RFCC

Vendor Document No. TPC-DQR-002-TRM-OPS-015

ARAMIS Development Ltd

Rev. A

Page 1 of 323

TRAINING MODULE

RESIDUE FLUID CATALYTIC CRACKER (RFCC) UNIT: 15

VIETNAM OIL AND GAS CORPORATION (PETROVIETNAM) DUNG QUAT REFINERY (DQR) PROJECT DUNG QUAT, VIETNAM

Requisition Number:

8474L-000-CFB-XXXX-0001

Purchase Order Number:

8474L-000-CS01-17061

Equipment / Item Tag:

Not Applicable

Equipment / Item Description:

Not Applicable

TPC Document Number:

8474L-015-A5016-0000-001-005

Document Class:

X

A

06-DEC-07

Rev

Date DD-MMM-YY

Stamp

Comment given in this document does not relieve vendor of his/her responsibility for the correct engineering design and fabrication. This equipment or product shall be made as per the codes, requisition, specification, project procedures, and international standards.

Issue for review

Benoit Rabaud

Paul Walsh

JB Guillemin

Status

Written By (name & visa)

Check By (name & visa)

Approved By (name & visa)

Pages changed in this revision: Sections changed in last revision are identified by a vertical line in the margin DOCUMENT REVISIONS

TRAINING MODULE RESIDUE FLUID CATALYTIC CRACKER (RFCC)

DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

TRAINING MODULE


A 06/12/07 REV DATE TRAINING DURATION

Benoit Rabaud Paul Walsh PREPARED BY CHECKED BY VENUE

JB Guillemin APPROVED BY

ATTENDANCE ATTENDEES REQUIREMENTS MODULE OBJECTIVES

INSTRUCTORS NAME/POSITION SUMMARY/AGENDA

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IMPORTANT

THIS TRAINING MODULE HAS BEEN PREPARED BY ARAMIS FOR THE DUNG QUAT REFINERY. THIS MODULE MUST BE RECOGNIZED AS A TOOL AND GUIDE ONLY. IT WOULD BE IMPOSSIBLE TO ANTICIPATE AND PRESENT ALL POTENTIAL VARIABLES AND PROCESS CONDITIONS THAT OPERATIONAL PERSONNEL MIGHT BE EXPOSED TO. IT IS IMPERATIVE THAT THE READER ALWAYS AS CERTAIN THAT REFERENCE MATERIALS UTILIZED, WHILE PERFORMING OPERATIONAL DUTIES, CONFORM AT A MINIMUM TO THE LATEST ISSUE OF STANDARD OPERATING PROCEDURES, SAFETY CODES, ENGINEERING STANDARDS, AND GOVERNMENT REGULATIONS. SOME DESIGN FIGURES MIGHT NOT BE IN LINE DURING THE START-UP OF THE REFINERY.

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TABLE OF CONTENT SECTION 1 : GENERAL description ........................................................................................... 14 1.1.

Purpose of the Unit ................................................................................................ 17

1.2.

Basis of Design ...................................................................................................... 24 1.2.1. Duty of Plant ............................................................................................... 24 1.2.2. Feed Characteristics ................................................................................... 25 1.2.2.1. Atmospheric Residue Properties................................................... 25 1.2.2.2. CDU Stabilizer Off Gas ................................................................. 25 1.2.2.3. NHT Stripper off gas to RFCC....................................................... 26 1.2.2.4. CDU LPG Rich Stream.................................................................. 27 1.2.2.5. Slops feed to RFCC ...................................................................... 27 1.2.3. Product Specifications ................................................................................ 27 1.2.3.1. Distillation Specifications............................................................... 27 1.2.3.2. Gas Recovery Targets .................................................................. 28 1.2.3.3. Flue Gas Specifications................................................................. 28 1.2.3.4. Fuel Gas Specification .................................................................. 28 1.2.3.5. Decant Oil Specification (after Slurry Separation) ........................ 28 1.2.3.6. Estimated Product Properties........................................................ 29 1.2.3.7. LPG Composition .......................................................................... 32 1.2.4. Utility/Power/Chemicals/Catalyst consumption .......................................... 33 1.2.4.1. Utility Consumption ....................................................................... 33 1.2.4.2. Catalysts & Chemicals .................................................................. 43

1.3.

Glossary of terms and Acronyms........................................................................... 47 1.3.1. Acronyms .................................................................................................... 47 1.3.2. Glossary ...................................................................................................... 50

SECTION 2 : Process Flow Description ...................................................................................... 52 2.1.

Feed Section .......................................................................................................... 52

2.2.

Reaction Section .................................................................................................... 53 2.2.1. Feed Injection Zone .................................................................................... 53 2.2.2. Riser/Reactor .............................................................................................. 54 2.2.3. Stripper........................................................................................................ 55 2.2.4. Spent Catalyst Transfer .............................................................................. 56

2.3.

Catalyst Regeneration Section .............................................................................. 56 2.3.1. Air blower and air heaters........................................................................... 57

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2.3.2. First stage regenerator ............................................................................... 57 2.3.3. Second stage regenerator .......................................................................... 58 2.3.4. Combustion Air Rings ................................................................................. 59 2.3.5. Regenerated catalyst transfer..................................................................... 59 2.3.6. Catalyst handling ........................................................................................ 59 2.4.

Flue gas treatment ................................................................................................. 61 2.4.1. Phosphate injection .................................................................................... 65

2.5.

Fractionation Section ............................................................................................. 66 2.5.1. Fractionator bottom section ........................................................................ 66 2.5.2. HCO section................................................................................................ 67 2.5.3. LCO section ................................................................................................ 68 2.5.4. MTC and heavy naphtha section ................................................................ 69 2.5.5. Top section ................................................................................................. 70 2.5.6. Fractionator overhead section .................................................................... 70

2.6.

Gas Recovery section ............................................................................................ 71 2.6.1. Wet gas compressor and HP condenser.................................................... 71 2.6.2. Stripper condenser and high pressure separator drum.............................. 71 2.6.3. Primary absorber T-1551............................................................................ 72 2.6.4. Stripper........................................................................................................ 72 2.6.5. Secondary absorber T-1553 ....................................................................... 73 2.6.6. Fuel gas absorber ....................................................................................... 73 2.6.7. Debutanizer................................................................................................. 74 2.6.8. LPG amine absorber T-1556 ...................................................................... 75

SECTION 3 : Process control ...................................................................................................... 77 3.1.

Control narrative & operating parameters.............................................................. 77 3.1.1. Feed Oil Temperature Control .................................................................... 77 3.1.2. UC-001 Feed Injector ................................................................................. 79 3.1.3. UC-028 MTC INJECTOR............................................................................ 81 3.1.4. Riser Outlet Temperature Control .............................................................. 83 3.1.5. Catalyst Stripper Level Control ................................................................... 86 3.1.6. Catalyst Regenerators Level Control.......................................................... 87 3.1.7. Catalyst Regenerators Pressure Control.................................................... 89 3.1.8. Disengager Pressure Control ..................................................................... 91 3.1.9. Catalyst Regeneration Air and Total Flue gas to Stack Control................. 91 3.1.10. Catalyst Draw-Off Control ......................................................................... 94 3.1.11. Slurry Pumparound Return Control........................................................... 96 Page 5 of 323


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3.1.12. Feed Pumps Automatic Start-up............................................................... 98 3.1.13. UY-405, Slurry Pumparound (PA) Return Control .................................... 98 3.1.14. UC-414, E-1505 Slurry PA flow balance control..................................... 100 3.1.15. UC-413, E-1503 Slurry PA flow balance control..................................... 102 3.1.16. Steam Generation 3 Elements Control ................................................... 104 3.1.17. Split Range Control of Surge Drum ........................................................ 105 3.1.18. Main Fractionator Pressure Control ........................................................ 107 3.1.19. HCO Pumparound Heat Removal Control.............................................. 107 3.1.20. HCO Recycle and HCO Recycle MP steam generator E-1508.............. 108 3.1.21. HCO LP Steam Generator E-1510 Controls........................................... 108 3.1.22. HCO Flushing Oil Pumps Auto-start Control .......................................... 109 3.1.23. LCO and Heavy Naphta Pumparound Heat Removal Control ............... 111 3.1.24. Heavy Naphta Product Draw-Off and T-1501 Overheads Temperature Control 111 3.1.25. Water Draw Off and Recirculation .......................................................... 112 3.1.26. Wet Gas Compressor Control................................................................. 112 3.1.27. First Stage KO Drum D-1551 Level Control ........................................... 112 3.1.28. Stripper.................................................................................................... 113 3.1.29. Debutanizer ............................................................................................. 114 3.1.30. LPG Amine Absorber .............................................................................. 114 3.1.31. Control Narrative for the Slurry Separator Package X-1504 .................. 114 3.1.32. Tempered Water for E-1507 A-D ............................................................ 116 3.1.33. Amine Closed Drain Recovery Drum Pump P-1564............................... 117 3.1.34. RFCC lift station No.1 & No.2 Pits Pumps Control ................................. 118 3.1.35. Inter-Unit Controls & Interfaces............................................................... 118 3.1.35.1. RFCC Feed Control ................................................................... 118 3.1.35.2. Temperature of Lean Amine from the ARU............................... 120 3.1.36. Operating Parameters............................................................................. 122 3.2.

Instrument List...................................................................................................... 122

3.3.

Main Equipment ................................................................................................... 123 3.3.1. Reactor Riser, Stripper, Disengager and Catalyst Stand Pipe................. 123 3.3.1.1. Riser Outlet Separation System .................................................. 126 3.3.1.2. Catalyst Stripper .......................................................................... 129 3.3.2. 1st Stage Regenerator D-1502.................................................................. 131 3.3.3. 2nd Stage Regenerator D-1503................................................................. 133 3.3.4. Aeration and Fluidization Systems ........................................................... 137 Page 6 of 323


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3.3.5. Special Valves .......................................................................................... 138 3.3.6. Air Heaters ................................................................................................ 142 3.3.7. CO Boiler / Waste Heat Boiler Package H-1503 ...................................... 144 3.3.8. Electrostatic Precipitator X-1507 .............................................................. 151 3.3.9. Main Fractionator ...................................................................................... 153 3.3.10. Stripper T-1552 & Primary Absorber T-1551 .......................................... 155 3.3.11. Debutanizer T-1554 ................................................................................ 159 3.3.12. LPG Amine Absorber .............................................................................. 161 3.3.13. Secondary Absorber T-1553................................................................... 163 3.3.14. Fuel Gas Absorber T-1555...................................................................... 165 3.3.15. Slurry Separator ...................................................................................... 167 3.3.16. Air Blower, C-1501 .................................................................................. 168 3.3.17. Wet Gas Compressor C-1551................................................................. 171 SECTION 4 : Safeguarding devices .......................................................................................... 175 4.1.

Alarms and Trips .................................................................................................. 175

4.2.

Safeguarding Description..................................................................................... 175 4.2.1. Logic UX-001 – Reaction Stop ................................................................. 175 4.2.2. Logic UX-002: Catalyst Circulation Stops................................................. 178 4.2.3. Logic UX-003: First Regenerator Air Heater Trip ..................................... 179 4.2.4. Logic UX-004: Second Regenerator Air Heater Trip ................................ 180 4.2.5. Logic UX-005: Air Blower Protection ........................................................ 181 4.2.6. Logic UX-008: COB/WHB 1st Regenerator Flue Gas Bypass Operation . 182 4.2.7. Logic UX-009: Steam Drum D-1512 overfilling protection ....................... 183 4.2.8. Logic UX-010: COB/WHB 2nd Regenerator Flue Gas Bypass Operation 184 4.2.9. Logic UX-013: Economizer Bypass Cooling............................................. 185 4.2.10. Logic UX-421: Feed Surge Drum D-1513 overfilling protection ............. 186 4.2.11. Logic UX-422: Feed Pumps P-1501 A/B Protection ............................... 186 4.2.12. Logic UX-423: T-1501 & P-1507 A/B inventory isolation........................ 187 4.2.13. Logic UX-424: T-1501 & P-1508 A/B inventory isolation........................ 188 4.2.14. Logic UX-425: Slurry pumps P-1519 A/B/C protection........................... 189 4.2.15. Logic UX-426: T-1501 & P-1519 inventory isolation............................... 190 4.2.16. Logic UX-427: T-1504 & P-1509 A/B inventory isolation........................ 192 4.2.17. Logic UX-428: Heavy Naphta Product Pumps P-1515 A/B protection ... 194 4.2.18. Logic UX-429: LCO Stripper Pumps P-1511 A/B protection .................. 194 4.2.19. Logic UX-430: D-1514, P-1516 A/B & P-1518 A/B inventory isolation... 195 4.2.20. Logic UX-431: D-1524, P-1517 A/B inventory isolation.......................... 196 Page 7 of 323


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4.2.21. Logic UX-432: D-1515 overfilling protection ........................................... 197 4.2.22. Logic UX-433: Slurry Product Pumps P-1504 A/B protection................. 198 4.2.23. Logic UX-434: Backflush Oil Recycle Pumps P-1506 A/B protection .... 198 4.2.24. Logic UX-435: D-1517 overfilling protection ........................................... 198 4.2.25. Logic UX-436: Backflush Oil Pumps P-1505 A/B protection .................. 199 4.2.26. Logic UX-437: D-1516 overfilling protection ........................................... 199 4.2.27. Logic UX-438: HCO Flushing Oil Pumps P-1521 A/B protection ........... 200 4.2.28. Logic UX-439: LCO Flushing Oil Pumps P-1522 A/B protection ............ 201 4.2.29. Logic UX-440: D-1522 overfilling protection ........................................... 201 4.2.30. Logic UX-441: Light Slops Pumps P-1526 A/B protection...................... 201 4.2.31. Logic UX-442: D-1523 overfilling protection ........................................... 202 4.2.32. Logic UX-443: Heavy Slops Pumps P-1527 A/B protection ................... 202 4.2.33. Logic UX-444: Tempered Water Pumps P-1528 A/B Protection ............ 203 4.2.34. Logic UX-705: C-1551 Isolation and Protection...................................... 203 4.2.35. Logic UX-706: Interstage drum pump P-1551 A/B Protection ................ 204 4.2.36. Logic UX-707: HP separator drum D-1553 Interface Isolation ............... 205 4.2.37. Logic UX-708: HP separator drum D-1553 Inventory Isolation .............. 205 4.2.38. Logic UX-709: Lean Oil Coalescer Interface Isolation............................ 206 4.2.39. Logic UX-710: T-1555 Interface Isolation ............................................... 207 4.2.40. Logic UX-712: Debutanizer T-1554 Inventory Isolation .......................... 207 4.2.41. Logic UX-713: D-1554 Interface Isolation............................................... 208 4.2.42. Logic UX-714: Debutanizer Reflux Drum D-1554 Inventory Isolation .... 209 4.2.43. Logic UX-715: T-1556 Interface Isolation ............................................... 210 4.2.44. Logic UX-716: LPG amine coalescer D-1555 Interface Isolation ........... 210 4.2.45. Logic UX-717: LPG amine absorber T-1556 depressurization............... 211 4.2.46. Logic UX-718: Fuel Gas Absorber Outlet KO Drum D-1559 Interface Isolation ................................................................................................................ 211 4.2.47. Logic UX-719: D-1553 depressurization ................................................. 212 4.2.48. Logic UX-861 Wet Gas Compressor C-1551 Protection ........................ 212 4.3.

Safeguarding Equipment ..................................................................................... 214 4.3.1. Pressure Safety Devices .......................................................................... 214

SECTION 5 : Fire & Gas Systems............................................................................................. 225 5.1.

Fire & Gas detection ............................................................................................ 225

5.2.

Fire Protection...................................................................................................... 225

SECTION 6 : Quality control...................................................................................................... 227 6.1.

Sampling Analysis................................................................................................ 227 Page 8 of 323


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6.1.1. Feed Oil .................................................................................................... 227 6.1.2. Catalyst ..................................................................................................... 227 6.1.3. Light Cycle Oil........................................................................................... 228 6.1.4. Heavy Cycle Oil ........................................................................................ 228 6.1.5. Clarified Oil ............................................................................................... 228 6.1.6. Slurry......................................................................................................... 229 6.1.7. Absorber Gas............................................................................................ 229 6.1.8. Heavy Naphta ........................................................................................... 229 6.1.9. LPG ........................................................................................................... 229 6.1.10. Sour Water .............................................................................................. 230 6.1.11. Sampling Connections ............................................................................ 230 6.2.

On-line analyzers ................................................................................................. 233

SECTION 7 : Causes and effect................................................................................................ 237 7.1.

Cause & Effect Matrix: ......................................................................................... 237 7.1.1. Example from Cause and Effect Chart ..................................................... 237 7.1.1.1. Sheet 18: UX-426: T-1501 & P-1519 inventory isolation ............ 237

SECTION 8 : Operating practices.............................................................................................. 243 8.1.

Normal Operation................................................................................................. 243 8.1.1. Operating conditions................................................................................. 243 8.1.2. Operating Parameters .............................................................................. 271

8.2.

Start-up Procedure............................................................................................... 271 8.2.1. Pre-commissioning Activities .................................................................... 272 8.2.2. Initial Start-up............................................................................................ 272 8.2.2.1. Status of the Unit prior to first start-up ........................................ 272 8.2.2.2. Chronology of first Start-up ......................................................... 273 8.2.3. Initial & Normal Start-Up ........................................................................... 274 8.2.3.1. Start-up summary of the Reaction Section ................................. 274 8.2.3.2. Start-up summary of the Fractionation & Gas Recovery Sections 279

8.3.

Shutdown Procedures.......................................................................................... 284 8.3.1. Normal Shutdown ..................................................................................... 284 8.3.1.1. Normal Shutdown Summary of Reactor & Regenerator............. 284 8.3.1.2. Normal Shutdown Summary of Fractionation and Gas Recovery Section 288

8.4.

Emergency Shutdown .......................................................................................... 290 8.4.1. General emergency shutdown.................................................................. 290 Page 9 of 323


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8.4.2. Power failure ............................................................................................. 290 8.4.3. Instrument air failure ................................................................................. 291 8.4.4. Fluidization / Aeration / Purge Air and FG failure ..................................... 292 8.4.5. Steam failure............................................................................................. 293 8.4.6. Boiler feed water failure ............................................................................ 294 8.4.7. Cooling water failure ................................................................................. 295 8.4.8. Sea water failure ....................................................................................... 295 8.4.9. Air blower failure ....................................................................................... 295 8.4.10. Feed pump failure ................................................................................... 297 8.4.11. Other pump failure .................................................................................. 297 8.4.12. Fuel gas failure........................................................................................ 297 8.4.13. Wet gas compressor failure .................................................................... 298 8.4.14. Catalyst slide valve / plug valve failure ................................................... 299 8.4.15. Loss of regenerators pressure control (flue gas slide valve failure) ....... 299 8.4.16. Control system failure ............................................................................. 300 8.4.17. Oil reversal .............................................................................................. 300 8.4.18. Low riser outlet temperature (ROT) ........................................................ 300 8.4.19. Plugged catalyst circulation .................................................................... 301 8.4.20. Downstream unit failure .......................................................................... 301 8.4.21. Fire emergency ....................................................................................... 301 8.4.22. Emergency shutdown of Fractionator and Gas Recovery Section - General 302 8.4.23. Steam failure for the Fractionation/Gas Recovery Section..................... 302 8.4.24. Instrument air failure for the Fractionation/Gas Recovery Section......... 302 8.4.25. Boiler feed water failure for the Fractionation/Gas Recovery Section.... 303 8.4.26. Fuel gas failure for the Fractionation/Gas Recovery Section ................. 303 8.4.27. Electrical power failure for the Fractionation/Gas Recovery Section ..... 303 8.4.28. Cooling water failure for the Fractionation/Gas Recovery Section......... 304 8.4.29. Sea water failure for the Fractionation/Gas Recovery Section............... 304 8.4.30. Wet gas compressor failure for the Fractionation/Gas Recovery Section 304 SECTION 9 : HSE...................................................................................................................... 306 9.1.

Hazardous Areas ................................................................................................. 306

9.2.

Safety Equipment................................................................................................. 306

9.3.

Specific PPE ........................................................................................................ 306 9.3.1. Catalyst ..................................................................................................... 306 Page 10 of 323


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9.3.2. Flue gas .................................................................................................... 307 9.3.2.1. Carbon Monoxide ........................................................................ 307 9.3.3. H2S ........................................................................................................... 307 9.3.4. Nickel passivator – NALCO NICKEL PASSIVATION PLUS EC9192 ...... 308 9.3.5. Corrosion Inhibitor - CHIMEC 1430.......................................................... 308 9.3.6. Antifoam CHIMEC 8045 ........................................................................... 309 9.3.7. Phosphate NALCO 7208 .......................................................................... 309 9.4.

Chemical Hazards................................................................................................ 309 9.4.1. Hazardous Properties of Catalyst............................................................. 310 9.4.2. Flue gas .................................................................................................... 310 9.4.2.1. Hazardous properties of carbon monoxide (CO) ........................ 310 9.4.3. Hazardous Properties of Cracked hydrocarbons ..................................... 311 9.4.4. Hazardous Properties of Hydrogen Sulfide Toxicity................................. 311 9.4.4.1. Acute Hydrogen Sulfide Poisoning.............................................. 312 9.4.4.2. Subacute Hydrogen sulfide Poisoning ........................................ 313 9.4.5. Hazardous Properties of NALCO NICKEL PASSIVATION PLUS EC9192 313 9.4.6. Hazardous Properties of Corrosion Inhibitor - CHIMEC 1430.................. 314 9.4.7. Hazardous Properties of Antifoam CHIMEC 8045 ................................... 314 9.4.8. Hazardous Properties of Phosphate NALCO 7208 .................................. 315

SECTION 10 : Reference documents index.............................................................................. 317 10.1. Operating Manual/ Licensor Documentation ....................................................... 317 10.2. Arrangement Drawings, Layouts and Plot Plans ................................................. 317 10.3. Process Flow Diagrams ....................................................................................... 317 10.4. Piping and Instrumentation Diagrams.................................................................. 317 10.5. Equipment list....................................................................................................... 320 10.6. Main Equipment Data Sheet ................................................................................ 320 10.7. Instrument List...................................................................................................... 321 10.8. Cause & Effect Matrix .......................................................................................... 321 10.9. Safety Logic diagram ........................................................................................... 321 10.10.

Fire & Gas Cause & Effect Chart .............................................................. 321

10.11.

Fire & Gas Detectors Layout..................................................................... 321

10.12.

Fire Protection Layout ............................................................................... 321

10.13.

Hazardous Area Classification.................................................................. 322

10.14.

MSDS ........................................................................................................ 322

10.15.

