel is set to 0%, that the fuel gas control valve and its bypass valve are closed, that the block valves at the control station are both open, and that the manual block valves in the main fuel gas line and the block valve at the burner are open.
B.
If the air flow rate is not at least 50%, use the local manual air control to set the air flow at 50% as indicated by the flow indicator.
C.
Press the "MAIN FUEL START" push-button on the local TTO control panel to open the main fuel gas block valves. NOTE: Be sure the air flow is above the low-low flow shutdown point, about 20% on the flow indicator, or the TTO ESD will be activated when the bypass timer expires and the Thermal Oxidizer will shut down. (This timer begins running when the "MAIN FUEL START" push-button is pressed, and has a 2 minute duration.)
Issued 30 August 2011
D.
Use the manual fuel gas control to increase the firing rate and bring the Thermal Oxidizer back to its normal operating temperature.
E.
As the firing rate increases, raise the air flow rate with the local manual air control to 75%-80% as indicated by the flow indicator.
F.
Press the "PILOT STOP" push-button on the local TTO control panel to block the pilot air and to "double block and bleed" the pilot gas. Verify that the "PILOT ON" light is extinguished.
G.
Close the following manual block valves: (1)
The manual block valves in the pilot gas to the pilot.
(2)
The manual block valves in the air supply to the pilot.
Tailgas Thermal Oxidation
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK H.
Loosen the packing gland on the pilot and retract or extract the pilot assembly: (1)
(2)
If the pilot is just to be retracted: (a)
Retract it until it reaches the limit of the retraction bar.
(b)
Tighten the packing gland on the pilot.
(c)
Confirm that the pilot is still being purged with air.
If the pilot is to be completely extracted: (a)
Retract it until the retaining chain is taut.
(b)
Close the block valve at the furnace to isolate the pilot from the furnace.
(c)
Close the block valve in the purge air to the pilot burner. CAUTION: THE PILOT ASSEMBLY WILL BE VERY HOT. HANDLE IT CAREFULLY TO AVOID BURNS AND TO AVOID DAMAGING IT.
(d)
(3)
Verify that the pilot burner mounting nozzle is still being purged with air.
I.
Confirm that the Thermal Oxidizer Waste Heat Boiler steam pressure controller is in "automatic" and is controlling the steam pressure properly.
J.
Confirm that the superheated steam temperature controllers are in "automatic" and are controlling the steam temperature properly.
K.
Switch the combustion air flow control from the local TTO control panel to the DCS as follows: (1)
Issued 30 August 2011
Disconnect the chain and remove the pilot assembly and store it in a safe place.
Confirm that the air flow controller in the DCS is in "automatic", its output is tracking the output from the
Tailgas Thermal Oxidation
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK manual air control on the local TTO control panel, and its setpoint is tracking its current value.
L.
Issued 30 August 2011
(2)
Switch the air flow control hand switch from "local" to "remote". The air flow controller now has control of the air flow control valve, and will be controlling the air flow rate with its last value as the setpoint.
(3)
Slowly adjust the setpoint of the air flow controller to its normal value.
Switch the temperature control of the Thermal Oxidizer from the local TTO control panel to the DCS as follows: (1)
Confirm that the temperature control in the DCS is in "automatic", its output is tracking the output of the manual fuel gas control on the local TTO control panel, and its setpoint is tracking its current value.
(2)
Switch the hand switch from "local" to "remote". The temperature control now has control of the fuel gas control valve, and will be controlling the temperature with its last value as the setpoint.
(3)
Slowly adjust the setpoint of the temperature control to its normal value.
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Operating Guidelines Fall 2011
12.8.2.4
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK Routing SRU/TGCU Tailgas to the Thermal Oxidizer A.
When the Thermal Oxidizer temperature reaches 816°C, the TTO is ready to be placed in service. Switch the Startup/Run selector switch on the local TTO control panel to "RUN". The PLC will open the TTO inlet valve, then close the TTO bypass valve. The "INLET OPEN" light will be illuminated, then the "BYPASS OPEN" light will be extinguished as the valves move to their new positions.
Issued 30 August 2011
B.