Vendors Documentation............................................................................ 322 Page 11 of 323


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TRAINING MODULE


Course Content: Section 1 - General Description

X

Section 2 - Process Flow Description Section 3 - Process Control Section 4 - Safeguarding Devices Section 5 - Fire & Gas Systems Section 6 - Quality Control Section 7 - Cause & Effects Section 8 - Operating Procedures Section 9 - HSE Section 10 - Reference Document Index

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SECTION 1 : GENERAL DESCRIPTION The Residue Fluid Catalytic Cracking (RFCC) converts various residues from CDU to lower boiling, high value products: Naphtha sent to NTU (unit 17), Light Cycle Oil sent to LCO HDT (unit 24) and intermediate storage and LPG sent to the LTU (unit 16). As by-products of the reaction, fuel gas, slurry oil, and coke are also generated in the reactorriser. The resulting Decanted Cycle Oil from these by-products will then be incorporated in the Fuel oil Blend. The majority of the RFCC reaction section equipment handles catalyst / vapour product separation and removal of the coke from the catalyst, while only a small portion of the system is directly used for the cracking reaction. The RFCC is also provided with a Fractionation Section to distillate the vapour product from the reaction section, as well as a Gas recovery Section which process the overhead of the Fractionation Section

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Figure 1: 2D Refinery Plot Plan Page 15 of 323


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Figure 2: 3D Refinery Plot Plan Page 16 of 323


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1.1. Purpose of the Unit The purpose of the Residue Fluid Catalytic Cracker (RFCC) R2R process is to convert various reduced crudes to lower boiling, high value products, primarily C3-C4 LPG, gasoline and light cycle oil. This is achieved using vapour phase chemical reactions in the presence of specialized FCC cracking catalyst during which the long molecular chain of the reduced crude is cracked into shorter chain molecules. Heat for the cracking process is supplied by the hot regenerated catalyst which vaporizes the finely atomized oil feed and sets the stage for the rapid and selective cracking process. The vaporization and cracking reactions occur in the reactor riser in about 2 seconds. As by-product of the reaction, fuel gas, slurry oil, and coke are also generated in the reactor riser. The RFCC has been designed by AXENS to offer maximum flexibility. The reaction section of this unit particularly includes a 2-stage catalyst regeneration system, a unique feed injection system, mixed temperature control, an efficient riser termination system and effective air/steam distribution devices. The Fractionation section of the RFCC fractionates the vapour product from the reaction section into clarified oil, LOC and heavy naphta. The fractionator overhead vapour and liquid streams are further processed in the Gas Recovery section, which produces light gasoline, amine treated fuel gas and amine treated LPG. For the Maximum Gasoline Operation, the heavy naphta is combined with the light gasoline from the Gas Recovery Section. For the maximum Distillate Operation, the heavy naphta combined with LCO products.

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Figure 3: Refinery Plot Plan Page 18 of 323


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North East View Page 20 of 323


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North West View Page 21 of 323


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South East Page 22 of 323


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South West Figure 4: RFCC 3D Drawings Page 23 of 323


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1.2. Basis of Design 1.2.1. Duty of Plant The Residue Fluid Catalytic Cracking (RFCC) is designed for 2 atmospheric residues from Bach Ho and Bach Ho/Dubai crudes mixture: •

The RFCC design capacity is 3,256,000 tones per annum of Bach Ho 370+°C crude distillation residue (from unit 11), which is equivalent to a volumetric flowrate of 69,700 BPSD, based on the RFCC operation of 8 000 hours operation per year.

•

The RFCC is also designed to process a residue based on the CDU (from unit 11) processing a sour crude blend in the ratio of 1.0 million tones of Dubai crude to 5.5 million tones of Bach Ho crude. The sour residue blend capacity is also 3,256,000 tones per annum, which is equivalent to a volumetric flowrate of 69,700 BPSD, based on 8 000 hours operation per year.

The RFCC is also designed to process both the Bach Ho and sour crude mix residues in2 modes of operation: •

Maximize RFCC Naphtha (Max Gasoline)

•

Maximize LCO (Max Distillate)

NOTE: The product guarantees are based on RFCC operating in the maximum distillate mode of operation. The RFCC is designed to process 100% hot feed direct from the Crude Distillation Unit and is capable of processing up to 100% cold feed from storage. In addition to the above, the RFCC Gas Plant can process the following streams: •

CDU Stabilizer Off-gas

•

CDU LPG rich stream

The RFCC shall also treat the off-gas stream from the Naphtha hydrotreater (NHT).

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1.2.2. Feed Characteristics 1.2.2.1. Atmospheric Residue Properties Crude (Sour) Blend

100% (Sweet) Bach Ho

Cut Range, TPB (°C)

370+

370+

Vol% on Crude

46.6

47.3

Wt% on Crude

50.0

50.1

API Gravity

2695

28.9

Specific Gravity at 15/4°C

0.893

0.882

Nitrogen (wt ppm)

1800

1300

Sulphur (wt%)

0.55

0.05

D-1266

Conradson Carbon (wt%)

2.66

1.57

D189

Vanadium (wt ppm)

10.5

0

D2787

5

1

Sodium (wt ppm)

1.6

1.6

D2788

Viscosity at 50°C (cSt)

43.4

43.4

D445


8.8

9

Pour Point (°C)

50

52

D97

Asphaltenes (wt%)

2.0

1.0

D128

Wax Content (wt%)

N/A

41

Hydrogen (wt%)

12.7

12.84

D1018

Neutralization No. (mg KOH/gm)

0.05

0.05

D3242

Characterization “K” Factor

12.58

12.78

IBP

263

262

10%

379

379

30%

435

437

50%

475

480

Vol% above 550°C

32.4

32.5

Property

Nickel (wt ppm)

ASTM Test Method

ASTM Distillation (°C) D-1160 at 760 mmHg

1.2.2.2. CDU Stabilizer Off Gas The following gas stream is fed from the CDU Stabilizer, directly to the suction of the wet-gas compressor in the RFCC Gas Plant: Page 25 of 323


Property

DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Crude (Sour) Blend [1]


339.0

291.0

N2 (mol%)

-

-

H2S (mol%)

-

-

C1 (mol%)

-

0.7

C2 (mol%)

6.3

4.8

C3 (mol%)

37.0

22.7

iC4 (mol%)

14.3

16.0

nC4 (mol%)

40.6

53.5

iC5 (mol%)

0.4

0.4

nC5 (mol%)

-

-

C6+ (mol%)

-

-

H2O (mol%)

1.4

1.9

Total (mol%)

100.0

100.0

Molecular Weight

50.6

52.6

Flowrate (kg/hr) Composition

Note: [1]: Sour Crude Blend data based on 100% Dubai Crude.

1.2.2.3. NHT Stripper off gas to RFCC Component

Content

H2O (kg mol/h)

0.13

H2S (kg mol/h)

0.32

NH3 (kg mol/h)

Trace

H2 (kg mol/h)

13.17

C1 (kg mol/h)

1.69

C2 (kg mol/h)

1.37

C3 (kg mol/h)

0.83

iC4 (kg mol/h)

0.06

nC4 (kg mol/h)

0.40

IC5 (kg mol/h)

0.10

C6+ (kg mol/h)

0.63

Total (kg mol/h)

18.84

Total (kg/h)

243 Page 26 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

1.2.2.4. CDU LPG Rich Stream Property

Crude (Sour) Blend [1]


Flowrate (kg/hr)

6206

2071

Specific Gravity at 15°C

0.565

0.572

-

-

1.2

0.8

Propene (mol%)

-

-

Propane (mol%)

19.3

10.7

-

-

iC4 (mol%)

16.5

16.1

nC4 (mol%)

61.7

71.0

iC5+ (mol%)

1.3

1.4

Total (mol%)

100.0

100.0

Composition Ethylene (mol%) Ethane (mol%)

Butene (mol%)

1.2.2.5. Slops feed to RFCC Provision is made to allow the re-running of slops through the RFCC main fractionator. Heavy slops:

5000 BPSD

Light slops:

5000 BPSD

1.2.3. Product Specifications 1.2.3.1. Distillation Specifications Product Gasoline LCO Slurry

Property

Max. Gasoline

Max. Distillate

TBP cut points

C5 - 205°C

C5 - 165°C

RVP (kPa) TBP cut point

60 max. 205 – 360°C

Flash Point TBP cut point Flash Point

165 – 390°C 65°C min.

360+°C

390+°C 100°C min.

Page 27 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

1.2.3.2. Gas Recovery Targets Component

Value

C3 overall recovery

95% min.

C4 overall recovery

96% min.

C5+ content in LPG

0.7% wt max.

H2S content in LPG

25 ppm wt max.

1.2.3.3. Flue Gas Specifications The following describes the flue gas properties downstream of the electrostatic precipitator and the DeSOx unit: Component

Value

NOx

1000 mg/Nm3 max

SOx

500 mg/Nm3 max

Catalyst fines

50m/Nm3 max

CO content

300 mg/Nm3 max

NOTE: DeSOx unit will be provided in the future. Indeed, the unit will be initially operated with Bach Ho Crude only, thus producing SO2 content smaller than 500 mg/Nm3.

1.2.3.4. Fuel Gas Specification H2S content: 50 wt ppm MAX.

1.2.3.5. Decant Oil Specification (after Slurry Separation) Catalyst content: 100 wt ppm MAX.

Page 28 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

1.2.3.6. Estimated Product Properties Mixed MG

Bach Ho MG

Mixed MD

Bach Ho MD

LPG Specific Gravity 15/15

0.565

0.566

.565

0.565

Mercaptans (wt ppm)

78

7.1

78

1.7

COS (wt ppm)

5.0

5.0

5.0

5.0

Total Sulphur (wt ppm)

3786

332

4260

383

Butadiene (wt ppm)

3012

1647

1358

1063

Sulphur (wt ppm)

230

10

RON clear

92.0

91.7

MON clear

79.5

79.2

True Vapour Pressure (g/cm2)

498

531

Reid Vapour Pressure (kPa)

48

51

Specific Gravity (15/15)

00.719

0.715

IBP

35

34

5

43

42

10

47

46

30

60

58

50

72

70

70

1

89

90

129

129

95

144

143

EBP

159

156

43

45

Gasoline (C5 – 165°C)

D-86

Olefins (wt %) Gasoline (C5 – 205°C) Sulphur (wt ppm)

340

10

RON clear

92.1

91.8

79.9

79.6

True Vapour Pressure (g/cm )

337

363

Reid Vapour Pressure (kPa)

32

34

Specific Gravity (15/15)

0.736

0.732

MON clear 2

Page 29 of 323


Mixed MG

DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Bach Ho MG

Mixed MD

Bach Ho MD

D-86 IBP

39

39

5

50

49

10

55

54

30

71

70

50

90

87

70

116

113

90

160

159

95

176

175

EBP

197

197

34

35

Olefins (wt %) Light Cycle Oil (165 – 390°C) Sulphur (wt %)

0.45

0.04

Cetane Number

33.9

38.4

Cloud Point (°C)

-1.8

-0.9


1.02

1.02


2.05

2.04

Pour Point (°C)

-17.3

-18.9

Flash Point (°C)

67

67

Specific Gravity 15/15

0.881

0.864

IBP

189

189

5

203

204

10

212

212

30

239

239

50

263

264

70

291

292

90

333

334

95

349

350

EBP

373

374

D-86

Light Cycle Oil (205 – 360°C) Sulphur (wt %)

0.619

0.055

Cetane Number

24.4

28.1

Page 30 of 323


Mixed MG

DOC NO: 8474L-015-A5016-0000-001-005 REV: A

Bach Ho MG

Cloud Point (°C)

-6.1

-5.3


0.99

0.97


1.92

1.88

Pour Point (°C)

-12.8

-14.0

Flash Point (°C)

76

74

Specific Gravity 15/15

0.926

0.911

IBP

188

180

5

221

220

10

230

230

30

24

245

50

263

262

70

287

286

90

323

322

95

336

335

EBP

353

353

DATE: 06/12/07

Mixed MD

Bach Ho MD

D-86

Slurry (390+°C) Specific Gravity 15/15

0.994

0.960

Sulphur (wt %)

0.835

0.07

Conradson Carbon (wt %)

12.5

9.5


8.94

6.09


110

45

Pour Point (°C)

15-20

15-20

Slurry (390+°C) Specific Gravity 15/15

1.092

1.043

Sulphur (wt %)

1.03

0.10

Conradson Carbon (wt %)

15.7

12.7


14.5

11.1


160

140

Pour Point (°C)

15-20

15-20

Page 31 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

1.2.3.7. LPG Composition

Component

Mixed MG

Bach Ho MG

Mixed MD

Bach Ho MD

LPG Rate (kg/h)

LPG Rate (kg/h)

LPG Rate (kg/h)

LPG Rate (kg/h)

H2 S

1

1

1

2

H2

0

0

0

0

C1

0

0

0

0

C2

449

333

444

349

Ethylene

9

6

9

7

C3

6124

5179

6627

5793

Propylene

20251

14145

19626

14621

iC4

14681

11273

13689

10839

nC4

5801

4221

7858

6560

Isobutylene

6579

4679

6758

5170

1-Butene

6317

4706

5922

4653

Cis-2-Butene

6482

4751

5909

4592

Trans-2-Butene

9862

7245

8964

6975

Butadiene

106

50

184

64

20-50

541

399

540

424

TOTAL:

77203

56988

76530

60049

Component

LPG (kmol/h)

LPG (kmol/h)

LPG (kmol/h)

LPG (kmol/h)

H2 S

0.04

0.03

0.04

0.06

H2

0.00

0.00

0.00

0.00

C1

0.00

0.00

0.00

0.00

C2

14.94

11.07

14.77

11.62

Ethylene

0.31

0.21

0.32

0.24

C3

138.87

117.44

150.28

131.37

Propylene

481.23

336.14

466.37

347.44

iC4

252.58

193.94

235.51

186.49

nC4

99.81

72.63

135.20

112.86

Isobutylene

117.26

83.39

120.45

92.15

1-Butene

112.59

83.88

105.54

82.93

Page 32 of 323


Mixed MG

DOC NO: 8474L-015-A5016-0000-001-005 REV: A

Bach Ho MG

DATE: 06/12/07

Mixed MD

Bach Ho MD

Cis-2-Butene

115.53

84.68

105.32

81.84

Trans-2-Butene

175.76

129.12

159.76

124.31

Butadiene

1.96

0.93

3.41

1.18

20-50

8.07

6.10

8.00

6.47

TOTAL:

1518.96

1119.56

1504.96

1178.96

Mercaptans (wt ppm)

7

7

78

78

COS (wt ppm)

5

5

5

5

Temperature (°C)

40

40

40

40

Pressure (kg/cm2g)

18

18

18

18

Density (P; T)

530.2

530.1

529.8

529.8

Density (15°C)

563.3

563

562.8

562.7

Note: Dry Liquid.

1.2.4. Utility/Power/Chemicals/Catalyst consumption 1.2.4.1. Utility Consumption The following describes the utility consumption of the RFCC based on the Estimated Utility Consumption Documents: 8474L-015-CN-0003-511

Bach Ho – Max Gasoline – Normal case

8474L-015-CN-0003-512

Bach Ho – Max Distillate – Normal case

8474L-023-CN-0003-513

Mixed Crude – Max Gasoline – Normal case

8474L-023-CN-0003-514

Mixed Crude – Max Distillate – Normal case

8474L-015-CN-0003-521

Bach Ho – Max Gasoline – Design case

8474L-015-CN-0003-522

Bach Ho – Max Distillate – Design case

8474L-023-CN-0003-523

Mixed Crude – Max Gasoline – Design case

8474L-023-CN-0003-524

Mixed Crude – Max Distillate – Design case

Page 33 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Only the Bach Ho – Max Distillate – Normal case is described in the following. For the other cases, refer to the abovementioned documents. Note: In the following subsections: ( ): Intermittent Producer/Consumer +: Indicates Quantity Produced -: Indicates Quantity Consumed 1.2.4.1.1. Electrical Power Electric Power, kW Mech. Running Load

Elec. Oper. Load

-0.3

-0.3

1230

-683.0

-697.0

Air Blower

3

-3.0

-3.0

P-1529A

C-1501 Turbine Condensate Pump

55

-39.0

-43.3

P-1529B


55

(-39.0)

(-43.3)

-

C-1501 Lube oil Pump (Main)

37

-18.5

-20.6

-

Turbine Gear Motor

15

-15.0

-15.0

C-1551

Wet Gas Compressor

-1.5

-1.5

P-1559A


18.5

-13.9

-14.8

P-1559B


18.5

(-13.9)

(-14.8)

-

C-1551 Lube Oil Pump (Main)

30

-16.0

-17.8

P-1501A

Feed Pump

600

-476.0

-500.5

P-1501B

Feed Pump

600

(-476.0)

(-500.5)

P-1504A

Slurry Product Pump

55

-42.7

-45.1

P-1504B

Slurry Product Pump

55

(-42.7)

(-45.1)

P-1505A

Backflush Oil Pump

22

-15.0

-16.5

P-1505B

Backflush Oil Pump

22

(-15.0)

(-16.5)

P-1506A

Backflush Oil Recycle Pump

11

-7.4

-8.4

P-1506B

Backflush Oil Recycle Pump

11

(-7.4)

(-8.4)

P-1507A

HCO Recycle Pump

150

-128.0

-142.2

P-1508B

HCO Recycle Pump

150

(-128.0)

(-142.2)

P-1508A

HCO Pumparound Pump

220

-179.4

-188,4

P-1508B

HCO Pumparound Pump

220

(-179.4)

(-188.4)

Item No.

Description

H-1503

COB/WHB package

C-1502A

Forced Draft Air Fan

C-1501

Motor Load/ Rating

Page 34 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Electric Power, kW Motor Load/ Rating

Mech. Running Load

Elec. Oper. Load

HCO Product Pump

15

-9.1

-10.1

P-1509B

HCO Product Pump

15

(-9.1)

(-10.1)

P-1510A

LCO Pumparound Pump

335

-303.0

-316.0

P-1510B

LCO Pumparound Pump

335

(-303.0)

(-316.0)

P-1511A

LCO Stripper Pump

90

-73.4

-76.9

P-1511B

LCO Stripper Pump

90

(-73.4)

(-76.9)

P-1512A

MTC Recycle Pump

75

0.0

0.0

P-1512B

MTC Recycle Pump

75

(0.0)

(0.0)

P-1513A

Lean Oil Pump

75

-55.0

-58.1

P-1513B

Lean Oil Pump

75

(-55.0)

(-58.1)

P-1514A

Naphta Pumparound Pump

225

-203.0

-213.9

P-1514B

Naphta Pumparound Pump

225

(-203.0)

(-213.9)

P-1515A

Heavy Naphta Product Pump

55

-39.4

-41.6

P-1515B

Heavy Naphta Product Pump

55

(-39.4)

(-41.6)

P-1516A

Fractionator Reflux Pump

110

-96.0

-101.3

P-1516B

Fractionator Reflux Pump

110

(-96.0)

(-101.3)

P-1517A

Overhead Sour Water Pump

30

-25.5

-27.6

P-1517B

Overhead Sour Water Pump

30

(-25.5)

-(27.6)

P-1518A

Overhead Liquid Pump

250

-206.0

-228.9

P-1518B

Overhead Liquid Pump

250

(-206.0)

(-228.9)

P-1521B

HCO Flushing Oil Pump

110

(-80.9)

(-84.4)

P-1522A

LCO Flushing Oil Pump

30

-18.4

-19.9

P-1522B

LCO Flushing Oil Pump

30

(-18.4)

(-19.9)

P-1526A

Light Slops Pump

37

-16.1

-27.9

P-1526B

Light Slops Pump

37

(-16.1)

(-27.9)

P-1527A

Heavy Slops Pump

37

-27.9

-29.8

P-1527B

Heavy Slops Pump

37

(-27.9)

(-29.8)

P-1528A

Tempered Water Pump

15

-10.5

-11.7

P-1528B

Tempered Water Pump

15

(-10.5)

(-11.7)

P-1551A

Interstage Drum Pump

150

-134.0

-142.3

P-1551B

Interstage Drum Pump

150

(-134.0)

(-142.3)

Item No.

Description

P-1509A

Page 35 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Electric Power, kW Mech. Running Load

Elec. Oper. Load

4

-1.2

-1.4

KO Drum Liquid Pump

4

(-1.2)

(-1.4)

P-1553A

Stripper Feed Pump

132

-112.0

-117.9

P-1553B

Stripper Feed Pump

132

(-112.0)

(-117.9)

P-1554A

Gasoline Recycle Pump

55

-44.0

-47.7

P-1554B

Gasoline Recycle Pump

55

(-44.0)

(-47.7)

P-1556A

Debutanizer Overhead Pump

225

-185.0

-194.9

P-1556B

Debutanizer Overhead Pump

225

(-185.0)

(-194.9)

P-1560A

RFCC Closed Drain Pump

22

(-16.5)

(-18.1)

P-1560B

RFCC Closed Drain Pump

22

(-16.5)

(-18.1)

P-1561

RFCC Lift Station No.1 Sump Pump

7.5

(-4.9)

(-5.4)

P-1562

RFCC Lift Station No.2 Sump Pump

7.5

(-4.9)

(-5.4)

P-1563

Oily Water Lift Pump – Common Spare

7.5

(-4.9)

(-5.4)

P-1564

Amine Closed Drain Pump

15

(-10.8)

(-12.0)

E-1514

LCO Air Cooler

120

-97.6

-106.2

E-1517

Heavy Naphta Air Cooler

33

-20.4

-23.1

E-1519

Overhead Air Condenser

960

-736.0

-800.9

E-1521

Heavy Naphta Pumparound Air Cooler

120

-99.6

-108.4

E-1530

Tempered Water Air Cooler

22.5

-15.0

-17.8

E-1551

Wet Gas Compressor Intercooler

240

-190.4

-207.2

E-1553

HP Condenser

180

-134.4

-146.2

E-1558

Gasoline Air Cooler

120

-92.8

-101.0

X-1504

Slurry Separator

-230.0

-230.0

X-1505

Corrosion Inhibitor Injection Package

P-1520

Corrosion Inhibitor Pump

0.55

-0.40

-0.44

X-1507

Electrostatic Precipitator

491

-379.0

-379.0

Intermittent Users in X-1507

88

(-53)

(-53)

(-270.0)

(300.0)

Item No.

Description

P-1552A

KO Drum Liquid Pump

P-1552B

Motor Load/ Rating

X-1508

DeSOx Unit (Future)

X-1509

Metal Passivation Injection Package

P-1502A

Metal Passivation Pump

0.55

0.00

0.00

P-1502B

Metal Passivation Pump

0.55

(0.00)

(0.00) Page 36 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Electric Power, kW Mech. Running Load

Elec. Oper. Load

6.05

-4.36

-4.84

Anti-Foaming Pump

0.55

(-0.40)

(-0.44)

P-1558

Anti-Foaming Pump

0.55

(-0.40)

(-0.44)

EJ-1501

Catalyst Hoppers Steam Ejector

SV-1501

Regenerated Catalyst Slide Valve

4.0

-3.0

-3.3

SV-1502

Spent Catalyst Slide Valve

4.0

-3.0

-3.3

SV-1503

1st Regenerator Flue Gas Slide Valve

4.0

-3.0

-3.3

SV-1504

2nd Regenerator Flue Gas Slide Valve

4.0

-3.0

-3.3

PV-1501

Plug Valve

4.0

-3.0

-3.3

-

Oil Mist Generator

3.0

-3.0

-3.0

TOTAL(excluded Future DeSOx): 10066

-5225.9

-5526.7

TOTAL(included Future DeSOx): 10066

-5495.9

-5836.7

Item No.