If the temperature of the superheated steam leaving the superheater pass of the Thermal Oxidizer Waste Heat Boiler fell low enough to activate the low-low temperature interlock while the Thermal Oxidizer was being restarted, the steam will be venting to atmosphere at this time. After confirming that the steam temperature is under control at the proper value and the steam header is ready to accept steam, "toggle" the steam reset permit switch in the DCS to slowly close the steam blow-off valve and send the steam to the export header.
C.
The Thermal Oxidizer is back on-stream, incinerating SRU tailgas or TGCU effluent. Before directing your attention away from the Thermal Oxidizer, be sure that: (1)
The Thermal Oxidizer is operating smoothly, with both the combustion air and fuel gas on automatic control.
(2)
The Thermal Oxidizer Waste Heat Boiler level, pressure, and steam temperature controls are functioning properly.
(3)
The stack gas analyzers are performing satisfactorily.
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
12.9 Shutdown Procedures The procedures to be used in performing a planned shutdown of the Thermal Oxidizer will vary depending on the extent and type of work to be performed in and around the TTO during the downtime period. If there are no plans for entering the TTO equipment, no special procedures are required in performing the shutdown. Section 12.9.1 that follows is an example of such a procedure. However, if you plan to enter any vessels for inspection or maintenance, then more extensive and lengthy procedures must be followed to accomplish a satisfactory shutdown and minimize the time required for performance of the desired maintenance work. Section 12.9.2 that follows is an example of a procedure for this circumstance. One special circumstance that may exist during a shutdown is to have tube leaks in the Thermal Oxidizer Waste Heat Boiler. This special case is discussed in Section 12.9.3. Section 12.9.4 is a discussion of emergency shutdown situations. A guide to troubleshooting the causes of unplanned shutdowns is presented to assist in quickly identifying and correcting the problem so the Thermal Oxidizer can be put back on-line in a minimum amount of time. The TTO is affected directly and indirectly by shutdowns and outages that occur in other systems both within the Sulfur Block and outside the battery limits. The more important aspects of the effects these other systems can have on the Thermal Oxidizer are discussed in Section 0. Typical shutdown procedures are outlined and discussed in the sections that follow for the more common cases. Your existing company procedures and common sense operational judgment should be used to modify these procedures as needed to serve the purpose of any given planned shutdown situation.
Issued 30 August 2011
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Operating Guidelines Fall 2011
12.9.1
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
Planned Shutdown - No Entry When there are no plans to enter any of the equipment in the TTO system, no special shutdown procedures are required. Under these circumstances, the shutdown procedure given in this section may be used as a guide. It is generally preferable to shut down the Thermal Oxidizer in a controlled fashion to minimize the impact on the other process units, particularly if the SRUs and/or TGCU are to remain on-line. If time does not allow performing a controlled shutdown, however, the Thermal Oxidizer can be shut down by simply activating its TTO ESD system (using either the local push-button or the DCS "toggle" switch). This will automatically block the fuel gas, pilot gas, and combustion air feeding the Thermal Oxidizer. A.
If the SRUs and/or the TGCU are to be shut down also, shut down the TGCU first using the appropriate procedures from Section 11.9 Then shutdown the SRUs using the appropriate procedures from Section 9.9. NOTE:
If the SRUs are to remain in service while the TTO is shut down, SRU tailgas or TGCU effluent (plus the Sulfur Surge Tank sweep air and spent degassing air) will be flowing through the Thermal Oxidizer. Since these gases contains H2S (and possibly SO2), they should not be allowed to escape to the surroundings except from the top of the Thermal Oxidizer Vent Stack. The operating permit for this plant may not allow venting un-oxidized process gases for extended periods. In addition to H2S and SO2, SRU tailgas, Sulfur Surge Tank sweep air, and spent degassing air also contain elemental sulfur. This sulfur may condense in the Thermal Oxidizer system while it is shut down.
Issued 30 August 2011
B.
If the SRUs and the TGCU have been shut down, continue firing the Thermal Oxidizer Burner with the main fuel gas burner for several minutes to clear as much of the sulfur gases out of the system as possible.
C.
Use the "toggle" switch in the DCS or the push-button on the local TTO control panel to activate the TTO ESD system.