Description

X-1510

Phosphate Injection Package

X-1551

Antifoam Injection Package

P-1557

Motor Load/ Rating

Page 37 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

1.2.4.1.2. Steam, Condensate & Boiler Feed Water Steam (T/h) Item No.

Description

HP STM

H-1503

COB/WHB Package (with Economizer)

219.3

C-1502B

Forced Draft Air Fan

(-21.0)

C-1502B Hot Standby

-1.7

MP STM

Condensate (T/h) LP STM

HP COND

MP COND

LP COND

BFW (T/h) COLD COND

0.7

HP BFW -225.5

LP BFW -0.7

Cold BFW

Losses (T/h) 6.2

(21.0)

E-1534

BFW Heater

-7.0

C-1501

Air Blower

-68.7

-

C-1501 Lube Oil Pump (Spare)

(-2.6)

C-1551

Wet Gas Compressor

-30.4

-

C-1551 Lube Oil Pump (Spare)

(-2.1)

D-1501

Disengager / Stripper

-

COB/WHB LP Blowdown Drum

0.5

-0.5

D-1527

LP Blowdown Drum

0.2

-0.2

T-1503

LCO Stripper

-3.0

3.0

T-1504

HCO Stripper

-0.5

0.5

P-1519A

Slurry Pumparound Pump

-10.3

10.3

P-1519B


-10.3

10.3

P-1519C


(-10.3)

(10.3)

P-1519C Hot Standby

-0.8

-0.3

7.0 -0.1

0.0

68.7

0.3

30.4

0.4

(2.6) -0.4 (2.1) -34.7

34.7

0.8 Page 38 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Steam (T/h)

Condensate (T/h)

BFW (T/h)

Item No.

Description

HP STM

P-121A

HCO Flushing Oil Pump

-3.7

E-1503

Slurry HP Steam Generator

0.0

0.0

E-1504

Slurry HP Steam Generator

18.0

-18.5

E-1505

Slurry MP Steam Generator

E-1506

Slurry LP Steam Generator

E-1508

HCO Recycle MP Steam Generator

E-1510

HCO LP Steam Generator

E-1513

LCO Product LP Steam Generator

E-1522

MP steam Feed Heater [1]

-6.5

E-1523

HCO Pumparound MP Steam Generator

7.3

E-1524

HP Steam Feed Heater [2] st

MP STM

LP STM

HP COND

MP COND

LP COND

COLD COND

HP BFW

LP BFW

Cold BFW

Losses (T/h)

3.7

13.8 1.3 6.5 2.9 8.6

-11.3

0.5 -14.2

0.4

-1.4

0.1

-6.7

0.2

-3.0

0.1

-8.9

0.3

-7.5

0.2

6.5

11.3

SPR1501

1 Regenerator Torch Oil Sprayer

(-0.3)

(0.3)

SPR1502

2nd Regenerator Torch Oil Sprayer

(-0.3)

(0.3)

SPR1503

Water Spray for D-1502 Flue Gas Bypass

(-1.5)

(-22.8)

(-24.3)

SPR1504

Water Spray for D-1503 Flue Gas Bypass

(-1.5)

(-14.0)

(-15.5)

Page 39 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Steam (T/h) Item No.

Description

SPR1505

Water Spray for Economizer

X-1507


EJ-1501

Catalyst Hoppers Steam Ejector

HP STM

MP STM

Condensate (T/h) LP STM

MP COND

LP COND

COLD COND

HP BFW

(-1.5)

LP BFW

Cold BFW

(-5.2)

0.3

(-0.9)

(0.9)

SV-1503

1 Regenerator Flue Gas Slide Valve

-0.1

-

Steam Trace

-2.0 100.1

-20.6

Losses (T/h)

(-6.7)

-0.3

st

TOTAL:

HP COND

BFW (T/h)

31.8

0.1 2.0 11.3

13.5

2.1

99.1

-244.0

-42.4

0.0

49.1

Notes: [1]: Cold Feed Case: -16.4 T/h MPS [2]: Cold Feed Case: -20.7 Y/h HPS

Page 40 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

1.2.4.1.3. Cooling water & Seawater

Item no.

Description

Cooling Water ΔT (°C)

m3/hr

E-1518

Heavy Naphta Trim Cooler

6.0

-20

E-1520 A-H

Overhead Trim Condenser

8.0

-1743

E-1531

Surface Condenser

E-1532

Blowdown Cooler

13.0

-15

E-1533

Blowdown Cooler

15.0

-24

E-1552 A/B

Wet gas Compressor Trim Cooler

8.0

-225

E-1554 A-D

Stripper Condenser

6.0

-650

E-1559

Gasoline Cooler

6.0

-138

E-1561 A/B

Debutanizer Condenser

12.0

-1159

E-1562

LPG Cooler

6.0

-49

E-1564

Lean Oil Cooler

6.0

-196

E-1565

Fuel Gas Cooler

6.0

-6

E-1566

Lean Amine Cooler

6.0

-53

E-1567

Turbine Condenser Pump / Compressor Cooling

ΔT (°C)

m3/hr

8.8

-7285

8.8

-2300

-95

H-1503

COB/WHB Package

-

C-1501 Gland Condenser

-76

-

C-1501 Oil Cooler

-32

-

C-1501 Main Oil Cooler

6.0

-60

-

C-1501 Gland Condenser

6.0

-50

TOTAL

Seawater

15.0

-3

-4594

-9585

Note: [1]: Peak consumption of 12.9 Nm3/hr with temperature rise of 13°C

Page 41 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

1.2.4.1.4. Instrument & Plant Air Plant Air (Nm3/h)

Item No.

Description

Instrument Air (Nm3/h)

Continuous Intermittent

H-1503

COB/WHB Package

-120

-50

(-125)

X-1507


-26

-8

(-85)

X-1504

Slurry Separator

-1

Oil Mist Generator

-165

X-1502

Fresh Catalyst Feeder

-3

-60

(-40)

X-1503

Auxiliary Catalyst Feeder

(-3)

(-60)

(-40)

C-1501

Air Blower

-22

C-1551

Wet Gas Compressor

6

PV-1501

Plug Valve

-611

SV-1504

nd

2 Regenerator Catalyst Slide Valve

-134

Primary Plant Air for Regeneration Section (form instrument air header)

-4230

Secondary Plant Air for Regeneration Section

(-2320)

Miscellaneous Users

-340 TOTAL: -5658

-118

0

1.2.4.1.5. Nitrogen Item No.

Description

Nitrogen Nm3/h Continuous

C-1551

Wet Gas Compressor

-71

SV-1501

Regenerated Catalyst Slide Valve

-84

SV-1502

Spent Catalyst Slide Valve

-36

Miscellaneous Users

-160 TOTAL: -351

Intermittent (-280)

(-560) 0

Page 42 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

1.2.4.1.6. Furnaces & Boilers Item No.

Description

Fuel Fired

H-1501

1st Regenerator Air Heater Start-Up

Approx. 4.5 T/h

H-1502

2nd Regenerator Air Heater Start-Up

Approx. 4.5 T/h

H-1503

COB/WHB Package

-110 MW

1.2.4.2. Catalysts & Chemicals 1.2.4.2.1. Catalysts The proper selection of catalyst is very important for successful residue cracking operations. Several catalyst properties should be examined for a particular feed. The Axens recommendation for use in R2R residue cracking unit is low sodium, Ultra-Stable Hydrogen Y type (USHY) zeolite. For detailed information on the catalyst properties and recommendations, refer to the licensor operating manual doc. No. 8474L-015-ML-001. Catalyst Inventory and Addition Rate: Catalyst Inventory: 675 tons Fresh Catalyst Addition Rate: •

Mixed Crude:

•

Bach Ho Crude: 5.2 Tons/day (dry basis)

15.2 Tons/day (dry basis)

Fresh Catalyst Selection The fresh catalyst will be specifically designed to maximize middle distillate (LCO) and metal resistance. The target for the MAT activity associated with the corresponding delta coke is given hereafter and linked to the metal concentration to be sustained. Mixed

Mixed

Bach Ho

Bach Ho

Max. Gasoline Max. Distillate Max. Gasoline Max. Distillate Ni Content (ppm)

3213

1776

V Content (ppm)

6748

Page 43 of 323


Mixed

Mixed

DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Bach Ho

Bach Ho

Max. Gasoline Max. Distillate Max. Gasoline Max. Distillate Equilibrium Catalyst MAT Activity (wt %)

68

55

75

60

Delta Coke (Wt %)

1.22

0.99

0.94

0.91

2 catalyst lines fit appropriately with the operation objectives: •

Albemarle (Former Akzo), COBRA RMR DQ1

•

GRACE Davison, GDC-1825

The final guarantee catalyst will be selected by AXENS after evaluation of the best candidates proposed by Vendors.

1.2.4.2.2. Antimony (Nickel passivator, only in Mixed Crude Case) Metal Passivator is injected into the fresh feed just ahead of the feed nozzles from the Metal Passivator Injection Package X-1509 acts to inhibit the undesirable effects of nickel on the catalyst in the feed. It is required for Mixed Crude Feed case only. Used in:

RFCC Feed Section

Type:

NALCO EC9192A or equivalent

Antimony content:

23%

Injection rate:

ratio Sb/Ni in feed: 0.5

Normal consumption:

109 kg/day Mixed Case 0 kg/day Bach Ho Case

Maximum consumption:

15 kg/h

1.2.4.2.3. Corrosion inhibitor Used in:

Fractionator overhead

Type:

CHIMEC 1430

Normal consumption:

60 kg/day


120 kg/day

Page 44 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

1.2.4.2.4. Amine antifoaming agent Antifoaming agent is injected batch wise in either the fuel gas absorber T-1551 or the LPG amine absorber T-1556 of when foaming is experienced. Once foaming is settled, stop injection to avoid over-dosing of chemical. It should be noted that injection of antifoaming agent is the last resolution. Used in:

Gas recovery Section in LPG / Fuel gas amine absorber

Type:

CHIMEC 8045

Normal consumption:

10 kg/day:


20 kg/day

1.2.4.2.5. Amine (outside battery limit) Lean amine if supplied from the ARU (unit 19) to absorb H2S contained in both the fuel gas and the LPG recovered in the Gas Recovery Section of the RFCC. Lean amine if fed to the Fuel Gas Absorber T-1555 and the LPG Amine Absorber T-1556. The rich amine leaving these 2 towers is then returned to the ARU for regeneration. Type DEA:

20% wt di-ethanolamine

H2S content:

0.022 mole/mole DEA

Lean Amine Flowrate:

Bach Ho: 50382 kg/hr Mixed Crude: 77623 kg/hr

Rich Amine Flowrate:

Bach Ho: 50926 kg/hr Mixed Crude: 78145 kg/hr

During amine absorber operation, lean amine temperature should be always 15°C higher than feed gas to avoid condensation of hydrocarbon inside of the fuel gas absorber.

1.2.4.2.6. Phosphate for Steam Generation Phosphate is injected to buffer the water in order to minimize pH fluctuation. It also precipitates calcium or magnesium into a soft deposit rather than a hard scale. Additionally, it helps to promote the protective layer on steam generators metal surfaces. The following phosphate quantities will be used for steam generation: Page 45 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

RFCC HPS and MPS Generation

7.0 kg/day

RFCC Waste Heat Boiler

24.0 kg/day

Total

31.0 kg/day

Phosphate injection rate depends on blow down flow rate and phosphate level in the steam drum or generator. The above rate is based on 1.0 % of blow down from the steam generation system, and marinating 30 wt ppm of phosphate concentration. For LPS steam generation, it is not required to operate blow down operation, and thus phosphate injection is also not required.

Page 46 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

1.3. Glossary of terms and Acronyms 1.3.1. Acronyms COMPANIES/ORGANISATIONS DQR DQIZMB EVN FW MOC MOSTE MPI SRV TPC

Dung Quat Refinery Dung Quat Industrial Zone Management Board Electricity Authority of Vietnam Foster Wheeler Energy Limited Ministry of Construction Ministry of Science, Technology and Environment Ministry of Planning and Investment Socialist Republic of Vietnam Technip Consortium

OTHERS ACE ADP AER

Application Control Environment Analyser Data Acquisition System Alarm Display Panel Application Engineers Room

AI

Analyser Indicator

AIT

Auto Ignition Temperature

MCC MCR MCS MOV Control System MDF

AMS

Asset Management System

MIS

ANSI

American National Standards institute

MMS

APC

Advanced Process Control

MMT

API ARU ASC

American Petroleum Institute Amine Regeneration Unit Analyser Speciality Contractor American Society of Mechanical Engineers

MOC MOM MOV

Minimum Maintained Temperature Madrid Operating Center Minutes of Meeting Motor Operated Valve

MP

Medium Pressure

Analyser Systems Package

MPT

Minimum Pressurization Temperature

MR

Material Requisition

MRR MSD MSDS MTBF MTTR

Marshalling Rack Room Material Selection Diagram Material Safety Data Sheet Mean Time Between Failures Mean Time To Repair

ADAS

ASME ASP ASTM ATM BCS BEDD BFD BFW

American Society of Testing and Materials Asynchronous Transfer Mode Blending Control System Basic Engineering Design Data Block Flow Diagram Boiler Feed Water

MC

Marshalling Cabinet

MCB

Main Control Building Motor Control Center Main Control Room MOV Control System Main Distribution Frame Management Information System Machine Monitoring System

Page 47 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

BL BOM

Battery Unit Bill of Materials

MTO MTPA

BPC

Blending Properties Control

MVIP

BPCD

Barrels per Calendar Day

NACE

BPSD BRC

Barrels per Stream Day Blending Ratio Control

NCR NDE

CAD

Computer Aid Design

NFPA

CALM CBT

NHT NIR NPSH

Net Positive Suction Head

CCC CCR CCTV CD

Catenary Anchor Leg Mooring Commercial Bid Tabulation Control Complex Auxiliary Room Central Control Complex Continuous Catalytic Reformer Closed Circuit Television Chart Datum

Material Take-Off Metric Tonnes per Annum Multi Vendor Interface Program (Honeywell) National Association of Corrosion Engineers Non Conformance Report Non Destructive Examination National Fire Protection Association Naphtha Hydrotreater (Unit) Near Infrared Spectroscopy

NPV NTU OAS OJT

CDU

Crude Distillation Unit

OM&S

OSBL

Net Present Value Naphtha Treater Unit Oil Accounting System On Job Training Oil Movement and Storage Control System Oil Movement and Storage automation Operation Override Switch Operations Planning and Scheduling System Outside Battery Limit

OTS

Operator Training Simulator

CCAR

CENELEC CFC CFR C&I CMMS CNU

European Committee for Electrotechnical Standardization Chlorofluorocarbons Cooperative Fuel Research (Engine) Control and Instrumentation Computerized Maintenance Management System (Spent) Caustic Neutralization Unit

OMSA OOS OPSS

PABX

CPI

Corrugated Plate Interceptor

PAGA

CSI DAF DAU DCS

Control Systems Integrator Dissolved Air Flotation Data Acquisition Unit Distributed Control System

PCB PFD PFM PDB

DEA

Diethanolamine

PGC

Private Automatic Branch Exchange Public Address / General Alarm Printed Circuit Board Process Flow Diagram Path Find Module Project Documents Base Process Gas Chromatograph (Analysers)

PHD

Plant History Database

DMDS DMS

Detailed Environmental Impact Assessment Dimethyldisulfide Document Management System

PI PIB

DNV

Det Nork Veritas

PID

Plant Air Process Interface Building Piping and Instrument Diagram Project Implementation Manual Process Knowledge System (Honeywell DCS) Pipeline End Manifold Planning Project Management

DEIA

DPTD DQMIS DQRP DVM DWT

Design, Pressure, Temperature Diagram Dung Quat Management Information System Dung Quat Refinery Project Digital Video Manager Dead Weight Tonnes

PIM PKS PLEM PLG PMC

Page 48 of 323


EL EOR

ERP ES ESD ETP ETS EWS FDC FAP

Equipment List End of Run Electronic Document Management System Electromagnetic Compatibility Engineering Procurement, Construction and Commissioning Enterprise Resource Planning Ethernet Switch Emergency Shut Down Effluent Treatment Plant Effluent Treatment System Engineering Work Station Feed Development Contract Fire Alarm Panel

FAT

Factory Acceptance Test

FEL

Front End Loading

F&G FIU FIC

Fire and Gas System Field Interface Unit Flow Indicating Controller

FM

Factory Mutual (Approval body)

FOTC

Fibre Optic Termination Cabinet

EDMS EMC EPC

FTE GC GFT

Fail Safe Controller (Honeywell ESD) Fault Tolerant Ethernet Gas Chromatograph Ground Fault

HAZAN

Hazard Analysis Study

HAZOP

Hazard and Operability Study

HDT

Hydrotreater

HEI

Heat Exchange Institution

HHP HGO HIC HP HSE

High High Pressure (Steam) Heavy Gas Oil Hydrogen Induced Cracking High Pressure Health, Safety and Environment Heating Ventilation Air Conditioning Instrument Air International Civil Aviation Organisation Instrument Clean Earth

FSC

HVAC IA ICAO ICE

DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

PMI PMT

Consultant Positive Material Identification Project Management Team

PO

Purchase Order

POC

Paris Operating Center

PP

Project Procedure

PPB PPM PRU PWHT QA QC RA R&D

Parts per Billion Parts per Million Propylene Recovery Unit Post Weld Heat Treatment Quality Assurance Quality Control Risk Analysis Research and Development Real Time Database RDBMS Management System Residue Fluid Catalytic RFCC Cracking RFSU Ready for Start-Up RLU Remote Line Unit ROW Right of Way Refinery Performance RPMS Management System Resistance Temperature RTD Detector Real Time Data Base RTDB (System) RTU Remote Terminal Unit SAT Site Acceptance Test SBT Segregated Ballast Tanks Software Bypass Management SBMS System Supervisory Control and Data SCADA Acquisition SCC Satellite Control Complex Simulation Control SCE Environment SCR Satellite Control Room SDH Synchronous Digital Hierarchy SE Safety Earth S&E Safety & Environmental SGS Safeguarding System SOE

Sequence of Events

SOR

Start of Run

SOW

Scope of Work

SP

Specification Page 49 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

ICS

Integrated Control System

SPIR

IIP I/O IP

SPM SR SRU STC

Construction Standard

IRP IRR

Initial Interface Plan Input/Output Institute of Petroleum Instrumented Protective System Interposing Relay Panel Internal Rate of Return

Spare Parts and interchangeability Record Single Point Mooring Scope of Supply Sulphur Recovery Unit

STD STEL

IS

Intrinsically Safe

SVAC

ISA ISE ISBL ISOM

Instrument Society of America Intrinsically Safe Earth Inside Battery Limit Isomerisation Unit

SWS TAS TBT

ITB

Invitation to Bid

TCF

ITP

Inspection and Test Plan

TCM

JB

Junction Box

TEMA

JCC

Jetty Control Complex

TGIF

JCR JSD JSS

Jetty Control Room Job Specification for Design Job Specification for Supply

TLCR TLCS TN

JVD

Joint Venture Directorate

TPS

KLOC KTU LAN LCO LCOHDT

Kuala Lumpur Operating Center Kerosene Treatment Unit Local Area Network Light Cycle Oil LCO Hydrotreater

TQM TS TWA UFD U/G

LDE

Lead Discipline Engineer

UL

Design Standard Short Term Exposure Limit Shelter Ventilation and Air Conditioning System (Analyser houses) Sour Water Stripping (Unit) Terminal Automation System Technical Bid Tabulation Temporary Construction Facilities Task Control Module Tubular Exchanger Manufacturers' Association Temperature Gauge Indication Facilities (Tankage) Truck Loading Control Room Truck Loading Control System Transmittal Note Total Plant Solution (Honeywell) Total Quality Management Terminal Server Time Weighted Average Utility Flow diagram Underground Underwriter Laboratories (Approval body)

IPS

LEL LGO LIMS

Lower Exposition Limit (F&G, Analysers) Light Gas Oil Laboratory Information Management System

UPS

Uninterruptible Power Supply

VDU

Visual Display Unit

VPU

Vendor Package Unit

LIS

Laboratory Information System

WABT

LLU LP LPG LTU LPG

Local Line Unit Low Pressure Liquefied Petroleum Gas Treater Unit

WBS WHB YOC

Weight Average Bed Temperature Wash Breakdown Structure Waste Heat Boiler Yokohama Operating Center

1.3.2. Glossary Refer to separate glossary.

Page 50 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

TRAINING MODULE


Course Content: Section 1 - General Description Section 2 - Process Flow Description

X

Section 3 - Process Control Section 4 - Safeguarding Devices Section 5 - Fire & Gas Systems Section 6 - Quality Control Section 7 - Cause & Effects Section 8 - Operating Procedures Section 9 - HSE Section 10 - Reference Document Index

Page 51 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

SECTION 2 : PROCESS FLOW DESCRIPTION Drawing to be inserted here Figure 5: RFCC Block Flow Diagram Drawing to be inserted here Figure 6: RFCC Process Flow Scheme 2.1. Feed Section Drawing to be inserted here Figure 7: RFCC Feed Section Long residue is normally fed directly to the unit from the Crude Unit (CDU) at 115°C. Alternatively part, or all, of the feed can be fed from storage at 70°C. Indeed, the preheat system of the feed is also designed to process 100% cold feed. Hot feed straight from the CDU and cold feed from storage enters the battery limits and flows to the Feed Surge Drum D-1513 on level control by LIC-042 with a split range level control signal to the controller inside the CDU or to the flow controller on the cold feed from storage. The pressure in the Feed Surge Drum is maintained at 1 kg/cm2g by either admitting Fuel Gas or venting excess off gas to the Flare header. In D-1513, water contained in the feed is separated and sent to the OWS. The feed is then pumped from the feed Surge Drum by the Feed Pumps P-1501 A/B to the feed preheat train, in which the way feed is preheated depends on the type of crude used: •

Bach Ho Case: Feed is 1st pumped to the LCO Pumparound Feed Preheat Exchangers E-1512 AD, in which the feed is preheated against LCO pumparound pumped by the LCO Pumparound Pumps P-1510 A/B from the tray #25 of the main fractionator T1501. Then the feed is further heated against MP steam first in the MP Steam Feed Heater E-1522 and secondly against HP steam in the HP steam Feed Heater E1524. The Residue Feed is finally heated against Slurry in the 1st Feed Preheat Slurry Exchangers E-1502 A/B/C and the 2nd Feed Preheat Slurry Exchangers E-1501 A/B, from where feed exits at the temperature of 290°C. Slurry is feed to the tube sides of the 1st and 2nd feed preheat slurry exchangers by means of the Slurry Pumparound Pumps P-1519 A/B/C from the bottom of the Main Fractionator T1501.