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Operating Guidelines Fall 2011
D.
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK Switch the Startup/Run selector switch on the local TTO control panel to "STARTUP". This will open the Thermal Oxidizer Bypass valve and prove it open, then close the Thermal Oxidizer Feed valve.
E.
Close the manual block valves in the discharge lines of the Thermal Oxidizer Air Blowers.
F.
Visually confirm that:
G.
(1)
The main fuel gas shutdown valves are closed and the vent valve is open.
(2)
The block valves in the main fuel gas line and pilot gas supply line are closed.
(3)
The automated block valve in the air supply to the ignitor/pilot, and the automated block valves in the pilot gas supply to the ignitor/pilot, are closed and the pilot gas vent valve is open.
(4)
The Thermal Oxidizer Air Blowers are shut down and their discharge valves are closed.
(5)
The air flow control valve is closed.
If the Thermal Oxidizer will be down for an extended period, special precautions should be taken to prevent the boiler tubes from cooling to the point where water can condense on them. Most of the corrosion that occurs in TTOs is due to the acidic water that can form if the plant is allowed to get cold. Allow the Thermal Oxidizer Waste Heat Boiler to cool enough to Then reduce the steam pressure to about 1.0 kg/cm2(g). de-pressure the boiler and drain the water from it. Use a temporary "jumper" to supply LP steam to the boiler, and drain the condensate from it occasionally. This will keep the tubes safely above the water condensation temperature (100-110°C) and above the temperature at which sulfur freezes (119°C).
Issued 30 August 2011
Tailgas Thermal Oxidation
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Operating Guidelines Fall 2011
12.9.2
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
Planned Shutdown for Entry When vessel entry for maintenance, inspection, or other purposes is required, the Thermal Oxidizer must be cooled down and isolated. The procedure below may be used as a guide for performing this type of shutdown. A.
Shut down the TGCU first with the appropriate procedures.
B.
Shut down the SRU with the appropriate procedures.
C.
Shut down the SDU with the appropriate procedures.
D.
Shut down the Sulfur Surge Tank Vent Ejectors as follows: (1)
Close the gate valve and the globe valve in the motive steam supply line.
(2)
Close its manual discharge valve.
WARNING NEVER BLOCK-IN THE EJECTORS COMPLETELY (CLOSING BOTH THE SUCTION VALVE AND THE DISCHARGE VALVE AT THE SAME TIME) WHILE THE HP MOTIVE STEAM SUPPLY LINE IS CONNECTED TO THE EJECTOR. A LEAK IN THE MOTIVE STEAM BLOCK VALVES COULD ALLOW THE HP STEAM TO OVER-PRESSURE THE EJECTOR BODY. E.
Continue firing the Thermal Oxidizer Burner with the main fuel gas burner for several minutes to clear as much of the sulfur gases out of the system as possible.
F.
Use the temperature controller to gradually reduce the temperature in the Thermal Oxidizer. To prevent damage to the refractory lining in the furnace, do not allow the temperature to drop more rapidly than 100-150°C per hour. NOTE:
Issued 30 August 2011
As the furnace temperature drops, the fuel gas flow rate will become progressively lower. Once the fuel gas control valve reaches its "minimum fire" position, it will not be possible to drop the temperature any further.
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Operating Guidelines Fall 2011
G.
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK Once the furnace temperature reaches 100-150°C, the burner can be extinguished and the air blower used to provide the rest of the cooling: (1)
Shut down the Thermal Oxidizer by pressing the S/D push-button on the local TTO control panel.
(2)
Visually confirm that the main fuel gas shutdown valves are closed and the vent valve is open.
(3)
Visually confirm that the automated block valves in the pilot gas supply to the ignitor/pilot are closed and the vent valve is open.
(4)
Close the gate valve in the main fuel gas supply line and the gate valve at the burner.
(5)
Switch the Startup/Run selector switch on the local TTO control panel to "STARTUP".
(6)
Switch the air flow control hand switch in the DCS to "local" so that the manual air control on the local TTO control panel has control of the air flow control valve.
(7)
Start a Thermal Oxidizer Air Blower and open its discharge valve.
(8)
Press the "ESD RESET" push-button on the local TTO control panel.