•

Mixed Crude Case In the case of Mixed Crude feed, the feed is pumped by the Feed Pumps P-1501 A/B to E-1512 A/B/C/D where it is preheated to the required temperature of 170°C by the LCO pumparound when 100% of the feed to the surge drum is hot. Additionally, the feed is heated against MP steam downstream of the LCO Pumparound Preheat Exchangers only when the feed is all or partly cold. This is required to obtain the required temperature of 170°C. Page 52 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Downstream of the preheat train, preheat feed is mixed with HCO recycle from above the Bed #4 of the main fractionator. Before being mixed with the feed, HCO recycle is cooled against Boiler Feed Water in the HCO Recycle MP steam Generator E-1508. Depending upon the operating case, a different quality of recycle to feed is used. In Mixed Crude Max Gasoline (MG) operation, a heavy naphtha recycle is used in order to adjust the feed viscosity and further improve the feed atomization. An additional effect is to decrease the heavy oil partial pressure leading to a better vaporization. In MD operation, a HCO recycle is used in order to improve the bottom (HCO and heavier) conversion. The combined feed is then sent to the reaction section via the Feed Line Static Mixer M1501. The LCO pumparound used in E-1512 A/B/C/D is then returned to the main fractionator above the Bed #2. The Slurry used in the 2nd Feed Preheat Slurry Exchangers is returned to the main fractionator above the Bed #5 and so is part of the slurry used in the 1st Feed Preheat Slurry Exchangers. The remaining part of the Slurry used in E-1501 A/B is sent back to the quench zone of T-1501. NOTE: When processing mixed crude feed, the slurry preheat exchangers are not required. These exchangers should have the slurry flushed out of them to avoid settling of catalyst fines and because of the high viscosity and high pour point of the slurry. 2.2. Reaction Section Drawing to be inserted here Figure 8: RFCC Reaction Section 2.2.1. Feed Injection Zone The specially designed feed injection system insures the reaction is carried out efficiently to minimize the production of coke, gas and slurry oil. Oil feed to the riser is preheated before entering the reaction system. Preheat temperature along with regenerated catalyst temperature is controlled to result in an optimum catalyst to oil ratio. The preheated feed mixture is sent to the base of the riser D-1501 and divided into equal flows by the flow controllers FIC-003 A-F to each of the six feed nozzles I1501 A-F. Metal Passivator is injected into the fresh feed just ahead of the feed nozzles from the Metal Passivator Injection Package X-1509 by means of the Metal Passivation Page 53 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Pumps P-1502 A/B and acts to inhibit the undesirable effects of nickel on the catalyst in the feed. It is required for Mixed Crude Feed case only. Shutdown valves will stop the flow of feed to the riser and divert it back to the feed surge drum D-1513 in case of certain emergencies. Dispersion steam is supplied to each of the six feed nozzles to promote atomization and vaporization of the feed. The flow of MP steam to each of the feed nozzles is adjusted by flow controllers FIC-005 A-F. Heavy FCC naphta is injected to the riser above the feed injection zone through the MTC (Mix Temperature Control) injectors I-1502 A-D, where it is mixed with medium pressure dispersion steam. MTC plays an important role in the heat balance control and heavy feed vaporization. The key is to achieve a higher temperature in the fresh feed mixing zone. The MTC is designed to face the two main challenges encountered when processing very heavy, highly contaminated feeds: •

Achieve a satisfactory vaporization of the feed so as to eliminate the unnecessary coke production resulting from an incomplete vaporization

•

To keep the desired heat balance while maintaining the conversion at the optimum level

MTC flow and dispersion steam flow to each of the four injectors are adjusted by flow controllers FIC-010 A-D and FIC-011 A-D respectively. Upstream the feed injection, stabilization steam is injected in the riser, through the four stabilization steam injectors I-1503 A-D, in order to promote a smooth and homogeneous catalyst flow at the feed injection point. The flow to each of the injectors is adjusted by flow controllers FIC-007 A-D. Upon emergency shutdown the steam flow control valves on all injectors automatically open to clear the riser of oil and catalyst with steam. Finally Backflush oil is pumped by the backflush oil recycle pumps P-1506 A/B from the backflush oil receiver in the fractionation a section to the riser, downstream of the MTC injectors. Backflush oil is injected into the riser and mixed with MP dispersion steam via the backflush oil injector I-1504. The flow of backflush oil and dispersion steam to the injector is controlled by FIC-012 and FIC-013 respectively.

2.2.2. Riser/Reactor The sensible heat, heat of vaporization and heat of reaction required by the feed is supplied by the hot regenerated catalyst. From the withdrawal well, hot regenerated catalyst flows to the riser wye, to be mixed with the feed, via the regenerated catalyst slide valve SV-1501. The riser outlet temperature is controlled by the amount of regenerated catalyst admitted to the riser through SV1501. Page 54 of 323


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In the wye section at the base of the riser, steam is injected via a steam ring to keep the regenerated catalyst in a fluid state at all times. The small droplets of feed contact hot regenerated catalyst in a counter current way and vaporize immediately. The vaporized oil intimately mixes with the catalyst particles and cracks into lighter, more valuable products along with slurry oil, coke and gas. The cracking reactions take place during the 2 seconds residence time in the riser as the reaction mixture (composed of the products and the catalyst) accelerates toward the Riser Outlet Separator System (ROSS) at the top of the riser. To prevent the continuation of reactions which produce gas at the expense of gasoline the catalyst is quickly separated from the hydrocarbon/steam vapors in the ROSS separator located at the end of the riser. This system drastically reduces the post riser catalyst/vapors contact time. After exiting the ROSS separator, the vapors pass through high efficiency single stage Disengager Cyclones CY-1501 A/B/C/D/E/F to complete the separation of catalyst from vapors, thus minimizing the amount of catalyst lost into the product. The ROSS separator and disengager cyclones CY-1501A-F separate the product vapors from spent catalyst and return the catalyst to the stripper bed. The reactor product vapors, containing a small amount of inerts, catalyst and steam, flow to the quench zone of the main fractionator T-1501. The small amount of catalyst contained in the product vapors is carried away from the fractionator in the bottom slurry product. The reactor pressure "floats on" the main fractionator pressure and as such is not directly controlled at the reaction section: A pressure control at the main fractionator reflux drum D-1514 allows achieving a steady operating pressure in the reaction system.

2.2.3. Stripper Catalyst exiting the ROSS separator is pre-stripped with MP steam from a steam ring located immediately at the exit of the separator diplegs. This is an important feature for reducing coke yield. The catalyst is further stripped by steam from the main steam ring as the catalyst flows down the Disengager/stripper D-1501. 2 additional rings are also provided in addition to the main ring: •

The upper ring, above the main ring, achieves a second stage of prestripping of the catalyst before it enters the stripper.

•

The lower ring is located in the bottom head of the stripper to achieve a stable fluidization at the inlet of the spent catalyst standpipe. The steam rate for this ring is part of the total steam required for good stripping but its prime function is to aerate the catalyst entering the spent catalyst standpipe. This is important for adequate head build-up to maintain an adequate slide valve differential pressure for controlling the stripper level. Page 55 of 323


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The total steam flow is designed to provide about 6 kg of steam per ton of catalyst circulated. The contact between catalyst and steam is enhanced by the presence of fluidized bed packing permitting cross and counter current flow of steam and catalyst. The fluidized bed packing is located between the main ring and the lower ring. It allows efficient contact between the catalyst and steam to displace the volatile hydrocarbons contained on and in the catalyst particles before they enter the 1st stage regenerator D-1502, where coke will be burnt off.

2.2.4. Spent Catalyst Transfer Downstream of the main ring, stripped catalyst flows down the spent catalyst standpipe where the spent catalyst is aerated by means of fuel gas from the fuel gas header (or Nitrogen) to maintain proper density and fluid characteristics of the spent catalyst. Aeration gas injectors are distributed al along the spent catalyst stand pipe. While aerated, the catalyst flows down through the spent catalyst line expansion joint EX-1501 and then the spent catalyst slide valve SV-1502, which regulates the level of the stripper by regulating the flow of catalyst leaving it. Then the spent catalyst flows into the 1st stage regenerator D-1502 through a distributor which ensures that the entering coke-laden catalyst is spread across the regenerator bed. 2.3. Catalyst Regeneration Section The first stage regenerator D-1502 burns 50 to 80% of the coke and the remainder is burned in the second stage regenerator D-1503. This two stage approach to regeneration adds considerable flexibility to the process as potential heat is rejected in the first stage regenerator in the form of CO. When running heavy feeds, the need for heat rejection is higher; the amount of coke burned in the first stage regenerator is increased, thereby lowering the final temperature of the regenerated catalyst. When running lighter feeds the amount of coke burned in the first stage regenerator D-1502 is reduced, thus increasing the regenerated catalyst temperature. The amount of coke burned in the first stage can be varied by adjusting the air flowrate in order to achieve operating flexibility on the unit for different feedstocks. The heat of combustion released by the combustion of coke is transferred to the catalyst which will later supply the heat required to the reactor D-1501. The heat balance of the unit is much more flexible than in single stage regeneration systems because potential energy in the form of carbon monoxide from the first stage regenerator D-1502 can be adjusted while complete regeneration of the catalyst is accomplished in the second stage.

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2.3.1. Air blower and air heaters The combustion air required for the combustion reactions in the 1st and 2nd catalyst regenerators D-1502 and D-1503 is supplied by the steam turbine driven air blower C-1501. Atmospheric air is introduced to the air blower C-1501 through an intake filter and silencer F-1501. At C-1501 discharge, the blower air is distributed to a header system providing combustion air to the downstream equipment as follow: •

Combustion air is supplied to the inner air rings and outer air rings at the bottom of the 1st Catalyst Regenerator D-1502 via the 1st regenerator air heater H-1501 which heats the blower to the required temperature. The outer air ring and inner air ring are designed to handle about 70% and 30% of the combustion air to the first stage regenerator D-1502 respectively.

•

Combustion air is supplied on flow control to the unique air ring located at the bottom of the 2nd regenerator D-1503 via the 2nd regenerator air heater H-1502, which also heats the blower to the required temperature for coke burning in D-1503.

•

Blower air is also used as lift air and is supplied on flow control to the bottom of the lift line of the 1st regenerator in order to transfer partly regenerated catalyst from D-1502 to D-1503. Air is injected through the hollow stem of the plug valve PV-1501 which regulates the amount of catalyst transferred to the 2nd stage regenerator.

•

Blower air is also injected in the catalyst loading line at the bottom of each regenerator as fluidizing medium.

•

Finally blower air is supplied in the withdrawal ring of the withdrawal well downstream of the point where the hot regenerated catalyst is discharged to the well, also as fluidizing medium.

C-1501 surging is prevented by venting air using a sophisticated anti-surge controller. Also, power assisted check valves at the blower discharge prevent back-flow of catalyst in the event of blower shutdown. The air heaters are working on propane and are used during start-up to heat-up the equipment including dry out of refractory. Instrumentation is provided to prevent overheating the equipment during air heater operation and a flame safety package is included to prevent unsafe conditions during burner operation. 2.3.2. First stage regenerator Spent catalyst containing roughly 1 to 1.5 wt % coke flows from the spent catalyst distributor and is spread across the bed in the first stage regenerator D-1502. Part of the coke is burned by combustion air supplied from the outer and inner air rings. This regenerator operates in a counter current (air inlet at bottom and spent catalyst inlet at top) to prevent catalyst overheating.

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In order to limit hydrothermal deactivation of the catalyst, the regeneration conditions are mild: 1st stage regenerator total combustion air is controlled to limit the temperature in this 1st stage to maximum 730°C. The partially regenerated catalyst flows down through the first stage regenerator bed to the entrance of the air lift. Aeration by a fluffing ring is supplied in the vicinity of the air lift to ensure smooth flow of catalyst to the lift. A hollow stem plug valve PV-1501 regulates the flow of catalyst to the lift line and is controlled by the level in the first stage regenerator D-1502 via LIC-004. Blower air injected through the hollow stem of the plug valve into the air lift is flow controlled at a rate sufficient to lift the catalyst in a dilute phase up to the second stage regenerator D1503. Emergency air is provided through blast connections to clear the lift in the event of plugging. 2 stage cyclones (CY-1502A-F / CY-1503A-F) separate entrained catalyst from the flue gas exiting the 1st stage regenerator D-1502 towards the CO Incinerator H-1503 where the incineration of the CO in the flue gas is then accomplished. At the exit of the regenerator, the flue gas pressure is reduced through a double disc flue gas slide valve SV-1503 controlling the regenerator pressure. During the start-up, torch oil is used to heat the regeneration process to its operating temperature. Oil and steam on flow control (FIC-069/077A-C) are directed to three nozzles SPR-1501A-C which spray into the bed of air preheated catalyst. A continuous catalyst withdrawal is necessary to maintain the unit catalyst inventory in the normal operating region. Equilibrium catalyst is continuously withdrawn from D-1502 through the Catalyst Draw-Off System X-1501 and is sent either to the spent catalyst hopper D-1506 or the Auxiliary Catalyst Hopper D1507.

2.3.3. Second stage regenerator The partially regenerated catalyst flows up the lift line through the expansion joints between the regenerators EX-1502 and enters the 2nd stage regenerator D-1503 below the air ring. A distributor at the end of the lift provides for efficient distribution of catalyst and air from the lift. Catalyst is then completely regenerated to less than about 0.05% carbon through combustion at more severe conditions than in the first stage regenerator D-1502. Very little carbon monoxide is produced in the 2nd stage and excess oxygen is regulated by flow control of the combustion air from C-1501 (FIC-164) for efficient and complete combustion. Because most of the hydrogen in coke was removed in the 1st stage, very little water vapor is produced in the second stage. This limits hydrothermal deactivation of the catalyst as higher regeneration temperatures are experienced. External refractory lined cyclones CY-1504A-D are used on the 2nd stage flue gas outlet to remove entrained catalyst. The cyclone dip legs are external to the Page 58 of 323


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regenerator. Catalyst recovered in the cyclones is returned to the regenerator bed below the normal operating level by way of the diplegs. Aeration is supplied to the diplegs to maintain a smooth fluidized catalyst flow and the diplegs outlets are equipped with flapper (trickle) valves to prevent catalyst and gas backflow into the cyclones. Flue gas from the 2nd stage regenerator then flows to the Waste Heat Boiler H1503 through the 2nd Regenerator Flue gas Slide Valve SV-1504 and the 2nd Regenerator Flue gas Block Valve BV-1502 A. The second stage regenerator pressure is controlled by the flue gas double disc slide valve SV-1504, through differential pressure between the first and second stage regenerators PDIC-172. 2.3.4. Combustion Air Rings The combustion air rings distribute the combustion air evenly across the bed in the regenerators. A well distributed source of combustion air is essential for good, evenly distributed catalyst regeneration without after burn. The rings are designed to operate satisfactorily at the minimum turndown design for the unit. The pressure drop across the ring is kept above 0.07 bar at turndown to maintain adequate distribution and prevent intrusion of catalyst into the ring and avoid associated erosion. 2.3.5. Regenerated catalyst transfer The hot regenerated catalyst flows from the 2nd stage regenerator D-1503 through a lateral into the withdrawal well. In the withdrawal well a stable bed is established at proper standpipe density by introduction of a controlled amount of fluidizing air from the withdrawal well ring. A smooth stable flow of catalyst down the standpipe is provided by injection of aeration Plant Air at several elevations on the regenerated catalyst standpipe. As the head pressure increases down the standpipe and the fluidized catalyst is compressed, these aeration points are used to replace the lost volume to ensure a continuity of fluid catalyst flow properties. At the bottom of the regenerated catalyst standpipe the regenerated catalyst slide valve SV-1501 controls the flow of hot catalyst. The Riser Outlet Temperature sets the position of the slide valve which regulates the flow of hot regenerated catalyst. The regenerated catalyst passes to the wye section at the base of the riser D1501 where a steam ring fluidizes the catalyst. The wye steam and fluidization points in the wye section ensure that the catalyst flow to the feed injection point is stable and smooth in order for the feed injection system to perform at its optimum.

2.3.6. Catalyst handling The catalyst handling system includes hoppers for storage of fresh catalyst and spent catalyst, loading devices for catalyst addition and a draw-off device for continuous equilibrium catalyst withdrawal. Three hoppers are installed: •

The fresh catalyst hopper D-1505, Page 59 of 323


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•

The spent catalyst hopper D-1506

•

The auxiliary catalyst hopper D-1507, which provides flexibility in the operation for different options: o Storage of imported equilibrium catalyst reused as part of the makeup catalyst, o Storage of excess spent catalyst, o Storage of a 2nd grade of fresh catalyst for make-up.

The spent and fresh catalyst hoppers are sized to contain the entire unit inventory. Each hopper is provided with one cyclone and with aerations in the bottom cone to assist the catalyst circulation to the transfer lines. Hoppers loading and unloading Fresh catalyst or equilibrium catalyst, delivered in trucks, are loaded into the fresh catalyst hopper D-1505 for fresh catalyst, and spent catalyst hopper for equilibrium catalyst, using either the truck compressor or the steam ejector EJ-1501 supplied for reducing the hopper pressure. Spent catalyst is unloaded from the spent catalyst hopper D-1506 to the flexible bag by hopper pressurizing with plant air. Unit loading and unloading Before start-up, equilibrium catalyst is loaded into the spent catalyst hopper D1506 as described above. When the unit warm-up is completed, the catalyst is loaded into the unit through the first regenerator D-1502. The hopper is pressurized with plant air. Air from the blower C-1501 is injected into the catalyst addition line to D-1502 to act as motive fluid to transport the catalyst. After shutdown, the spent catalyst is unloaded from the unit into the spent catalyst hopper by reducing the pressure in the hopper using the steam ejector EJ-1501. Catalyst addition and withdrawal To maintain the catalyst inventory during normal operation, fresh catalyst is automatically added (batchwise) at the desired rate into the unit through the 1st regenerator D-1502 by means of either of the batch catalyst feeders: X-1502 for the fresh catalyst hopper D-1505 or X-1503 for the auxiliary Catalyst Hopper D1507. Each batch catalyst feeder can be adjusted for batch size and frequency of additions. As most of the time, catalyst addition is higher than the catalyst losses from the unit, catalyst must be withdrawn to keep the unit inventory constant. This operation is achieved by a catalyst draw-off system X-1501 provided on the first regenerator D-1502: Hot catalyst is withdrawn, cooled down through a finned tube and sent to the spent catalyst hopper D-1506 at a temperature below 400°C.

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2.4. Flue gas treatment Drawing to be inserted here Figure 9a: Flue Gas Treatment Section

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Figure 9b: COB/WHB Package Flow Scheme Page 62 of 323


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The flue gas coming from the first regenerator contains CO and some unburned products. It is sent to the CO incinerator H-1503, via flue gas slide valve SV-1503 for combustion completion. The incinerator burner is supplied with combustion air via the duty motor driven forced draft air fans C-1502 A/B. The CO Boiler is provided with burners for fuel gas and also fuel oil in order to obtain a complete combustion of CO into CO2. The flue gas from the CO Boiler is routed to the Waste Heat Boiler H-1503 for HP steam regeneration. The flue gas coming from the second regenerator D-1503 is sent straight to the waste heat boiler H-1503 via the second regenerator flue gas slide valve and SV1504 and the COB/WHB 2nd regenerator flue gas block valve BV-1502 A. The flue gas exiting the waste heat boiler H-1503 is sent to an electrostatic precipitator X-1507 before flowing through the economizer E-1525 section of the CON/WHB package, and DeSOx unit (X-1508, for future), and then to a stack SK1501. Heat released in WHB H-1503 is used for HP steam generation: HP boiler feed water is fed from the battery limits to the heavy naphta boiler feed water heater E-1516 where HP BFW is heated in the tube side against heavy naphta product (in the shell side) pumped by the heavy naphta product pumps P1515 A/B. The heated BFW is then sent to the LCO Pumparound BFW heater E-1511 where the BFW (tube side) is heated against LCO pumparound (shell side) drawn off from the main fractionator and pumped by the LCO Pumparound Pumps P-1510 A/B. The preheated HP BFW leaving E-1511 is then split into 2 streams: •

Part of the preheated BFW is fed to: o The Slurry HP Steam Generators E-1503 A/B/C in which preheated HP steam is generated against slurry pumparound pumped by P1519 A/B/C from the bottom of the main fractionator. o The slurry HP Steam Generators E-1504 A/B in which HP steam is generated against slurry pumparound pumped by P-1519 A/B/C from the bottom of the main fractionator The HP Steam leaving E-1503 A/B/C and E-1504 A/B is then recombined before being fed to the HP steam superheater of the waste heat boiler.

•

The other part of the preheated BFW is sent to the economiser section of the COB/WHB Package H-1503. Preheated HP BFW is then heated (tube side) against MP steam (Shell side) in the BFW Preheater E-1534. before being fed to the economizer E-1525. In the economizer, the flue gas coming from the electrostatic precipitator X-1507 is used as heating medium. The steam leaving the economizer is then fed to the Steam Drum D-1512

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Phosphate is also injected into the Steam Drum D-1512 by means of either of the Phosphate injection Pumps A-1502-P-01-A/B from the Phosphate Tank A-1502TK-01. Phosphate is injected to buffer the water in order to minimize pH fluctuation. It also precipitates calcium or magnesium into a soft deposit rather than a hard scale. Additionally, it helps to promote the protective layer on boiler metal surfaces. However, phosphate forms sludge as it reacts with hardness; So blowdown or other procedures need be established to remove the sludge during a routine boiler shutdown. Boiler water then exits the bottom of the steam drum via 3 lines, the inlet of each being equipped with a vortex breaker, and flows to the 4 Evaporator Coil Banks of the WHB H-1503. In each of the Evaporator Coil Banks, steam is generated (tube side) by means of the flue gas exiting the HP superheater of the WHB H-1503. The mixture of steam and boiler water at the outlet of each evaporator coil bank is then routed back to the steam drum via 4 dedicated lines. Boiler water from the steam drum is also fed to the Screen Steam Generator upstream the HP steam Superheater in the Waste Heat Boiler. The steam/boiler water stream generated by the flue gas exiting the CO Combustion exits the Screen Steam Generator and is routed back to the Steam Drum D-1512. Saturated steam from D-1512 is sent to the HP Steam Superheater after being mixed with HP steam from the E-1503 A/B/C and E-1504 A/B. In the Superheater, flue gas exiting the Screen Steam Generator generates Superheated HP steam (tube side). The superheated HP steam generated is then de-superheated by means of HP BFW prior to being sent to the Superheated HP steam header. Part this HP steam is also sent to the turbine of the standby forced draft fan C-1502 B. A continuous blowdown from the steam drum is sent to the continous blowdown drum D-1531. The LP steam recovered in D-1531 is sent to the LP steam header while the water collected is sent to the intermittent blowdown drum D-1532. The water in D-1532 is cooled down against cooling water in the Blowdown Cooler E1533 before being sent to the oily water sewer. Superheated MP steam is also generated in the WHB: LP Boiler Feed Water is fed to the following MP steam generators in parallel: •

HCO recycle MP steam generator E-1508 where LP BFW is heated (shell side against HCO recycle drawn-off from the main fractionator and pumped by the HCO recycle pumps P-1507 A/B.

•

HCO Pumparound MP steam generator E-1523 where LP BFW is heated (shell side) against HCO pumparound drawn off from the main fractionator and pumped by the HCO Pumparound pumps P-1508 A/B.