(9)
Adjust the manual air control to send a large flow, 80% or more on the combustion air flow line alarms, to the Thermal Oxidizer.
H.
Allow the large flow of air to continue until the Thermal Oxidizer reaches ambient temperature.
I.
Once the Thermal Oxidizer is cool, use the "toggle" switch in the DCS, or the push-button on the local TTO control panel to activate the TTO ESD system.
J.
Close the manual block valves in the discharge lines of the Thermal Oxidizer Air Blowers.
K.
Visually confirm that: (1)
Issued 30 August 2011
The main fuel gas shutdown valves are closed and the vent valve is open.
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Operating Guidelines Fall 2011
L.
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK (2)
The block valves in the main fuel gas line and the pilot gas supply line are closed.
(3)
The automated block valve in the air supply to the ignitor/pilot and the automated block valves in the pilot gas supply to the ignitor/pilot are closed and the pilot gas vent valve is open.
(4)
The Thermal Oxidizer Air Blowers are shut down and their discharge valves are closed.
(5)
The air flow control valve is closed.
Isolate the Thermal Oxidizer from all potential contaminating gases using slip blinds or by disconnecting the piping. In particular, isolate the Thermal Oxidizer from the SRUs and the TGCU using slip-blinds, etc.
WARNING THE THERMAL OXIDIZER INLET LINE CONTAINS TOXIC GASES (H2S AND SO2). THE "GENERAL SAFETY" SECTION OF THIS MANUAL SHOULD BE CONSULTED IF THERE IS ANY DOUBT ABOUT HOW TO WORK SAFELY WHEN THESE GASES ARE PRESENT.
CAUTION SINCE ISOLATION OF THE THERMAL OXIDIZER RESULTS IN THE LOW PRESSURE PIPING AND EQUIPMENT IN THE SRUS AND TGCU BEING COMPLETELY BLOCKED-IN, THE ACID GAS TO THE SRUS, SWS GAS TO THE SRUS, FUEL GAS TO THE SRUS, REDUCING GAS TO THE TGCU, AND NITROGEN PURGES TO THE SRUS AND THE TGCU SHOULD ALSO BE BLINDED OR DISCONNECTED. THIS WILL ENSURE THAT A LEAKING VALVE, ESPECIALLY FUEL GAS OR NITROGEN, WILL NOT BE ABLE TO OVER-PRESSURE THE SRUS AND/OR THE TGCU.
Issued 30 August 2011
Tailgas Thermal Oxidation
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Operating Guidelines Fall 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
M.
Once the Thermal Oxidizer is isolated, the TTO system can be opened for entry. Refer to the "General Safety" section of this manual for procedures to be followed when performing maintenance work on this plant.
N.
If the Thermal Oxidizer will be down for an extended period, special precautions should be taken to prevent the boiler tubes from cooling to the point where water can condense on them. Most of the corrosion that occurs in TTOs is due to the acidic water that can form if the plant is allowed to get cold. Allow the Thermal Oxidizer Waste Heat Boiler to cool enough to reduce the steam pressure to about 1.0 kg/cm2(g). Then de-pressure the boiler and drain the water from it. Use a temporary "jumper" to supply LP steam to the boiler, and drain the condensate from it occasionally. This will keep the tubes safely above the water condensation temperature (100-110°C) and above the temperature at which sulfur freezes (119°C).
Issued 30 August 2011
Tailgas Thermal Oxidation
Page 12-64
Operating Guidelines Fall 2011
12.9.3
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
Shutting Down When Boiler Tubes Are Leaking One special circumstance that merits discussion is shutting down the TTO when there are tube leaks in the Thermal Oxidizer Waste Heat Boiler. While the plant is running, minor tube leaks usually cause little damage because the hot process gas vaporizes the boiler feed water before it has a chance to form acid and cause rapid corrosion. When a Thermal Oxidizer is shut down, however, several problems can develop: 1.
Liquid water may accumulate in the equipment or piping and form a variety of acids (sulfurous, polythionic, etc.) that will rapidly corrode the steel.
2.
Liquid water may reach the refractory linings in the equipment and damage the linings.
3.