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•

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Slurry MP steam generators E-1505 A/B where LP Boiler Feed Water is heated (shell side) against slurry from the HP steam generators E-1504 A/B

The MP steam streams leaving in the above exchangers are then recombined and the MP steam stream is fed to the MP steam superheater downstream of the 4th Evaporator Coil Bank. There, the MP steam is superheated against the flue gas leaving the evaporator. Superheated MP steam is then de-superheated against LP BFW prior to being discharged to the MP steam header. The flue gas leaving the WHB H-1503 is then routed to the Electrostatic Precipitator X-1507 where the content of catalyst dust contained in the flue gas leaving the COB/WHB package is decreased to meet the environmental specification. The dust fine content at precipitator outlet shall not exceed 50 mg/Nm3 dry basis. The principle of operation is to provide high voltage electric for collection of dust by corona effect. (Refer to the section 4 of the present document for more information on X-1507 package.) In case of trip of the COB/WHB package, the flue gas from the 1st and 2nd regenerators is sent directly to the electrostatic precipitator package X-1507 through the bypass valves BV-1501B (1st regenerator flue gas) and BV-1502B (2nd regenerator flue gas). In such an event, H-1503 is isolated by closure of the associated block valves BV-1501A (1st regenerator flue gas) and BV-1502A (2nd regenerator flue gas). The flue gas leaving the electrostatic precipitator is then fed to the Economizer E1525 before being finally sent to the stack. In the future, the flue gas leaving the Economizer will undergo another stage of processing with the DeSOx unit before running to the stack. 2.4.1. Phosphate injection For the same reasons than for the phosphate injection in the steam drum D-1512 (see previous paragraph), phosphate solution, from the tank TK-1510 in the phosphate injection package X-1510, is injected to the BFW fed to the following steam generators: •

Slurry HP steam generators E-1503 A/B/C by means of the metering pumps P-1531A/B/C respectively;

•

Slurry HP steam generators E-1504 A/B by means of the phosphate injection pumps P-1531 D/E respectively;

•

Slurry MP steam generators E-1505 A/B by means of the phosphate injection pumps P-1532 A/B respectively;

•

HCO LP steam generator E-1510, also from the discharge of the phosphate injection pump P-1532B

•

HCO pump pumparound MP steam generator E-1523, Slurry LP steam generators E-1506 A/B and LCO product LP steam generator E-1513 by means of the phosphate injection pump P-1532C Page 65 of 323


•

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HCO recycle MP steam generator E-1508 by means of the phosphate injection pump P-1532D

2.5. Fractionation Section Drawing to be inserted here Figure 10: Fractionation Section 2.5.1. Fractionator bottom section The reactor effluent from the disengager of the reaction section is sent to the bottom of the main fractionator T-1501 below the Bed #5. The bottom slurry pumparound is circulated by Slurry Pumparound Pumps P1519A/B/C to the downstream equipment depending on the operating case: •

In the case of Bach Ho feed, a large proportion of the bottom pumparound duty is used to preheat the feed in the 1st & 2nd Feed Preheat Slurry Exchangers E-1502 A/B/C and E-1501 A/B. The remaining duty is used to generate HP steam in HP steam generators E-1504 A/B and then MP steam in MP steam generators E-1505 A/B, prior to being sent back to T-1501 in the Quench Zone on flow control reset by the bottoms temperature controller (TIC-439) at the suction of the slurry pumparound pumps P-1519 A/B/C. Part of the slurry from E-1505 A/B is also sent back to T-1501 above the Bed #5 on flow control reset by the temperature controller TIC-443 above Bed #4. Meanwhile, the slurry used to preheat the feed in E-1502 A/B/C and part of the slurry exiting E-1502 A/B/C are then sent back to T-1501 in the grid section (Bed #5) after being mixed with the portion of Slurry Pumparound bypassing all the exchangers and steam generators. The remaining part of the slurry leaving E-1502A/B/C is sent to the Quench Zone of T-1501 on flow control reset by the bottoms temperature controller (TIC-439) at the suction of the slurry pumparound pumps P-1519 A/B/C. This quench is used to maintain the bottoms temperature to around 349°C in order to minimize coking

•

For the Mixed Crude feed case, E-1501A/B and E-1502 A/B/C are not in service. In this case the slurry pumped by P-1519 A/B/C is sent to the Slurry HP steam generators E-1503 A/B/C, where HP steam is generated shell side with BFW fed from E-1511. The main part of this cooled slurry pumparound is returned to the grid section (Bed #5) on flowrate control (FIC-425) reset by the temperature controller TIC-443 below the HCO draw-off tray. In the Grid Section of the Main Fractionator the reactor effluent is desuperheated and the bottom slurry product is condensed. Part of the cooled slurry is returned to the bottom of the column to quench the bottoms temperature TIC-439 to around 340°C to minimize coking. The remaining quench is taken from the discharge of the MP steam generator Page 66 of 323


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on flow control reset by the bottoms temperature controller as described for the Bach Ho case. •

A constant total flowrate (controlled by FIC-426) to the grid is maintained by by-passing hot slurry from the discharge of the slurry pumparound pumps.

The slurry product is taken from the discharge of the MP steam generators E-1505 A/B on flow control reset by T-1501 bottoms level controller (LIC-448) and flows to slurry draw-off drum D-1515. The pressure in D-1515 is maintained constant by either admitting fuel gas inside the vessel or venting excess off gas to the flare. The slurry product is pumped by the Slurry Product Pumps P-1504 A/B and is cooled in the Slurry LP Steam Generator E-1506 A/B, in which BFW is feed to generated LP steam shell side. Downstream of E-1506 A/B, the cooled slurry flows to the Slurry Separator X-1504 where catalyst fines are removed. The clarified oil leaving the slurry separator is finally cooled in tempered water coolers E-1507 A/B/C/D before going to storage on flow control reset by the level controller of the slurry draw off drum D-1515. The slurry separator X-1504 consists of 10 modules. These are automatically and sequentially taken out of service for back-flushing while the others remain in service. The modules are back-flushed by P-1505 A/B with Backflush Oil (HCO) from the Backflush Oil Draw Off Drum D-1516. The flush oil from the separator, containing a high concentration of catalyst fines, goes to back-flush oil receiver D-1517 after being mixed with HCO. The pressure in D-1517 is maintained constant by either admitting fuel gas inside the vessel or venting excess off gas to the flare. From D-1517, the back-flush oil is returned to the reactor riser at constant rate by the Backflush oil recycle pumps P-1506 A/B.

2.5.2. HCO section Heat is removed at high level in the HCO pumparound section. HCO flushing oil and HCO recycle are also taken from this section. HCO products and pumparound are taken from the draw off tray above the Bed #4 of the main fractionator T-1501. HCO pumparound is circulated by the HCO Pumparounds Pumps P-1508 A/B to the following equipment in parallel: •

The tube side of the Debutanizer Reboilers E-1560 A/B

•

The shell side of the Heavy Naphtha Stripper Reboiler E-1509

•

The tube side of MP Steam Generator E-1523

The cooled HCO leaving E-1560 A/B, E-1509 and E-1523 is then recombined before being returned to the main fractionator above the Bed #3. The total pumparound flow is maintained constant by controlling the flow of HCO by-passing the above equipments with (FIC-419) at P-1508 A/B discharge. Heat Page 67 of 323


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removal in the pumparound circuit is controlled by the flow controller at the outlet of E-1523 reset by the temperature controller TIC-446 on the recombined pumparound return line to T-1501. HCO for flushing oil is also taken from the draw off tray above the Bed #4 and is then stripped in the HCO stripper T-1504 by LP steam on flow control. The stripper vapour is returned to T-1501 above the pumparound return, Bed #3. The stripped HCO is pumped from T-1504 bottom by the HCO products pumps P-1509 A/B to the tube side of the LP Steam Generator E-1510 where it is used as heating medium to generate LP Steam from BFW in the shell side. The cooling of the HCO is controlled with TIC-474 on the HCO outlet by resetting the pressure controller of the LP steam generated to adjust the quantity of LP steam leaving E-1510. Part of the HCO goes to Backflush Oil Receiver D-1516 on flow control by FIC-469 reset by D-1516 level controller LIC-464. The pressure in D-1516 is maintained constant by either admitting fuel gas inside the vessel or venting excess off gas to the flare. The remaining part goes to: •

The HCO flushing oil system for flushing of slurry pump seals and for instrument flushing.

•

The Backflush Oil Receiver D-1517, on flow control reset by the level controller in D-1517, after being mixed with flush oil from the slurry separator X-1504.

For maximum distillate mode operation, HCO is recycled to the reactor feed. The HCO recycle is taken from the draw off tray above the Bed #4 and is pumped by P-1507 A/B to the tube side of the MP Steam Generator E-1508 where it is used as heating medium to produce MP steam from BFW in the shell side. The cooling of the HCO in E-1508 is controlled by TIC-425 on the HCO recycle line to the feed section by adjusting the amount of HCO bypassing the MP Steam Generator. HCO is then mixed with the feed upstream of the feed temperature control point, as described previously.

2.5.3. LCO section This section of T-1501 consists of six fractionating trays, trays 25 to 30, and a packed pumparound bed, Bed #2. LCO product and LCO pumparound are drawn off from the pumparound draw-off tray below the bed#2 of T-1501. LCO pumparound is circulated by the LCO pumparound pumps P-1510 A/B to the following equipment in parallel: •

Shell Side of the Stripper 2nd Reboiler E-1557,

•

Tube Side of the LCO pumparound Feed Preheat Exchangers E-1512 A/B/C/D,

•

Shell Side of the LCO pumparound BFW Heater E-1511.

The cooled LCO leaving E-1557, E-1512 A/B/C/D and E-1511 is then recombined before being returned to the main fractionator above the Bed #2.

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The total pumparound flow is maintained constant by controlling the flow of LCO by-passing the above equipments with (FIC-411) at P-1510 A/B discharge. Heat removal in the pumparound circuit is controlled by the flow controller at the outlet of E-1511 reset by the temperature controller TIC-452 on the recombined LCO pumparound return line to T-1501. LCO product is taken as a slip stream at the suction of the LCO pumparound pumps P-1510 A/B and is sent to the LCO stripper T-1503 on level controller of the stripper bottoms by LIC-436. The LCO is stripped by LP stream on flow control (FIC-452). The stripper vapor is returned to T-1501 above the pumparound, Bed #2. Stripped LCO is pumped by the LCO Stripper Pumps P-1511 A/B and is cooled on temperature control in LCO Product LP Steam Generator E-1513 and the air cooler E-1514 before going to the LCO Hydrotreater unit or to storage. For maximum gasoline operation this is the total LCO product. For maximum LCO operation (maximum distillate operation), heavy naphtha from the Heavy Naphta Trim Cooler E-1516 is mixed with this stream before being sent to the LCO Hydrotreater unit. In case of LCO Hydrotreater shut down, the LCO is sent directly to storage.

2.5.4. MTC and heavy naphtha section This section consists of 14 fractionating trays, trays 11 to 24, and heavy naphtha pumparound bed, Bed #1. MTC is drawn off from tray 19. The MTC (Mix Temperature Control) has a composition between the light end of the LCO and the heavy end of the heavy naphtha. This cut is recycled to the riser in the Mixed Crude Maximum Gasoline case. The MTC is pumped by the MTC Recycle Pumps P-1512 A/B to the riser injection nozzle on flow control. Heavy naphtha pumparound and heavy naphta product are drawn off from the tray below the bed #1. Heavy naphta pumparound is circulated by the naphta pumparound pumps P-1514 A/B to the following equipment in parallel: •

Tube side of the Stripper Feed Preheater E-1555,

•

Heavy Naphtha Pumparound air cooler E-1521

•

E-2107 & E-2108 in the Propylene Recovery Unit (PRU) for reboiling purpose.

The air cooler E-1521 is designed for the case when the PRU is not in operation. The cooled heavy naphta leaving E-1555, E-1521 and the PRU is then recombined before being returned to the main fractionator above the Bed #1.

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The total pumparound flow is maintained constant by controlling the flow of heavy naphta by-passing the above equipments with (FIC-412) at P-15114 A/B discharge. Heat removal in the pumparound circuit is controlled by the flow controller at the outlet of E-1521 reset by the temperature controller TIC-430 on the recombined heavy naphta pumparound return line to T-1501. Heavy naphta product is taken as a slip stream of the pumparound draw-off at the suction of the P-1514 A/B and is sent to the heavy naphta stripper T-1502 on level controller of the stripper bottoms by LIC-439. The heavy naphta stripper bottoms is reboiled in the reboiler E-1509, using HCO pumparound as heating medium. The stripper vapor is returned to T-1501 above the pumparound bed, Bed #1. Stripped heavy naphtha is pumped by the Heavy Naphta Product Pumps P-1515 A/B. It is first cooled by preheating HP boiler feed water in E-1516 and is then cooled in air cooler E-1517 and trim water cooler E-1518. For maximum LCO case, the heavy naphtha is mixed with LCO and for maximum gasoline case it is mixed with debutanized gasoline in the Gas Recovery Section. Heavy naphtha is also drawn off at the suction of P-1514 A/B as lean oil for the secondary absorber in the Gas recovery Section. The lean oil is pumped by P1513 A/B on flow control FIC-718 in the Gas Recovery Section where it is first cooled in Lean Oil / Rich Oil Exchanger E-1563 before cooling in Lean Oil Cooler E-1564.

2.5.5. Top section This section of T-1501 consists of 10 fractionation trays, trays 1 to 10. Rich oil from the bottom of the secondary absorber in the Gas Recovery Section is fed to tray 9. A partial draw-off accumulator tray is provided below the top tray. The accumulator tray is designed to separate water and hydrocarbon. Any water is drawn-off under interface level control LIC-416 and flows by gravity to the inlet of overhead condenser E-1519.

2.5.6. Fractionator overhead section The overhead vapor from T-1501 is partially condensed in the overhead air condenser E-1519 and cooling water exchanger E-1520A-H before flowing to the fractionator reflux drum where the liquid hydrocarbon, water and vapor phases are separated. Off-gas streams from CDU and NHT Units are also fed to D-1514. Part of the liquid hydrocarbon is sent back to the tray #1 of the main fractionator as a reflux by means of the Fractionator Reflux Pumps P-1516 A/B. The overhead naphtha cut point is controlled by the overhead temperature controller TIC-461 resetting this reflux rate. Part of the wash water is recycled from the fractionator reflux drum D-1514 boot to the inlet of the overhead condenser E-1519 by means f the overhead sour water Page 70 of 323


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pumps P-1517 A/B on flow control (FIC-459) in order to minimize corrosion in the condenser. From the discharge of P-1517 A/B, the remaining water is sent to: •

The SWS (unit 18) on flow control reset by the interface level controller LIC446 of the D-1514 boot;

•

To the wet gas compressor inter cooler on flow control (FIC-703) to be used as wash water.

Corrosion inhibitor is also injected into the overhead line of T-1501, upstream of the overhead condensers E-1519, from the corrosion inhibitor tank TK-15101 by means of either of the corrosion inhibitor pumps P-1520 A/B. The net overhead liquid product is pumped by the Overhead Liquid Pumps P-1518 A/B, under flow control FIC-455 reset by the level controller of the Main Fractionator Reflux Drum LIC-443, to the primary absorber in the Gas Recovery Section. The overhead vapor from D-1514 flows to the first stage KO drum of the wet gas compressor D-1551, while excess off gas is vented to flare on pressure control. 2.6. Gas Recovery section Drawing to be inserted here Figure 11: Gas Recovery Section 2.6.1. Wet gas compressor and HP condenser Wet gas from the Main Fractionator Reflux Drum D-1514 flows to the wet gas compressor first stage knock-out drum D-1551 where entrained and condensed liquids are separated. The liquid collected in D-1551 is pumped by the KO drum liquid pumps P-1552 A/B back to the fractionator reflux drum D-1514. The gas from D-1551 is compressed in the 1st stage of the compressor C-1551 and is then cooled in wet gas compressor intercooler E-1551 and trim cooler E1552 A/B. Sour water from the Fractionation Section is injected at the inlet of E1551 to minimize corrosion. The cooled vapor and condensed liquid from E-1552 are separated in the interstage KO drum D-1552. The vapor from D-1552 is compressed in the 2nd stage of compressor C-1551. The liquid phase in D-1552, hydrocarbon and water, is pumped by P-1551 A/B and is re-contacted with the compressor discharge vapor. This combined stream is partially condensed in HP air condenser E-1553 before being fed to the Stripper Condensers E-1554 A/B/C/D. A slip stream of this combined stream is recycled back to the inlet of the wet gas compressor intercooler E-1551.

2.6.2. Stripper condenser and high pressure separator drum The outlet from E-1553, the primary absorber T-1551 bottom liquid and the stripper T-1552 overhead vapour are combined before entering stripper water

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condensers E-1554A/B. An LPG stream from the CDU is also fed to the inlet of E1554 A/B. The mixed phase outlet from E-1554A/B is separated into water and hydrocarbon liquid phases and a vapor phase in HP separator drum D-1553. The sour water is sent on D-1553 boot interface level control to the sour water stripper (unit 18). The hydrocarbon liquid phase is pumped by the stripper feed pumps P-1553 A/B and after preheating in E-1555 by heavy naphta pumparound is fed to the top of stripper T-1552. The vapor phase from D-1553 is fed to the primary absorber T-1551, below the bottom tray.

2.6.3. Primary absorber T-1551 The primary absorber T-1551 recovers most of the C3 and C4 from D-1553 vapor. The overhead liquid from the Fractionation Section is fed to the top tray of T-1551. For other than Bach Ho Max Gasoline case, gasoline is also recycled from the bottom of the debutanizer T-1554: After being cooled in the stripper first reboiler E-1556, the gasoline air cooler E1558 and the gasoline cooler E-1559, recycle gasoline is pumped by the Recycle Gasoline Pumps P-1554 A/B to be mixed with the overhead liquid from the fractionation section and is fed to the to tray of T-1551. This Gasoline recycle enables required recovery of C3 and C4. The absorber bottom rich oil flows to the inlet of E-1554 under level control.

2.6.4. Stripper The LPG and gasoline mixture is fed from HP separator drum D-1553 to the top tray of the stripper by means of the stripper feed pumps P-1553 A/B and after cooling in the stripper feed preheater E-1555 against heavy naphta pumparound. The purpose of the stripper is to remove H2S, C2 and lighter from The LPG and gasoline mixture. The stripper feed temperature is controlled by the temperature of the stripper at the outlet of E-1555 with TIC-723 adjusting the flowrate of heavy naphta pumparound leaving E-1555. The necessary heat to perform the stripping operation is supplied by two reboilers in series: •

In the 1st stripper reboiler E-1556, the stripper bottoms are heated against debutanizer bottoms.

•

In the 2nd stripper reboiler E-1557, the stripper bottoms leaving E-1556 are heating by LCO pumparound from the Fractionation Section.

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The heat input to E-1557 is controlled by the stripper overhead vapor rate FIC709. This rate, and hence the reboiler duty, is set to meet the C2 specification in the debutanizer overheads. The overhead vapor leaving the stripper is returned to and condensed in E-1554. The bottom liquid of the stripper is fed to the debutanizer T-1554 on flow control FIC-714 reset by the stripper bottoms level controller LIC-712. 2.6.5. Secondary absorber T-1553 The secondary absorber T-1553 recovers gasoline light fractions contained in the overhead gas from primary absorber T-1551, by means of stripping with a heavy naphta stream from the fractionation section. The overhead gas from the primary absorber is sent straight to the secondary absorber T-1553 where it enters below the tray #20. The lean oil used for the absorption is a heavy naphtha stream is drawn off from the main fractionator T-1501 and pumped by P-1513 A/B to the lean oil/rich oil exchanger E-1563, where the lean oil is cooled by exchange with the bottoms of T-1553. Lean oil is then further cooled in the lean oil water cooler E-1564. The cooled liquid flows through lean oil coalescer D-1556 to remove entrained water before it is fed to the top tray of T-1553 on flow control FIC-718. Sour water collected in the boot of the lean oil coalescer D-1556 is sent to the SWS (unit 18) on boot interface level control. The rich oil from the bottom of the secondary absorber T-1553 flows under level control of T-1553 bottoms (by LIC-720) to the lean oil/rich oil exchanger E-1563 where it recovers heat before being recycle to the tray #9 of the Main Fractionator T-1501. The stripped overhead gas leaving T-1553 is cooled in the fuel gas water cooler E1565 and flows to fuel gas absorber K.O. drum D-1557.

2.6.6. Fuel gas absorber The fuel gas absorber T-1555 removes H2S and CO2 from the gas leaving the secondary absorber by contact with lean amine (DEA) fed from the ARU (unit 19). The small amount of liquid in the effluent from E-1565 is separated in the K.O. drum D-1557. The liquid is sent to mixing with rich oil at the inlet of the lean oil/rich oil exchanger E-1563 on level control of the absorber feed KO drum (LIC-726). The overhead gas of the FG absorber feed KO drum is fed to the bottom of the Fuel Gas Absorber T-1555, while the lean amine is fed to the top tray on flow control. In order to avoid hydrocarbon condensation, the temperature of the lean amine is controlled by TDIC-746 to maintain the lean amine at a fixed temperature difference above the inlet gas. Once treated by the lean amine, the overhead gas is sent to the Fuel Gas Absorber Outlet K.O. drum D-1559, where entrained and condensed liquid are separated before the treated fuel gas is sent to the fuel gas system. The gas

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leaving D-1559 is sent to the fuel gas system on pressure control of the secondary absorber overheads by PIC-733. The rich amine leaving the bottom of the fuel gas absorber is sent to the amine regeneration unit (ARU) under T-1555 level control by LIC-730. Any amine accumulated in K.O. drum D–1559 also goes to the ARU on level control of D1559 by LIC-733.

2.6.7. Debutanizer The debutanizer separates LPG from gasoline. The bottom of the stripper T-1552 is fed to the tray #22 of the debutanizer T-1554. The heat required to perform the separation is provided by the debutanizer reboilers E-1560 A/B in which the debutanizer bottoms are heated by HCO pumparound. The reboilers duty is controlled by adjusting the flow of HCO leaving the reboilers with FIC-722 and is set to ensure that the C4 specification in the gasoline is met. The overhead vapor leaving the debutanizer is totally condensed in the debutanizer condensers E-1561 A/B. The pressure in T-1554 is controlled with PIC-745 by bypassing part of the overhead vapor around E-1561 A/B to the reflux drum D-1554. The condensed liquid is pumped from D-1554 by P-1556 A/B: •

Part of the liquid from the debutanizer KO drum is sent to the tray #1 of the debutanizer as a reflux. The reflux rate is flow controlled by FIC-721 reset by the temperature controller TIC-754 on the sensitive tray (tray #8) in the top section of the column. This control loop determines the C5 specification in the overhead product.

•

The remaining overhead liquid, LPG product, is sent to the LPG Amine Absorber T-1556 after being cooled against cooling water in the LPG Cooler E-1562. The flow of LPG product being sent to T-1556 from the discharge of the Debutanizer Overheads Pumps P-1556 A/B is controlled by FIC-723 located downstream of the water cooler and reset by the level controller of the Debutanizer Reflux Drum LIC-742.