If there is a large tube leak in the boiler, water may back-flow into the hot Thermal Oxidizer and rapidly vaporize, possibly violently enough to damage its refractory lining or create high pressure in the Thermal Oxidizer.
If a boiler tube leak is suspected, a shutdown procedure similar to the following may be appropriate:
Issued 30 August 2011
A.
Shut down the TGCU, shut down the SDU and shut off the Sulfur Surge Tank Vent Ejectors. Shut down the SRUs.
B.
Begin cooling down the Thermal Oxidizer using the procedure in Section 12.9.2. Do not activate the TTO ESD to shut down the air blower (Step I in Section 12.9.2) until the Thermal Oxidizer Waste Heat Boiler has been drained in Step E below.
C.
De-pressure the Thermal Oxidizer Waste Heat Boiler, taking care to reduce the pressure slowly enough to avoid over-stressing the boiler.
D.
Maintain a visible water level in the boiler. Water must remain in the boiler until it is de-pressured and the Thermal Oxidizer has been cooled to prevent overheating damage to the tubes.
E.
Once the Thermal Oxidizer is cool and the boiler is fully de-pressured, drain the water from the boiler to prevent any further leakage into the process side of the equipment.
F.
The TTO is now ready to be isolated and made safe for entry.
Tailgas Thermal Oxidation
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Operating Guidelines Fall 2011
12.9.4
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
Emergency Shutdown The TTO ESD system can be initiated by any of the actuating devices outlined in Section 12.5.9.1 of this manual, or by a power failure. The operator must determine and correct the condition causing the shutdown before the TTO can be restarted. The problems outlined below should be investigated first by the operator in his troubleshooting procedure. If the malfunction causing the emergency shutdown can be determined and corrected in a short period of time, the TTO can be put back on-line using the normal restart procedure outlined in Section 12.8.2 of this manual.
Issued 30 August 2011
S/D Actuation Device
Possible Causes
Thermal Oxidizer Burner Low-Low Combustion Air Flow
1. Malfunction of the flow control valve or flow control system. 2. Blower discharge block valve is closed or pinched. 3. The discharge block valve on the spare blower is open, allowing air to escape. 4. Blower shutdown due to mechanical problems with the blower, the motor, or the switchgear. 5. High pressure drop from plugging in the waste heat boiler.
Thermal Oxidizer Air Blower Neither Blower Running
1. Equipment damage has caused the blower to quit running. 2. A failure in the starter contacts is causing a false indication that the blower is not running.
Thermal Oxidizer Burner Fuel Gas Low-Low Pressure
1. A manual block valve is closed or pinched. 2. Header pressure is low due to problems elsewhere. 3. Malfunction of the fuel gas pressure regulator.
Thermal Oxidizer Burner Fuel Gas High-High Burner Pressure
1. Malfunction of the fuel gas pressure regulator. 2. Malfunction of the temperature control system. 3. The burner has been damaged (tip plugged or obstructed, etc.).
Tailgas Thermal Oxidation
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Issued 30 August 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
S/D Actuation Device
Possible Causes
Thermal Oxidizer Burner Flame Failure
1. Failure of a component in the flame sensor circuit. 2. Condensation of sulfur or water vapor on the lens of the flame scanners. 3. Low fuel gas flow due to: a. Malfunction of the temperature control valve or the temperature control system. b. Malfunction of the fuel gas pressure regulator. c. A manual valve is closed or pinched. d. Fuel gas header pressure is low due to problems elsewhere. 4. Low combustion air flow due to: a. Malfunction of the flow control valve or the flow control system. b. Blower discharge block valve is closed or pinched. c. The discharge block valve on the spare blower is open, allowing air to escape. d. Blower shutdown due to mechanical problems with the blower, the motor, or the switchgear. e. High pressure drop from plugging in the waste heat boiler.
Thermal Oxidizer High-High Temperature
1. A sulfur plant is off-ratio, causing the tailgas from that SRU to contain large amounts of H2S (a combustible gas). 2. An upset in the TGCU is allowing large amounts of H2S to enter the Thermal Oxidizer. 3. Malfunction of the temperature control system or control valve. 4. Sulfur fire from accumulation of liquid sulfur in the bottom of the Thermal Oxidizer.
Tailgas Thermal Oxidation
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Issued 30 August 2011
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
S/D Actuation Device
Possible Causes
Thermal Oxidizer Waste Heat Boiler Superheated Steam High-High Temperature
1. Low steam flow through the superheater pass. 2. Malfunction of the interstage temperature control system or the desuperheating system. 3. Malfunction of the discharge temperature control system or the desuperheating system.
Thermal Oxidizer Waste Heat Boiler Low-Low Level
1. Loss of make-up water supply pressure. 2. Make-up water line plugged, or manual block valve closed or pinched. 3. Malfunction of the level control system. 4. Manual blowdown valve left open.
Thermal Oxidizer Vent Stack High-High Temperature
1. High temperature in the Thermal Oxidizer. 2. Sulfur fire from accumulation of liquid sulfur in the bottom of the stack or the Thermal Oxidizer Waste Heat Boiler casing. 3. Loss of water level in the Thermal Oxidizer Waste Heat Boiler which was not detected by the low-low level S/D. 4. Fouling of the tubes in the Thermal Oxidizer Waste Heat Boiler.
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Operating Guidelines Fall 2011
12.9.5
Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK
Effects of Shutdowns and Outages in Other Systems The Tailgas Thermal Oxidation system is directly or indirectly affected by shutdowns and/or outages in four other systems in the complex. These effects are described below.
12.9.5.1
ATU / ARU Outages Acid gas flow from the ARU can be interrupted for a variety of reasons. When these events occur, the acid gas flow will not cease immediately. If processing in the ARU is restarted within the time frame of the system residence time, the ARU acid gas flow to the SRUs will probably dip, but should not stop completely. If the interruption in an ARU is long enough, though, the ARU acid gas flow can fall far enough to cause the acid gas flame in the SRUs to become unstable, at which point the SRU ESDs will be activated by "flame failure". Section 12.9.5.3 below describes the effect of this on the TTO.
12.9.5.2
Sour Water Stripper Outages SWS gas flow from the Sour Water Stripper can also be interrupted for a variety of reasons. However, since the loss of SWS gas flow to the SRUs generally has minimal impact, outages in this system are usually of little consequence to the SRUs or to the TTO.
12.9.5.3
SRU ESD System The SRU ESD system stops the flow of acid gas to the SRU. As a result, the tailgas flow from the SRU ceases almost immediately. However, the Thermal Oxidizer will continue to operate, with the temperature control on the Thermal Oxidizer cutting back the flow of fuel gas to the Thermal Oxidizer Burner to the amount needed to heat its combustion air (plus the sweep air from the Sulfur Surge Tank and the spent degassing air) to the operating temperature of the Thermal Oxidizer. The Thermal Oxidizer can run in this mode indefinitely. When acid gas flow resumes to the SRU(s), SRU tailgas and/or TGCU effluent will begin to flow once again to the Thermal Oxidizer. The temperature control will automatically increase the fuel gas flow
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Samsung Total Petrochemicals Co., Ltd. Daesan, Korea SULFUR BLOCK as needed to increase the firing rate and continue oxidizing the gas streams feeding the TTO.
12.9.5.4
TGCU ESD System When the TGCU ESD system is activated, the warmup/bypass valve in the TGCU opens immediately to divert the SRU tailgas streams to the TTO. At the same time, the PLC opens the Tailgas Valve to the TTO, proves the valve open, then closes the Tailgas Valve to the TGCU. Once this switch is complete, the SRU tailgas streams are blocked off from the TGCU and flow directly to the Thermal Oxidizer. When the TGCU warmup/bypass valve first opens, the pressure drop through the TGCU will no longer be imposing back-pressure on the SRUs. Depending on the magnitude of this change in back-pressure (which is mainly determined by the unit throughput), there may be a temporary "bobble" in the feed and air flow rates to the SRUs. Although this will probably cause brief deviations from the proper air:acid gas ratio in the SRUs, the "bobble" should not be large enough to cause a "flame failure" shutdown in the SRUs. If so, the SRUs will remain on-line with their tailgas flowing to the TTO.
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Tailgas Thermal Oxidation
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