The water collected in the boot of the debutanizer reflux drum is sent to the SWS on interface level control. The gasoline product from the bottom of the debutanizer column is first cooled in stripper reboiler E-1556, then in air cooler E-1558 and finally in gasoline water cooler E-1559, before being split into 2 streams: Part of the cooled gasoline is pumped on flow control by the gasoline recycle pumps P-1554 A/B to the primary absorber as supplementary lean oil when required. The net gasoline product is sent to the Gasoline Treating Unit on flow control by FIC-715 reset by the debutanizer level controller LIC-736. For maximum Gasoline operation the heavy naphtha from the Fractionation section is combined with this stream.

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2.6.8. LPG amine absorber T-1556 The LPG amine absorber T-1556 removes H2S by contact with lean amine (DEA) from the ARU (unit 19). T-1556 is a packed column. The LPG enters at the bottom and flows up through the amine. Lean amine from the ARU is fed to the LPG amine absorber after being cooled against cooling water in E-1566. The LPG amine interface level control LIC-746 above the top packed section is maintained by controlling rich amine flow leaving the bottom of the absorber. The overhead LPG liquid flows to the LPG amine coalescer D-1555, where amine carry-over is separated: •

The amine collected in the boot of the LPC amine coalescer is sent to the rich amine stream from the absorber bottom on boot interface level control by LIC-749.

•

The overhead LPG from the drum goes to the LPG Treating Unit.

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TRAINING MODULE


Course Content: Section 1 - General Description Section 2 - Process Flow Description Section 3 - Process Control

X

Section 4 - Safeguarding Devices Section 5 - Fire & Gas Systems Section 6 - Quality Control Section 7 - Cause & Effects Section 8 - Operating Procedures Section 9 - HSE Section 10 - Reference Document Index

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SECTION 3 : PROCESS CONTROL The following is a description of the main control loops of the RFCC unit. For a detailed description of the control loops and the controllers, refer to the process control narrative, 8474L015-SP-1511-001. 3.1. Control narrative & operating parameters 3.1.1. Feed Oil Temperature Control The feed oil temperature control is the prime process parameter for the reactor riser temperature after the Riser Outlet Temperature Control. In the Bach Ho case preheating of feed is by the LCO pumparound, MP and HP steam exchangers and finally by slurry to obtain the feed temperature of 290°C. In the case of Mixed Crude feed, the feed is preheated to the required temperature of 170°C by the LCO pumparound when 100% of the feed to the surge drum is hot. Additionally, MP steam heating is required when the feed is all or partly cold. The temperature is controlled by TIC-002 at the outlet of the preheat train, downstream of the point where the feed is mixed with HCO Recycle. The output of TIC-002 is sent to the selector switch HS-002 which is used to select between the different modes of operation: •

Position 1: “Bach Ho Crude”: The output from TIC-002 is routed to TV-002 which regulates the flow of feed bypassing the 1st and 2nd feed preheat slurry exchangers E-1502 A-C and E-1501 A/B respectively. This way TIC-002 controls the final temperature of the feed. The preheat duty in LCO Pumparound Feed Exchanger in E-1512A/B/C/D is set by flow control of the total LCO pumparound via FIC-417, which acts on FV-417: Flow of LCO pumparound bypass. The duty of E-1522 is set by flow control of the MP Steam via FIC-410 acting on FV-410. The Duty of E-1524 is set by flow control of the HP Steam via FIC-411 reset by the temperature of the feed directly at the outlet of this exchanger (TIC411).

•

Position 2: “Mixed Crude-1” (Hot Feed) The output from TIC-002 is used to reset the flow controller FIC-409 at the LCO pumparound outlet of E-1512 A/B/C/D. FIC-409 adjusts the duty of the LCO Pumparound Feed Preheat Exchangers by acting on FV-409: LCO Pumparound return to main fractionator.

•

Position 3: “mixed Crude-2” (Cold Feed) The output from TIC-002 is used to reset the flow controller FIC-410 which controls the duty of the MP steam supply to E-1522 by acting on FV-410: E1522 MP steam inlet.

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Figure 12: Feed Oil Temperature Control Page 78 of 323


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A constant pressure is maintained on the feed to the reactor feed control valves by the pressure control valve PV-410 upstream of E-1502A/B/C with PIC-410 located upstream of the point where the recombined feed is mixed with HCO recycle. This pressure control ensures that the HCO recycle can enter the feed line. The location of the pressure control valve also facilitates the by-pass temperature control.

3.1.2. UC-001 Feed Injector The feed injection control system provides even distribution of the total feed flow (feed + recycle) to the 6 distributor nozzles I-1501 A/B/C/D/E/F. The total feed flow to each of the 6 feed nozzles I-1501 A-F is respectively controlled by FIC-003 A-F acting on FV-003 A-F at the nozzles inlet. Flowrate of the different feed sources, raw oil flow controller FIC-001 and HCO Recycle Oil flow controller FIC-002 are sent to the master controller UC-024 which sums the contributions from FIC-001 and FIC-002 and divides the total set flow by the number of feed injectors (6). UC-024 then provides this new set point (Total set flow/6) to each feed nozzle flow controller FIC-003 A-F which adjust the position of their feed nozzle flow valve accordingly. The process variable of UC-024 is the output from UY-020. UY-020 calculates the total measured feed flowrate to the riser with outputs from the 6 feed nozzles flow controllers FIC-003 A-F Total set flow = FIC-001 + FIC-002 Set value to FIC-003A= (Total set flow)/6 Set value to FIC-003B= (Total set flow)/6 Set value to FIC-003C= (Total set flow)/6 Set value to FIC-003D= (Total set flow)/6 Set value to FIC-003E= (Total set flow)/6 Set value to FIC-003F= (Total set flow)/6 Total measure flow= FIC-003A + FIC-003B + FIC-003C + FIC-003D + FIC-003E + FIC-003F Each flow controller FIC-003 A-F is temperature compensated with TI-003. HS-013 is provided for selection of signal from FIC-001 to FV-001, which is used for start-up operation of RFCC, when feed oil is circulating to the feed surge drum. During normal operation, HS-013 is selected to set flow rate of FIC-001 to UC024.

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Figure 13: Feed Injector Distribution Control Page 80 of 323


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The feed dispersion steam injected at each of the feed nozzles I-1501 A/B/C/D/E/F to mix with the feed is flow controlled by 6 controllers FIC-005 A/B/C/D/E/F (1 per feed nozzle) acting on their respective steam inlet valve FV005 A/B/C/D/E/F. The total flow of MP steam supplied to the feed injectors is computed and displayed via FI-005.

3.1.3. UC-028 MTC INJECTOR MTC (Mix Temperature Control) injectors I-1502A-D are provided above the feed injection zone to inject recycled heavy FCC naphtha. MTC plays an important role in the heat balance control and heavy feed vaporization. The key is to achieve a higher temperature in the fresh feed mixing zone. MTC injection is required for Maximum Gasoline Mode of Mixed Crude. MTC flowrate is set to maintain the desired temperature at the fresh feed injection point. A thermocouple located upstream of the MTC injectors measure the catalyst/vapor mixture temperature. The MTC Recycle flow to the 4 injectors I-1502 A/B/C/D is evenly distributed and controlled by the flow controllers FIC-010 A/B/C/D: A signal representing the flow of MTC recycle to the riser is sent by FI-009 to UC028, the late being the master controller for each individual controllers FIC-010 AD. UC-028 divides the flowrate signal from FI-009 by the number of MTC injectors (4) and sends the resulting value to each of the 4 flow controllers FIC-010 A/B/C/D as their new setpoint. Then FIC-010 A/B/C/D adjust the flow of MTC recycle to their respective injector by acting on FV-010 A/B/C/D respectively. The process variable of UC-028 is the output from UY-014. UY-014 calculates the total measured MTC flowrate to the riser with outputs from the 4 MTC injectors flow controllers FIC-010 A-D. Total measured flow= FIC-010A+FIC-010B+FIC-010C+FIC-010D Set value to FIC-010A= (Total measured flow by FI-009)/4 Set value to FIC-010B= (Total measured flow by FI-009)/4 Set value to FIC-010C= (Total measured flow by FI-009)/4 Set value to FIC-010D= (Total measured flow by FI-009)/4

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Figure 14: MTC Injector Distribution Control Page 82 of 323


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The MTC dispersion steam injected at each of the MTC injectors I-1502 A/B/C/D to mix with the MTC is flow controlled by 4 controllers FIC-005 A/B/C/D (1 per feed nozzle) acting on their respective MP steam inlet valve FV-005 A/B/C/D.

3.1.4. Riser Outlet Temperature Control The most critical control loop on the Reactor and Regenerator is the Riser Outlet Temperature Control TIC-010. The temperature should be controlled within ± 1°C of the setpoint. A thermocouple located near the outlet of the riser measures the reaction temperature. Since the temperature is a function of the amount of catalyst admitted to the riser by the Regenerated Catalyst Slide Valve SV-1501, the Riser Outlet Temperature controls the regenerated catalyst slide valve in order to provide sufficient flow of hot catalyst to maintain the riser at the desired temperature. Reaction temperature is basic to conversion of RFCC feedstocks. At the bottom of the regenerated catalyst standpipe the regenerated catalyst slide valve controls the flow of hot catalyst to the wye section at the base of the riser D1501. The Riser Outlet Temperature sets the position of the slide valve which regulates the flow of catalyst. The Regenerated Catalyst Slide Valve position can be set by either of the following temperature controllers: •

Riser Outlet Temperature Controller TIC-020

•

TIC-015 located above the Upper Steam Stripping Ring above the fluidized bed packing in the stripper section of the riser

The operator selects between these controllers via HS-004. In normal operation, the output of TIC-020 is selected. The output of the temperature controller TIC-020 is then sent to the low switch selector UY-020 which selects between this input and the output of the differential pressure controller PDIC-247. The later receives the measure of the differential pressure across SV-1501 by PDT-247. In the event the differential pressure across the slide valve falls to 0.1 bar then the signal from PDIC-247 will be selected by UY-020 in order to re-adjust the slide valve differential to its normal value (0.3 to 0.5 bar). Normal valve differential is essential to provide safe operation as well as stable control. Negative differentials should never happen. Note: In the event that PDIC-015 is less than 0.15 barg, then the output of PDIC-247 will be 0% to close SV-1501. The operator enables the low selector switch by means of HS-015 which has 2 positions: Enable/Disable. When HS-015 selects “Disable”, Low Selector Switch UY-012 will exclusively select the output of HS-004.

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The output of UY-012 is then sent to the software switch HS-028 which is used to select between this input and the output of the Software Hand Controller HIC-029 (which can be tuned in the range 0-100%). Software switch HS-028 has 2 positions: Auto & Manual: •

When AUTO is selected, then the output of HS-028, UY-017, is the signal from the low selector UY-017 and is sent to the PLC of the Regenerated Catalyst Slide Valve (Signal to UV-017).

•

In the case MANUAL is selected then the output of HS-028, UY-017, is the signal from the software hand controller HIC-029 and is sent to the PLC of the Regenerated Catalyst Slide Valve (Signal to UV-017).

HS-008 is used to activate the standby mode of the accumulator.

Figure 15: SV-1501

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A Riser Outlet Temperature (ROT) is chosen based on the type of feedstock processed and the type of yields distribution desired. The heat of reaction, the coke make, catalyst circulation rate, and the regenerator temperature change as the Riser Outlet Temperature is varied. The feed preheat temperature, MTC oil flow rate, can be manipulated to control these operating parameters within their optimum ranges. The optimum ROT operation varies with feedstock and operational goals. If the feed temperature is reduced, more hot regenerated catalyst will be required to heat the reaction mixture. The regenerated catalyst slide valve will open and the catalyst to oil ratio will increase. Coke make will increase because of the increased catalyst to oil ratio. The lower heat input into the RFCC, from the feed preheat exchangers will be made up by burning the extra coke. As the regenerator temperature increases the catalyst/oil ratio will find a new equilibrium. Thus, feed temperature can be adjusted to affect conversion at the expense of coke make. If the feed quality changes such that coke make begins to increase the regenerator temperature will rise and the regenerated catalyst slide valve will close slightly as it senses the increasing temperature of the riser outlet. The catalyst-to-oil ratio then decreases, conversion decreases, and coke make decreases. Although the unit is now in a new, stable, equilibrium operating point, an adjustment of some other operating variable may be necessary to maintain the desired product distribution at the new heat balanced level. If the percentage of residue in the feedstock gets too high there may be no remaining flexibility for the heat balance. In this case, coke make due to the nature of the feed becomes the predominant source of coke and changes in catalyst-tooil ratio have a smaller effect on overall coke make. In this case, an increase in the feed preheat may cause very high regenerator temperatures as the coke level builds up on the catalyst and significantly reduces the catalyst-to-oil ratio. Unacceptably poor conversion will result. If the MTC oil rate is increased, the Riser Outlet Temperature begins to decrease and the regenerated catalyst slide valve will open slightly as it senses the lower ROT. The catalyst-to-oil ratio then increases, mix zone temperature increases, conversion increases, and coke / slurry oil production decreases. When the set point of the riser outlet temperature is changed, the regenerated catalyst slide valve will immediately vary the catalyst-to-oil ratio to satisfy the new riser heat demand. Before the system reaches steady state and the regenerator equilibrates at a new temperature, the system will go through a transition stage due to the large catalyst inventory. During the transition, operating signals can be confusing. For example, a higher riser outlet temperature demands a higher catalyst circulation rate and a higher coke make. But the catalyst takes time to travel through the riser, disengager, stripper and the spent catalyst transfer line to reach the regenerator. The temperature in the regenerator will decline initially because of the immediate extra heat demand in the riser. Eventually, the unit will heat balance by producing more coke, and the regenerator temperature will rise. This higher temperature will cause the catalyst circulation rate to decrease. The system can eventually be returned to the optimal catalyst to oil ratio if the feed preheat temperature is adjusted to offset the additional riser heat demand.

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3.1.5. Catalyst Stripper Level Control The spent catalyst slide valve controls the catalyst stripper level by modulating the flow of spent catalyst from the catalyst stripper to the first stage regenerator. The catalyst level in the stripper is measured by differential pressure instruments and sends a signal to the controller which sets the position of the slide valve. A minimum level is required in the catalyst stripper to ensure good stripping of hydrocarbons from the catalyst and a seal at the diplegs outlet of the Riser Outlet Separation System.

Figure 16: SV-1502

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The selector HS-005 is provided to select between either of the level controller of the catalyst stripper LIC-002 and LIC-003. The Level controller output selected is then sent to the low signal selector UY-011 which selects between this input and the output from PDIC-103. The later receives the differential pressure across SV1502 as measured by PDT-103 as input. In the event the differential pressure across the slide valve falls to 0.1 bar then the signal from PDIC-103 will be selected by UY-011 in order to re-adjust the slide valve differential to its normal value (0.3 to 0.5 bar). Normal valve differential is essential to provide safe operation as well as stable control. Negative differentials should never happen. The software switch HS-014 is provided to enable or disable the low selector switch. HS-014 has only 2 positions: Enable and Disable. When HS-014 selects “Disable”, Low Selector Switch UY-011 will exclusively select the output of HS005. The output of UY-011, (in normal operating conditions: either of the level controllers of the catalyst stripper) is sent to the software switch HS-025 which is used to select between UY-011 output and the manual control of the slide valve via software hand controller HIC-025. Software switch HS-025 has only 2 positions, Auto & Manual: •

When AUTO is selected, then the output of HS-024, UY-015, is the signal from the low selector UY-011 and is sent to the PLC of the Spent Catalyst Slide Valve (Signal to UV-015). This way, in normal operation, the position of the spent catalyst slide valve is controlled by either of the level controller of the catalyst stripper.

•

In the case MANUAL is selected then the output of HS-024, UY-015, is the signal from the software hand controller HIC-025 and is sent to the PLC of the Spent Catalyst Slide Valve (Signal to UV-015).


3.1.6. Catalyst Regenerators Level Control The level in the first stage regenerator is measured by a differential pressure instrument LT-004 and is sent to the level controller of the 1st stage regenerator LIC-004 which resets the position of the air lift plug valve PV-1501. The plug valve modulates the flow of catalyst from the first stage regenerator into the lift to the second stage regenerator. A minimum level must be maintained in the first stage regenerator to ensure good regeneration and to seal the cyclone diplegs. A low level in the regenerator may unseal the diplegs which could result in backflow of flue gas up the diplegs and loss of catalyst fines with the flue gas. A high level in the first stage regenerator can also result in catalyst carryover from the cyclones because of higher entrainment from the bed and re-entrainment from the cyclone dust bowls.

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During normal operation, the second stage regenerator level LIC-007 is not controlled, but follows the unit inventory. This level is monitored and adjusted by continuous withdrawal as the level builds through catalyst addition. The level in the second stage regenerator must be held within certain limits for the same reasons as stated above for the first stage regenerator.

Figure 17: Air Lift Plug Valve PV-1501 Control In normal operation, the air lift plug valve is controlled by LIC-004, however, HS004 is provided to select between LIC-004 and LIC-007. The output of HS-006, (=output of LIC-004 in normal operation) is then sent to the software switch HS026 which is used to select between this input and the manual operation of the plug valve PV-1501 via HIC-027. Software switch HS-027 has only 2 positions, Auto & Manual: Page 88 of 323


•

DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

When AUTO is selected (=normal operation), then the output of HS-026, UY-016, is the signal from the low selector UY-006 and is sent to the PLC of the Air Lift Plug Valve (Signal to UV-016). This way, in normal operation, the position of the spent catalyst slide valve is controlled by either of the level controller of the catalyst stripper.

•

In the case MANUAL is selected then the output of HS-026, UY-016, is the signal from the software hand controller HIC-027 and is sent to the PLC of the Air Lift Plug Valve (Signal to UV-016).


3.1.7. Catalyst Regenerators Pressure Control The regenerators pressures are controlled by flue gas slide valves SV-1503/1504 which throttle the flow of flue gas from the vessels. The pressure of the first stage regenerator is directly controlled by the first regenerator flue gas slide valve SV-1503 with PIC-146.

Figure 18: First Regenerator Flue Gas Slide Valve SV-1503 Control Page 89 of 323


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The output of the pressure controller PIC-146 located at the top of the 1st regenerator D-1502 is sent to the software switch HS-030 which is used to select between this input and the manual operation of the slide valve via HIC-031. In normal operation, PIC-146 controls the operation of the slide valve SV-1503 and its output is sent to UY-018, which forwards 2 identical signals, UY-018 A and UY018 B and identical to the selected signal in HS-030, to the PLC of the double disc slide valve (UY-018A is sent to UV-018A and UY-018B is sent to UV-018B). This way PIC-146 commands both discs of the slide valve SV-1503. Software switches HS-040 A and B are provided to activate the standby mode of the valve accumulator A & B respectively. The differential pressure PDIC-172 between the first stage and second stage regenerators is controlled by the second regenerator flue gas slide valve SV-1504. This differential pressure is set to provide adequate pressure drop across the plug valve PV-1501 for stable control of the regenerators levels.

Figure 19: 2nd Regenerator Flue Gas Slide Valve SV-1504 Control Page 90 of 323


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PDIC-172 measures and controls the differential pressure between the top of the 1st regenerator and the bottom of the 2nd regenerator. The output of PDIC-172 is sent to the software switch HS-032 which is used to select between this input and the manual operation of the slide valve via HIC-033. In normal operation, PDIC-172 controls the operation of the 2nd regenerator slide valve SV-1504 and so its output is sent to UY-019. The later forwards 2 identical signals, UY-019 A and UY-019 B and identical to the selected signal in HS-032, to the PLC of the double disc slide valve (UY-019A is sent to UV-019A and UY-019B is sent to UV-019B). This way PDIC-172 commands both discs of the slide valve SV-1504.

3.1.8. Disengager Pressure Control The disengager pressure rides on the main fractionator pressure which is controlled at the main fractionator overhead receiver D-1514. The objective in operation is usually to set the main fractionator pressure to a base level for efficient operation and the regenerator vessel pressures to result in approximately equal differentials across the catalyst slide valves.

3.1.9. Catalyst Regeneration Air and Total Flue gas to Stack Control The pressure of blower air to the 1st Regeneration Air Heater H-1501 is controlled by PIC-311 located at the blower discharge and acting on the pressure valve PV311 on the blower air line to H-1501, upstream of the 1st regenerator air ring assisted check valve CV-1501. The flow of air to H-1501 is monitored by FIC-161 (Venturi Tube) just upstream of PIC-311. The output of FIC-161 is sent to the air blower C-1501 speed controller SC-803 via the selector unit HS-827. The flow of blower air to the 2nd regeneration air heater H-1502 is controlled by FIC-164 (Venturi Tube) with FV-164 on the air blower line to H-1502, upstream of the 2nd regenerator air ring assisted check valve CV-1502. The flow of blower air to the air lift plug valve PV-1501 of the first regenerator D1502 is controlled by FIC-166 (Venturi Tube) with FV-166 on the air blower line to PV-1501, upstream of the air lift assisted check valve CV-1503. The flow of blower air to the withdrawal well is controlled by FIC-169 with FV-169 on the blower air line to the withdrawal well. All above mentioned flow controllers are pressure and temperature compensated by PIC-311 and TI-821 respectively. The total Regeneration Air Flow is calculated by FI-162 which receives the signals from FIC-161, FIC-164, FIC-166 and FIC-169 as inputs: FI-162 (PV) = FIC-161(PV) + FIC-164(PV) + FIC-166(PV) + FIC-169(PV)

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The total flue gas to RFCC stack is calculated by the summing device UY-110 in order to monitor the emissions. The Total Flue Gas from COB H-1503 is calculated as per the following: [Flue Gas from COB] = FI-902(PV) + FI-920(PV) + FI-923(PV) + FI-908(PV) [kg/h] •

FI-902: Total combustion air to COB (kg/hr)

•

FI-920: Total fuel gas used for COB combustion (kg/hr)

•

FI-923: Total fuel oil used for COB combustion (kg/hr)

•

FI-908: Total MP Steam used for atomising COB combustion (kg/hr)

The total Regeneration air is calculated from FI-162 by multiplying with a factor to take into account air to the flue gas from the regeneration section as coke burning in the regenerators, and by converting from Nm3/h to kg/h. UY-110 calculates the total flue gas flow by summing the total regeneration air flow and the flow of flue gas from H-1503. The total flue gas flow is then displayed by FI-110 which converts the results from kg/h to Nm3/h.

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Figure 20: Regeneration Air and Total Flue Gas to Stack

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3.1.10. Catalyst Draw-Off Control The catalyst draw-off system allows the transfer of equilibrium catalyst from the 1st regenerator to the spent catalyst hopper. The hot catalyst is withdrawn through ON/OFF valve UV-021 actuated by timer and cooled down through a finned pipe. The catalyst flow rate is set by a Restriction Orifice RO-161. For catalyst conveying and line cleaning, plant air is injected into the catalyst line downstream of the restriction orifice by another ON/OFF valve UV-023 actuated by timer. The total amount of catalyst withdrawal is adjusted by the timer setting taking into account the operation requirement for overall catalyst balance. One cycle of catalyst draw off is fixed at 60min. The total daily amount of catalyst withdrawal is adjusted by timer HIC-018 setting taking into account the operation requirements for the overall catalyst balance.

Figure 21: Catalyst Draw Off Control

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•

HIC-018: Set Point of Opening Time (Range: 0 – 30 min/cycle). This setting value is used for timer set point of T-2 and T-4 (see DCS sequence below).

•

HIC-042: Set Point of Frequency (Range: 3 – 24 cycle/day (Integer number only to be used)) .This setting value is used for timer set point of T-5 (see DCS sequence here after).

The sequence can be stopped locally with HS-043 or remotely with the DCS software switch HS-044. The flow of catalyst to the catalyst hopper is monitored via TI-029. In the event of high temperature alarm from TI-029, then the drawoff sequence will also be stopped. DCS Draw-Off Sequence: (1) Sequence Start Sequence shall be started by activation of HS-043 at local panel. (2) Timer Setting T-1: Timer of Cleaning (UV-021: Close, UV-022: Open, UV-023: Open) T-1 = 5min This timer is started when HS-043 is activated or T-5 is up. When timer T-1 is up, T-2 will start. T-2: Timer of Conveying (UV-021: Open, UV-022: Open, UV-023: Open) T-2 = HIC-018 (Set Point) [min] When timer T-2 is up, T-3 will start. T-3: Timer of Cleaning (UV-021: Close, UV-022: Open, UV-023: Open) T-3 = 5min When timer T-3 is up, T-4 will start. T-4: Timer of Free of Catalyst T-4 = 60 – (T-1) – (T-3) - HIC-018 (SP) [min] When timer T-4 is up, T-5 will start. T-5: Timer of Interval T-5 = {{24 – HIC-024(SP)} x 60} / HIC-024(SP) [min] When this timer is up, T-1 will start. (3) Sequence in Progress Total time of conveying will be shown on DCS graphic, when sequence is in progress. This total time will reset at the end of the day. HIC-018 and HIC-042 can be changed during sequence in progress. New setting will be applied to the next cycle. Page 95 of 323


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(4) Sequence Stop The causes of sequence stop can be: •

HS-044: Normal Stop

•

TAH-029: Temperature High

•

Valve Discrepancy Alarm (UV-021/022/023)

When sequence is stopped by any of the above events, the sequence goes to cleaning mode (UV-021: Close, UV-022: Open, UV-023: Open) for 5min, then, all valves (UV-021/022/023) will be in the closed position and sequence will stop, then skip to the end (T0). The sequence will start, only when HS-043 is activated.

3.1.11. Slurry Pumparound Return Control The purpose of this control is to maintain a constant total flowrate of hot slurry pumparound bypass to the grid of Bed #5 of the main fractionator. It is essential to have an adequate flow to the grid of No.5 bed to ensure good distribution, and maintain liquid flow on the bed to minimize coking-up of the packing bed. The hot by-pass flow by FIC-426 and HIC-427 allow for this constant flow to the grid whistle permitting changes in heat removal from the heat exchangers.

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Figure 22: Catalyst Draw Off Sequence Page 97 of 323


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3.1.12. Feed Pumps Automatic Start-up The feed pump P-1501 A or B on standby is automatically started when Low low flow alarm FALL-404 at the pumps discharge is activated. HS-401 is provided for the duty/standby selection.

3.1.13. UY-405, Slurry Pumparound (PA) Return Control The purpose of this controller is to maintain the total flow rate of Slurry PA return to Bed No.5 of the main Fractionator. It is essential to have adequate flow to the grid of No.5 bed to ensure good distribution, and maintain liquid flow on the bed to minimize coking-up of the packing bed. The hot by-pass flow by FIC-426 and HIC-427 allow for constant flow to the grid whistle permitting changes in heat removal from the heat exchangers. The total flowrate of Slurry PA is set by the operator via the software hand controller HIC-427. This value is sent to UY-405 which also receives the following signals: •

FI-539 output: Total flowrate of slurry pumparound from the 2nd feed preheat slurry exchangers E-1501 A/B returned to the grid. The flowrate of slurry pumparound leaving E-1501 A is controlled by FIC-406 with FV-406 on the slurry returned line to the PA return header. Meanwhile, the flowrate of LCO pumparound leaving E-1501 B is controlled by FIC-501 with FV-501 on the slurry returned line to the PA return header. The output of FIC-406 and FIC-501 are summed in UY-539 and the result is sent to FI-539, which in turns forward the total slurry PA return flowrate to UY-405.

•

FIC-408 output: FIC-408 controls the flow of slurry pumparound leaving the last feed preheat slurry exchanger E-1501 A with FV-408 on the slurry PA return line to the PA header.

•

FIC-425 output: FIC-425 controls the flow of slurry pumparound flowing through the HP steam generators E-1503 A/B/C with FV-425 located on the return line to the pumparound header.

•

FIC-440 output: FIC-440 controls the flow of slurry pumparound leaving the MP steam generators E-1505 A/B and flowing through the slurry pumparound header back to the bed #5 of the main fractiontator.

The output of FI-539, FIC-408, FIC-425 and FIC-440 are summed in UX-405. The result of this summation is substracted to the total pumparound flowrate value set via HIC-427, which gives the setpoint of the hot bypass flow controller FIC-426. The later adjusts the position of FV-426 on the hot bypass line accordingly.

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Figure 23: Slurry Pumparound (PA) Return Control

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3.1.14. UC-414, E-1505 Slurry PA flow balance control The function of this controller is to balance evenly the slurry pumparound flow through the 2 branches of the steam generators: •

Branch A: E-1504A and E-1505A

•

Branch B: E-1505 adnd E-1505B

The basic function is that UC-414 selects the highest valve opening request. One of the flow control valves should then be fully opened by manual. The other valve will be then throttled as required to maintain equal flow through each exchanger train. The intent of the design is not to maintain a particular flow through the exchangers but to balance the flows through the exchangers. If there is an increase/decrease in flows downstream of these control valves then the flow rate through all exchangers will increase/decrease and the flow balancing will act to open to maximum one valve and throttle the others. As one valve is always fully open, the pressure drop through these control valves is always minimized. The operation of these valves should, therefore, not interfere with the downstream control.

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Figure 24: E-1505 Slurry PA flow balance control The flow of slurry leaving the MP steam generator E1505A is controlled by FIC438 with FV-438. The output of FIC-438 is sent to both the flow control valve FV438 and the summing device UY-410.

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The flow of slurry leaving the MP steam generator E1505b is controlled by FIC43y with FV-437. The output of FIC-437 is sent to both the flow control valve FV437 and the summing device UY-410. The controllers 015-FIC-437 and 015-FIC-438 can not be in Auto mode simultaneously: One of them must be in manual mode with its control valve fully open. UY-410 sums the flowrate of slurry pumparound through each of the 2 branches of E-1504 A/B and E-1505 A/B. The total flowrate obtained is then sent to the master controller UC-414 which divides it by the number of heat exchangers (2), to get the new setpoint of the flow controllers. The output of UC-414 is sent to FIC-438 or FIC-437 whichever is in auto mode. The flow controller in AUTO mode will in turn adjust the flow of slurry through its branch of the exchangers to half of the total flow measured, by means of its control valve. The slurry pumparound leaving the MP steam exchangers E-1505 A/B is then divided into 3 streams: •

Part of the slurry is sent to the slurry draw-off drum D-1515 on flow control by FIC-462 with FV-462 on the slurry draw-off line to D-1515 inlet. To maintain the normal level in the bottom of T-1501, the setpoint of FIC-462 is reset by the main fractionator bottoms level controller LIC-411.

•

Another part of the slurry leaving the MP steam generators E-1505 A/B flows to the quench zone of the main fractionator. The flow of slurry from E-1505 A/B sent to the quench zone is controlled by FIC-439 which is reset by the temperature controller TIC-439 of the main fractionator bottoms via software switch HS-426. HS-426 is provided to select either the flow control of the slurry PA to the quench from E-1505 A/B (FIC-439) or the flow control of the slurry PA to the quench from E-1503 A/B/C (FIC-424).

•

The last part of the slurry PA from the MP steam generators E-1505 A/B is sent back to the Bed #5 of the main fractionator via the PA return header. This slurry PA return flow is controlled by FIC-440 reset by the temperature controller TIC-443 on the Bed #4 of the main fractionator, via software switch HS-471. HS-471 is provided to select either the flow control of the slurry PA to the PA return from E-1505 A/B (FIC-440) or the flow control of the slurry PA to the PA return from E-1503 A/B/C (FIC-425).

3.1.15. UC-413, E-1503 Slurry PA flow balance control The function of this controller is to balance evenly the slurry pumparound flow through the 3 steam generators E-1503 A, B and C. The basic function is that UC-413 selects the highest valve opening request. One of the three flow control valves should then be fully opened by manual control. The other valves are then throttled as required to maintain equal flow through each exchanger train. Page 102 of 323


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The intent of the design is not to maintain a particular flow through the exchangers but to balance the flows through the exchangers. If there is an increase/decrease in flows downstream of these control valves then the flow rates through all exchangers will increase/decrease and the flow balancing will act to open to maximum one valve and throttle the others. As one valve is always fully open the pressure drop through these control valves is always minimized. The operation of these valves should, therefore, not interfere with the downstream control.

Figure 25: E-1503 Slurry PA flow balance control

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The flow of slurry leaving the slurry HP steam exchanger E-1503A is controlled by FIC-428 with FV-428 on the discharge line back to T-1501. The output of FIC-428 is sent both to its flow control valve and to the summing function UY-409. The flow of slurry leaving the slurry HP steam exchanger E-1503B is controlled by FIC-429 with FV-429 on the discharge line back to T-1501. The output of FIC-429 is sent both to its flow control valve and to the summing function UY-409. The flow of slurry leaving the slurry HP steam exchanger E-1503A is controlled by FIC-430 with FV-430 on the discharge line back to T-1501. The output of FIC-430 is sent both to its flow control valve and to the summing function UY-409. The controllers FIC-428, FIC-429 and FIC-430 can not be in Auto mode simultaneously: One of them must be in manual mode with its control valve fully open. UY-409 sums the flowrate of slurry pumparound through each HP steam generator. The total flowrate obtained is then sent to the master controller UC-413 which divides it by the number of heat exchangers (3), to get the new setpoint of each of the flow controllers. The output of UC-413 is sent to FIC-428, FIC-429 and/or FIC-430, whichever is in auto mode, as the new setpoint. The flow controller in AUTO mode will in turn adjust the flow of slurry through its HP steam generator to 1/3 of the total flow measured, by means of its control valve. Downstream of the slurry HP steam generators, the flow of slurry returned to the main fractionator is divided in 2 streams: •

Part of the slurry leaving the HP steam generators E-1503 A/B/C flows to the quench zone of the main fractionator on flow control by FIC-424. The later is reset by the temperature controller TIC-439 of the main fractionator bottoms via software switch HS-426. HS-426 is provided to select either the flow control of the slurry PA to the quench from E-1505 A/B (FIC-439) or the flow control of the slurry PA to the quench from E-1503 A/B/C (FIC-424).

•

Another part of the slurry leaving the HP steam generators E-1503 A/B/C is sent back to the Bed #5 of the main fractionator via the PA return header. This slurry PA return flow is controlled by FIC-425 reset by the temperature controller TIC-443 on the Bed #4 of the main fractionator, via software switch HS-471. HS-471 is provided to select either the flow control of the slurry PA to the PA return from E-1505 A/B (FIC-440) or the flow control of the slurry PA to the PA return from E-1503 A/B/C (FIC-425).

3.1.16. Steam Generation 3 Elements Control Three element controls are provided for the kettle type steam generators E-1503 A/B/C and E-1503 A/B. This scheme has the objective to control the level on the kettle steam generator at a constant set point, based on the high-pressure steam flow rate as major disturbance, like a feedfoward variable, that impact the level.

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Since the flow rate of steam increases, the level decreases, with the consequent action to increase the boiler feed water flow rate.

Figure 26: Steam Generation 3 Elements Control The summing function receives the linearized steam flowrate signal and adds or subtracts from the steam signal a signal which is the difference between the steam drum level controller output and a bias signal (the level setpoint) set at 50% signal. The resultant output signal from the summing function is the setpoint signal to the boiler feed water flow controller. The system is designed so that for every weight unit of steam make a weight unit of feed water is introduced and the level controller signal is only used to compensate for blowdown and error in steam to water ratio.

3.1.17. Split Range Control of Surge Drum The pressure of the following surge drums is maintained constant by means of split range pressure controller PIC-XXX with 2 control valves: One to admit fuel gas in the surge drum and the other one to vent off gas from the surge drum to the flare If the pressure inside the feed surge drum is lower than the setpoint of the pressure controller, Then the pressure controller will send an output in the low range (0-50%). In that case the control valve for fuel gas in will open while the control valve to flare will remain closed. The opening of control valve for fuel gas will increase when the output of the pressure controller decreases in the 0-50% range.

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If the pressure inside the feed surge drum is higher than the setpoint, then the pressure controller will send an output in the high range (50-100%). In this case, the control valve for fuel gas in will remain closed while the control valve to flare will open. The opening of the later will increase when the output of the controller increases (and so the pressure) in the 50-100% range.

Figure 27: Feed Surge Drum Pressure Control The above pressure control scheme is valid for the following drums: Drum Tag No.

Controller Tag No.

PV for Fuel Gas In

PV to Flare

D-1513

PIC-403

PV-403A

PV-403B

D-1515

PIC-468

PV-468A

PV-468B

D-1516

PIC-479

PV-479A

PV-479B

D-1517

PIC-475

PV-475A

PV-475B

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Drum Tag No.

Controller Tag No.

PV for Fuel Gas In

PV to Flare

D-1518

PIC-483

PV-483A

PV-483B

D-1519

PIC-489

PV-489A

PV-489B

D-1522

PIC-505

PV-505A

PV-505B

D-1523

PIC-510

PV-510A

PV-510B

3.1.18. Main Fractionator Pressure Control The main fractionator pressure is controlled at the reflux drum D-1514 via PIC-456 by speed control of the wet gas compressor C-1551 in the gas recovery section. A signal proportional to the pressure in the Main Fractionator Reflux Drum D-1514 is sent by the pressure controller PIC-456 to the software selector HS-702 which is used to select between this input and the output of the pressure controller PIC-068 at the Disengager section of the riser D-1501. In normal operation, the signal from PIC-456 is selected. HS-702 then forwards the selected signal to the speed controller SIC-861 of the wet gas compressor C-1551 in the gas recovery section. SIC-861 then adjusts the speed of C-1551 accordingly to maintain the adequate pressure in D-1514. Pressure is not a process variable from an operation point of view and is not adjusted to correct product specifications. The unit has been designed to operate with a pressure of 0.4 kg/cm²g in the fractionator reflux drum. This pressure sets the pressure in the reactor, where low pressure is desirable to achieve good feed vaporization. The output of the software selector switch is also routed to the low selector switch UY-701 which selects the lowest signal between this input and the output of the pressure controller PIC-707 at the gas outlet of the interstage KO drum D-1552 to the 2nd stage compressor. The lowest signal is then routed to the compressor antisurge control UC-861

3.1.19. HCO Pumparound Heat Removal Control The HCO pumparound provides heat to the debutanizer reboiler E-1560A/B and heavy naphtha stripper reboiler E-1509. Constant heat removal in the pumparound is controlled by controlling these 2 variables: •

Total pumparound flow with FIC-419 at the discharge of P-1508 A/B, which adjusts the HCO pumparound bypass flow by acting on FV-419 on the bypass line. This HCO pumparound bypass flow is routed directly to the PA return from the discharge of the HCO pumparound pumps.

•

Return pumparound temperature with TIC-446 located on the HCO PA return line to the Bed #3. The output of the temperature controller TIC-446 is used to reset the flow controller FIC-420, which controls the flow of HCO pumparound leaving the HCO Pumparound MP Steam Generator E-1523 with FV-420. The flow of HCO PA exiting E-1523 is measured and Page 107 of 323


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transmitted to FIC-420 by FT-420A in the high range and FT-420B in the low range.

3.1.20. HCO Recycle and HCO Recycle MP steam generator E-1508 For maximum distillate mode operation, HCO is recycled to the reactor feed after being cooled in the HCO recycle MP steam generator E-1508. The temperature of the cooled HCO is controlled via TIC-425 on the HCO outlet of E-1508 by adjusting the amount of HCO bypassing E-1508 with TV-425 on the bypass line. The differential pressure between the LCO inlet and outlet of the heat exchanger is controlled by PDIC-420 with PDV-420 on the LCO inlet line. The level in the MP steam generator is controlled and maintained constant by LIC408 cascaded on the flow controller FIC-415 of the BFW supply to the heat exchanger.

Figure 28: HCO Steam Generator Controls

3.1.21. HCO LP Steam Generator E-1510 Controls The temperature of the HCO leaving the LP steam generator E-1510 is controlled by TIC-474, at the HCO outlet of E-1510, cascaded on the pressure controller PIC-447 on the steam side of the HCO LPS generator E-1510. When the HCO temperature at TIC-474 is above the setpoint, then the setpoint of PIC-447 will be decreased to command the opening of the pressure valve PV-447 Page 108 of 323


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The level in E-1510 is controlled by LIC-435 cascaded on the flow controller FIC450, which adjust the flow of BFW fed to the LPS generator with FV-450.

Figure 28: HCO Steam Generator Controls

3.1.22. HCO Flushing Oil Pumps Auto-start Control HCO flushing oil is sent from the LCO HP steam generator E-1510 to the HCO flushing oil drum D-1518. From D-1518, HCO is pumped by the HCO flushing oil pumps P-1521 A/B to the HP flush oil header after being filtered in either of the HCO flushing oil filters F-1502 A/B. There are 2 HCO flushing oils pumps: •

P-1521 A is HP-LP steam backpressure turbine driven

•

P-1521 B is motor driven

The selection between these pumps is made via the software switch HS-404. The flow to the HCO flushing oil filters is controlled at the pumps discharge by means of FIC-461 which regulates the flow of HCO recycled back to the HCO flushing oil drum D-1518 with FV-461 on the spillback line.

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The minimum pressure at the pumps discharge is controlled by PIA-487: In case the pressure at the pumps discharge falls to the low pressure setting PAL-487, then the standby pump is automatically started. The turbine driven pump P-1521A is provided with 3 position switch (XHSO468/XHSC-468-XHSM-468) to have a similar function as HOA (Hand-Off-Auto) switch of motor. This function is configured as part of the ESD function UX-438 (see section 4) acting on the valve XV-468. Indeed, since this pump is steam turbine driven, the opening/closing of valve XV-468 in the steam inlet line drive this pump: •

When XHSO-468 is selected, then the valve will open, allowing the steam to flow through the turbine and so the pump starts.

•

When XHSC-468 is selected, then the valve XV-468 will close, thereby stopping the pump by cutting off the steam supply.

•

WhenXHSM-468 is selected, then the pump P-1561A will start remotely \.

The ESD trip logic UX-438 will take precedence over any manual valve open or remote (auto start) command.

Figure 29: HCO Flushing Oil Pumps Auto-Start

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3.1.23. LCO and Heavy Naphta Pumparound Heat Removal Control In a similar manner than the HCO PA heat removal, constant heat removal in the LCO pumparound is controlled by controlling these 2 variables: •

Total pumparound flow with FIC-417 at the discharge of P-1510 A/B, which adjusts the LCO pumparound bypass flow by acting on FV-417 on the bypass line.

•

Return pumparound temperature with TIC-452 (located on the LCO PA return line to the Bed #2) cascaded on the flow controller FIC-418 which controls the flow of LCO PA leaving the LCO PA BFW Heater E-1511.

In the same way, constant heat removal in the heavy naphta pumparound is controlled by controlling: •

The total pumparound flow with FIC-412 at the discharge of P-1514 A/B, which adjusts the LCO pumparound bypass flow by acting on FV-412 on the PA bypass line back to T-1501 Bed #1.

•

The return pumparound temperature with TIC-430 (located on the Heavy Naphta PA return line to the Bed #1) cascaded on the flow controller FIC414 controlling the flow of heavy naphta PA leaving the Heavy Napht Pumparound Cooler E-1521.

3.1.24. Heavy Naphta Product Draw-Off and T-1501 Overheads Temperature Control Heavy naphtha product is also drawn off with the heavy naphtha pumparound. The cut point between LCO and heavy naphtha is controlled by the temperature controller TIC-454 below the heavy naphtha draw tray. TIC-454 resets the heavy naphtha flow controller FIC-453 (via software switch HS-428) which controls the flow of heavy naphta leaving the unit with FV-453 downstream of the heavy naphta trim cooler E-1518. The cut point between heavy naphtha and overhead distillate is controlled by fractionator overhead temperature controller TIC-461 resetting reflux flow controller FIC-427 (via software switch HS-429) with FV-427 downstream of the Fractionator Reflux Pumps P-1516 A/B. HS-428 is provided to forward the output of TIC-454 either to FIC-453 (normal condition) or HS-429. HS-429 is provided to select between the output of TIC-461 (normal condition) and the one from HS-428. So alternatively, the heavy naphtha draw rate can be fixed on flow control and the temperature controller below Bed 1 can be switched to reset reflux flow via HS-428 and HS-429. For Maximum Distillate operation the overhead cut point is critical to ensure that the combined LCO flash point specification is met. Even with maximum reboiling of the heavy naphtha stripper T-1502, the flash point specification will not be met if the overhead cut point is too low. This temperature should be adjusted based on operating experience, in order to maximize total LCO product while meeting the flash point specification. Page 111 of 323


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3.1.25. Water Draw Off and Recirculation A water draw-off tray is provided below the top tray. In normal operation, water is continuously drawn off from the main fractionator. The flow of water draw-off is controlled by the software hand controller HIC-418 acting on the control valve LV416 located on the wash water line to E-1519. The normal overhead temperature is approximately 15°C to 20°C above the water dew point. If the column is operated at or near the overhead water dew point, water will condense (risk of corrosion). This can occur during start-up with the unit at turndown as the steam rates are not reduced proportionately to feed rate. In that case, water is drawn off under interface level control by LIC-416 acting on LV416. Software switch HS-417 is provided to select between the output of LIC-416 or the output of HIC-418 to control the opening of LV-416. Part of the wash water is recirculated from the boot of D-1514 back to the inlet of E-1519 on flow control by FIC-459 at the overhead sour water pumps P-1517 A/B discharge. Another part of the sour water from D-1514 boot is sent to the inlet of the wet gas compressor intercooler E-1551 on flow control by FIC-703, while the remaining sour water is sent to the SWS on flow control by FIC-456 at P-1517 discharge FIC-456 is reset by the interface level controller LIC-446 of D-1514.

3.1.26. Wet Gas Compressor Control The wet gas compressor operation is controlled by the pressure controller on the fractionator reflux drum, as described in the section 3.1.18 of this document. This pressure sets the operating pressure on the reaction section. The pressure controller is set at the normal value. It is not an operating variable for the gas plant and is not normally adjusted. The primary control on the compressor is speed control of the steam turbine within the operating speed range: In normal operation, the compressor speed is controlled by the pressure controller PIC-456 of the fractionator reflux drum D1514 which is cascaded on the compressor speed controller SIC-861 via HS-702. The secondary control is the spill-back control on the two compressor stages by UV-702 (controlled by the anti-surge controller UC-862) on the spillback line from the 2nd stage compressor back to the inlet of the wet gas intercooler E-1551. The compressor is protected from surge by the compressor anti-surge control system UC-861/862.

3.1.27. First Stage KO Drum D-1551 Level Control The liquid level on the drum D-1551 is controlled by starting/stopping the KO drum liquid pump P-1552 A/B based on the level controller LIA-701 of the KO drum:

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Figure 30: D-1551 Level Control The duty pump will be automatically started when LAH-701 is activated and stopped when LAL-701 is activated. HS-701 is provided for duty / stand-by selection.

3.1.28. Stripper The level in the HP separator Drum D-1553 is controlled by LIC-717, the output of which is used to reset the flow controller FIC-711 controlling the flow of stripper feed downstream of P-1553 A/B with FV-711. Correct operation of the stripper T-1552 is critical to the operation of the gas recovery section. The feed preheat temperature is controlled by TIC-723 on the feed outlet of the stripper feed preheater E-1555. TIC-723 controls the duty of E1555 by regulating the flow of heavy naphta leaving E-1555 with TV-723: If the feed temperature at the outlet of E-1555 is higher than the setpoint then TIC-723 will command the closing of TV-723. If the feed temperature is too low, there may be water condensation in the stripper. If it is too high it can reduce C3 recovery. The duty of the 2nd stripper reboiler E-1557 is controlled by the stripper overhead flow controller FIC-709 on the overhead line back to the stripper condensers E1554 A-D. FIC-709 reset the flow controller FIC-710 on the LCO pumparound inlet of E-1557, which adjust the flow of LCO entering the 2nd stripper reboiler with FV710 accordingly: In case the flow of stripper overheads is higher than the setpoint,

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then FIC-709 will decrease the setpoint of FIC-709 which will in turn reduce the opening of FV-710 to reduce the duty of the 2nd reboiler. If the reboil rate is too high, and hence the stripping rate, the primary absorber can be overloaded, resulting in reduced C3/C4 recovery. If the reboil rate is too low, the C2 and H2S rates going to the debutanizer will be too high. The set point of the stripper overhead flowrate should be adjusted to optimize C3 recovery, while maintaining acceptable H2S and C2 concentrations in the debutanizer overheads. As an alternative to controlling reboiler rate by the overhead flowrate, the reboiler duty can be fixed based on operating experience.

3.1.29. Debutanizer The debutanizer is designed to separate the LPG from gasoline. The two specifications to be met are the vapor pressure of the gasoline and the C5 content of the LPG. Additionally, there is an overall C4 recovery specification. Generally, if this recovery specification is met, the gasoline RVP specification will also be met. The column operating variables are the reflux rate FIC-721 and the reboiler duty: •

The overhead C5 specification is controlled by the temperature controller TIC-745 in the top section of the column (tray #8). The output of TIC-745 is used to reset FIC-721 which controls the reflux flow from P-1556 A/B with FV-721. Decreasing the temperature controller set point decreases C5 concentration in the LPG.

•

The reboilers duty is controlled by FIC-722 located on the HCO PA inlet of E-1560 A/B. FIC-722 maintains the duty of the reboilers by keep the flow of HCO PA constant with FV-722 on the HCO PA return line to the main fractionator. The reboilers duty should be set manually to obtain the gasoline RVP specification and/or the overall C4 recovery.

3.1.30. LPG Amine Absorber The LPG amine absorber removes H2S from the LPG prior to LPG treatment for the removal of mercaptans. The LPG-amine interface level above the top packed section is maintained by the interface level controller LIC-746 regulating the flow of rich amine leaving the absorber to the ARU. The lean amine flow entering the absorber is controlled by FIC-724 with FV-724 downstream of the lean amine cooler E-1566 to meet the H2S specification and also to maintain a maximum H2S to DEA mole ratio of 0.4 in the rich DEA.

3.1.31. Control Narrative for the Slurry Separator Package X-1504 The slurry separator is a system with 10 cylindrical modules. Special glass beads fill each module. High voltage is pressured to the internal of module. When slurry oil containing catalyst passes through the module, the catalyst particles are Page 114 of 323


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separated into positive/negative charge and transfer to the oil. Then the charges are absorbed by the glass beads (dielectric migration) while the slurry oil passes through the glass beads with minor pressure drop. This system is provided with a backflushing sequence using LCO. The control of the slurry separator system is as follow: 1. The system is ready to operate when 400 VAC power is applied to both local panels and 230 VAC is applied to the Unit Control Panel from either UPS #1 or UPS #2, or both. 2. The operator uses the Panelview Display Unit to input commands. Operator commands are: a) System Run b) System Stop c) Unit Bypass Select [1, 2, 3, 4, 5, 6, 7, 8, 9, 10] d) Alarm reset e) Overload Acknowledge The operator ca also set the Backflush Time, the High Voltage Delay Time and Pause Time. 3. When the operator issues a System Run Command, if there is no PLC fault alarm, then the PLC generates a Start Permissive Signal, and the Start Permissive Lights on both local panels are turned on. The system is now ready for automatic operation. The automatic operation is initiated by placing the Stop/Start switch in the Start Position at the local Panel. 4. When the Stop/Start Switch is placed in the Stop position, the system is inactive; all solenoids are de-energized and all high voltage power supplies are off. 5. When the Stop/Start switch is placed in the Start Position, after the Start Permissive is received, automatic operation of the system starts and will continue until stopped by one of the following: a) A system Stop command b) The Stop/Start Switch being placed in the Stop Position c) Loss of the Start Permissive Signal 6. With the system in automatic operation, each unit (module) is selected in sequence for an operational cycle. Each cycle proceeds as follow: a) For the unit selected, the high voltage is off and the feed solenoid and backflush solenoid are energized. Backflushing takes place until the backflush time expires. b) When the backflushing time expires, separation begins. The feed solenoid and the backflushing solenoid are de-energized and the high voltage delay time starts. Also, the unit count advances and the next unit in the sequence is selected. If any unit is bypassed, the system will advance to the next unit. Units are selected by the system in numerical order, with unit 1 following unit 10. Page 115 of 323


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c) As soon as the count advances, Pause Time starts. When Pause Time is complete the unit that was just selected will begin backflushing, thereby starting a new cycle. The process continues until stopped as described above. Whenever the Start/Stop Switch is in the Start position, all high voltage power supplies are monitored. If any of the power supplies indicates a high temperature, high pressure or overload, an alarm will be generated and the high voltage power supply for that module will not be allowed to turn on. In the case of an overload, an overload latch is set for that unit. The overload latch will reset when the overload is cleared, the unit is selected, the system is backflushing, and the operator issues an overload acknowledge command.

3.1.32. Tempered Water for E-1507 A-D Tempered water is provided from the tempered water surge drum D-1524 to the slurry clarified oil coolers E-1507 A-D, where it is used as cooling medium, by means of the tempered water pumps P-1528 A/B. Tempered water leaving E-1507 A-D is then cooled down in the tempered water air cooler E-1530 on temperature control of the water leaving E-1530 by TIC-525 acting the flow of water bypassing the cooler with TV-525 on the bypass line. The differential pressure across the cooler is controlled by PDIC-514 acting on PDV-514 in the water inlet line. Cooled tempered water is then recycled back to E-1507 A-D by means of P-1528 A/B. The flow of tempered water pumped to the slurry clarified oil coolers is controlled by FIC-487 which adjusts the amount of tempered water sent from the discharge of P-1528 A/B back to the pumps’ suction line with FV-487. The duty pump is selected by means of HS-488. In case of low low flow (FALL488) activated then the standby pump will automatically kick-in.

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Figure 31: Tempered Water Pumps Control RFCC Closed Drain Pumps P-1560 A/B Closed drain hydrocarbon liquid is collected in the RFCC closed drain vessel D1560, which is equipped with 2 vertical pumps P-1560 A/B (one on duty and one on standby) to empty the closed drain drum by pumping the slop oil to storage. Software switch HS-601 is provided to for standby/duty selection. Each pump P1560 A/B can be selected in manual or auto operation by means of MHS-601B and MHS-602B respectively. In AUTO mode, the standby pump will be automatically started when the high level alarm of the closed drain drum LAH-601 is activated and stopped when the low level alarm LAL-601 of the drum level controller LIC-602 is activated. Both pumps will be automatically stopped when the low low level alarm LALL-603 in the closed drain drum is activated.

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header. The amine recovered in D-1561 is then pumped to the ARU for regeneration by means of the pump P-1564 and on level control of the drum: P-1564 will automatically start when the high level alarm LAH-769 of the amine closed drain drum D-1560 is activated. Likewise, the pump will automatically stop when the low level alarm LAL-769 of the drum is activated. Also the pump will automatically stop in case the low low level trip LALL-774 is activated.

3.1.34. RFCC lift station No.1 & No.2 Pits Pumps Control Oily water from west area is collected in the No.1 Pit XP-1501 while oily water from east area is collected in the No.2 Pit XP-1502. The oily water is pumped from the pits XP-1501 and XP-1502 to the Effluent Treatment Plant (ETP) by means of P-1561 and P-1562 respectively. The pumps operated on level control of their sump just like for the amine closed drain drum D-1560: P-1561 starts automatically when the high level alarm of XP-1501 LAH-770 is activated and stops when the level in the sump has reached the low level setting of the level controller LIC-770, that is when LAL-770 is activated. The pump will stop in case the low low level alarm of the sump LALL-770 is activated Likewise, P-1562 starts automatically when the high level alarm of XP-1502 LAH772 is activated and stops when the level in the sump has reached the low level setting of the level controller LIC-772, that is when LAL-772 is activated. The pump will stop in case the low low level alarm of the sump LALL-772 is activated

3.1.35. Inter-Unit Controls & Interfaces 3.1.35.1. RFCC Feed Control The objective of the control of the atmospheric residue from the CDU to the RFCC to control the level in the bottom of the Main Fractionator of the CDU and route as much of the outgoing atmospheric residue to the RFCC as required.

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Figure 32: RFCC Feed Control The level in the Main Fractionator, T-1101 is controlled by a 3 way split range level controller 011-LIC-007 (direct acting): •

In the low range (0 -33%) the signal from 011-LIC-007 goes to 011LY-082, then to low selector 011-LY-007B, which selects between 011-LIC-007 and the feed requirement of the RFCC (015-LIC-402) to control the flow to the RFCC. Page 119 of 323


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•

In the mid range (33-67%) 011-LIC-007 resets the setpoint of 011-FQIC-026.

•

In the high range (67-100%) 011-LIC-007 resets the setpoint of 011-FQIC-027.

011-FQIC-026 and 011-FQIC-027 are parallel controllers used to regulate the flow of residue to storage. 011-FV-026 is a smaller valve than 011-FV027 and will normally be sufficient to control the amount of residue to storage whilst the RFCC is on-line. In the event that the RFCC is off-line then 011-FQIC-026 will be fully open and 011-FQIC-027 will control the flow to storage. The sum of flow of atmospheric residue to storage and RFCC is indicated to operator by signal 011-FI-065. The total flow of atmospheric residue is indicated to operator by signal 011-FI-167. The RFCC feed is controlled by a split range level controller 015-LIC-402, which takes flow preferentially from the CDU by cascading onto 011FQIC-029 via 011-LY-007B (low range output of the feed surge drum level controller). If there is not enough flow coming from the CDU (high range output of the feed surge drum level controller) then flow is taken from storage by acting on 015-FIC-402, flow controller in the line from storage.

3.1.35.2. Temperature of Lean Amine from the ARU The temperature of the lean amine fed from the Amine Regeneration Unit to the RFCC (and LCO HDT) is controlled such that there is a fixed minimum temperature differential between the fuel gas and lean amine in the Fuel Gas Absorbers T-1555 in the RFCC Unit (and T-2402 in the LCO HDT Unit).

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Figure 33: Temperature Control of Lean Amine from the ARU Page 121 of 323


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The ΔT between the temperature of the fuel gas entering the fuel gas absorber T-1555 from the FG Absorber Feed KO Drum D-1557 and the temperature of the lean amine fed to the top of the Fuel Gas Absorber is controlled by 015-TDIC-746. This ΔT is controlled by TDIC-087 in the LCO HDT. Signals from both 015-TDIC-746 in RFCC and 024-TDIC-087 in LCO HDT are directed to a low signal selector 019-TDY-019D in the ARU, in order to ensure that the lean amine temperature is always controlled at 5°C above the higher fuel gas temperature, to prevent hydrocarbon condensation. The lowest signal simultaneously acts on the control valves around the Amine Air-Cooler E-1904 via -019-TDY-019 A/B/C (direct acting for amine flow to aircooler and reverse acting for air-cooler by-pass valve so that one valve will close when the other opens). This arrangement will allow adjusting the required temperature difference with minimum flow/pressure variation of the lean amine supplied to the Refinery users.

3.1.36. Operating Parameters For the operating conditions of the RFCC refer to the following Process Flow Diagrams: 8474L-015-PFD-0010-101

Reactor / Regeneration Section – Case: Bach Ho

8474L-015-PFD-0010-102

Flue Gas Treatment Section – Case: Bach Ho

8474L-015-PFD-0010-103

Feed Section – Case: Bach Ho

8474L-015-PFD-0010-104

Fractionation Section – Case: Bach Ho

8474L-015-PFD-0010-105

Gas Recovery Section – Case: Bach Ho

8474L-015-PFD-0010-106

Material Balance Table – Case: Bach Ho MG

8474L-015-PFD-0010-107

Material Balance Table – Case: Bach Ho MD

8474L-015-PFD-0010-111

Reactor / Regeneration Section – Case: Mixed Crude

8474L-015-PFD-0010-112

Flue Gas Treatment Section – Case: Mixed Crude

8474L-015-PFD-0010-113

Feed Section – Case: Mixed Crude

8474L-015-PFD-0010-114

Fractionation Section – Case: Mixed Crude

8474L-015-PFD-0010-115

Gas Recovery Section – Case: Mixed Crude

8474L-015-PFD-0010-116

Material Balance Table – Case: Mixed Crude MG

8474L-015-PFD-0010-117

Material Balance Table – Case: Mixed Crude MD

3.2. Instrument List Refer to attached extracted instrument list: Unit 015 extracted instrument list.xls

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3.3. Main Equipment 3.3.1. Reactor Riser, Stripper, Disengager and Catalyst Stand Pipe The cracking reactions between the feed mixture and the catalyst take place in the riser, within the 2 sec. residence time. The riser is provided with (from bottom to top) •

Riser wye where the hot regenerated catalyst is injected from the withdrawal well

•

Riser Bottom Ring where MP steam is injected to fluidize the catalyst

•

4x Stabilization MP Steam injectors I-1503 A-D to promote smooth and homogeneous catalyst flow at the feed injection point.

•

6x Feed Injectors I-1501 A-F where the feed is finely atomized and mixed with dispersion steam

•

4x MTC injectors I-1502 A-D to inject recycled heavy naphta. The MTC plays an important role in the heat balance control and heavy feed vaporization. It is the key to achieve a higher temperature in the fresh feed mixing zone: With MTC, it is possible to raise the mix temperature while maintaining the Riser Outlet Temperature or even lowering it. Thus the optimum catalyst temperature, the target catalyst circulation, and the desired catalytic cracking reactions can be adjusted separately. The MTC technology offers the possibility of operating the feed injection zone at a higher temperature thereby promoting vaporization without reaching over-cracking conditions in the riser whose outlet is maintained at a lower temperature. MTC provides additional heat removal. Cooling is carried out by vaporization of the liquid hydrocarbons introduced at the MTC level.

•

Backflush Oil injector I-1504 for the slurry recycle

•

Riser Outlet Separator System (ROSS), located at the outlet of the riser, where the catalyst is quickly separated from the hydrocarbon / steam vapour.

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Riser Position

Vertical

Normal/MAX. Operating Temperature (°C)

772 / 815

Normal/MAX. Operating Pressure (kg/cm2g)

2.2 / 2.6

Design Conditions: Shell

350°C and 5.2 kg/cm2g

Internals

Normal/Max. Temperature (°C): 560 / 840

Insulation

Refractory Lining

Materials: Shell / Heads:

CS A516 Cr 70

Internals

Stainless Steel

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Figure 34: Reactor Riser Page 125 of 323


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Figure 35: injectors Arrangement

3.3.1.1. Riser Outlet Separation System The principle of the patented AXENS Riser Outlet Separation System (ROSS) is a symmetrical structure of separation chambers and collecting chambers alternatively arranged around the top of the riser. The separation chambers are connected in their upper section to the riser and the vapor + catalyst mixture follows a 45° turn downwards around an inlet baffle. The vapor outlets to the collecting chambers are located underneath the inlet baffle in the perpendicular direction of the incoming stream. This geometry provides simultaneously both the centrifugal effect and the inertial effect which are key factors for catalyst separation. Page 126 of 323


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The catalyst separated is collected in a hopper prolonged by a dip leg which achieves the necessary seal between the riser and the stripper vessel. The vapor exiting the separation chamber is then mixed in the collecting chamber with the steam evolved from the stripper vessel. The collecting chambers are then connected to a center pipe collector which distributes the vapor to the disengager cyclones for final catalyst separation. This system achieves in a single device an extra-short time of vapor disengagement of about 1 second (45° turn, no vortex) and an efficient catalyst separation in two chambers arranged in series. The main chamber which is the separation chamber itself and the secondary chamber which is the vapor collecting chamber providing an additional safety buffer volume for further catalyst disengagement in case of catalyst carry-over.

Figure 36: Cyclones Orientation

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Figure 37: Separator Arrangement

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3.3.1.2. Catalyst Stripper The purpose of this section of D-1501 is to strip the catalyst exiting the ROSS with steam to reduce coke yield. In order to provide an efficient stripping, the stripper is provided with the following steam rings: •

Pre-stripping steam ring (I1 on the figure) located immediately at the exit of the separator diplegs

•

Upper Stripping Ring (I2 on the figure) located just upstream of the fluidized bed packing

•

Stripper Main Ring (I3 on the figure) located just downstream of the fluidized bed packing

•

Lower Stripping Ring (I4 on the figure) located at the bottom of the stripper to achieve a stable fluidization at the inlet of the spent catalyst standpipe.

•

The steam rate for this ring is part of the total steam required for good stripping but its prime function is to aerate the catalyst entering the spent catalyst standpipe. This is important for adequate head build-up to maintain an adequate slide valve differential pressure for controlling the stripper level.

The stripper is also provided with a fluidized bed packing allowing for cross and counter current flow of steam and catalyst and enhancing the contact between the catalyst and the steam. Stripper Position

Vertical


525 / 545


2.2 / 2.6



Internals


Insulation

Refractory Lining


CS A516 Cr 70

Internals

CS A516 Cr 70

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Figure 38: Stripper Arrangement Page 130 of 323


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3.3.2. 1st Stage Regenerator D-1502 The purpose of the 1st stage regenerator is to burn part of the coke by combustion air from the air rings provided at the bottom of the vessel. Combustion air to the first stage regenerator D-1502 is split between two air rings: The outer air ring and inner air ring, which are designed to handle about 70% and 30% of the combustion air to the first stage regenerator D-1502 respectively. This regenerator operates in a counter current (air in at bottom and spent catalyst in at top) mode which helps prevent catalyst overheating. The regeneration conditions are mild to limit hydrothermal deactivation of the catalyst. First stage regenerator total combustion air is controlled to limit the temperature in the first stage to maximum 730°C. The first regenerator D-1502 is equipped with an air lift to transfer the catalyst from the bottom of D-1502 to the 2nd regenerator D-1503. The flow of catalyst transfer is regulated by means of the air lift plug valve PV-1501 (see special valves) A set of 6 two-stage cyclones is provided at the top of the first stage regenerator to separate entrained catalyst from the flue gas leaving D-1502. A double-disc flue gas slide valve (SV-1503) is provided at the outlet of the 1st stage regenerator to reduce the pressure of the flue gas upstream of the CO Combustor H-1503. 1st Stage Regenerator D-1502 Position

Vertical


678 / 730


2.28 / 2.68



Internals


Insulation

Refractory Lining


CS A516 Cr 70

Internals

SS A240-304H

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Figure 39: 1st Stage Regenerator Page 132 of 323


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Figure 40: 1st Stage Regenerator Two-Stage Cyclones Arrangement

3.3.3. 2nd Stage Regenerator D-1503 In the 2nd stage regenerator, the partly regenerated catalyst from D-1502 is completely regenerated to less than about 0.05% by means of combustion air and at more severe conditions than in D-1502. The combustion air is provided at the bottom head of the regenerator. A set of 4 external refractory lined cyclones CY-1504 A-D are provided to remove entrained catalyst from the 2nd stage flue gas. This design expands the operating envelope for regenerator temperatures. The cyclone dip legs are external to the Page 133 of 323


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regenerator. Catalyst recovered in the cyclones is returned to the regenerator bed below the normal operating level by way of the diplegs. Aeration is supplied to the diplegs to provide for smooth fluidized catalyst flow and the diplegs outlets are equipped with flapper (trickle) valves to prevent catalyst and gas backflow into the cyclones. At the flue gas outlet of the 2nd stage regenerator is provided a flue gas double disc slide valve SV-1504 to control the pressure of the flue gas flowing to the waste heat boiler H-1503. 2nd Stage Regenerator D-1503 Position

Vertical


772 / 815


1.30 / 1.70



Internals


Insulation

Refractory Lining


CS A516 Cr 70

Internals

SS ASTM A240-304H

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Figure 41: 2nd Stage Regenerator Page 135 of 323


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Figure 42: 2nd Stage Regenerator Cyclones

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Figure 43: 2nd Stage Regenerator Cyclones Arrangement

3.3.4. Aeration and Fluidization Systems The catalyst fluidization and aeration systems play a vital role in the stability of catalyst circulation. The standpipe aeration systems on the unit are designed to handle a wide range of conditions and still provide the smooth, stable, catalyst flow required for proper operation. This is essential for stable and adequate catalyst slide valve differentials. The system includes aeration points located along the vertical portions of the standpipes with a rotor meter or flow orifice provided for each tap. The flows to the taps are initially set equally to replace the volume of interstitial gas compressed by head pressure. Page 137 of 323


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It is important to note the difference between aeration and fluidization systems: •

Aeration is the process of replacing, with the injection of gas, the volume lost to compression by head pressure in a column of fluidized catalyst. Aeration medium is necessary to keep the catalyst from becoming non fluidized and developing unstable flow characteristics. The taps on standpipes are located such that there are twice the numbers required for an adequate aeration. If one becomes plugged the neighboring tap will continue to ensure stable operation.

•

Fluidization taps are employed when the direction of catalyst flow changes. In the R2R unit, 45° angle changes are used to redirect catalyst flow whenever possible. As the catalyst flows into a 45° line the fluidization media is injected to assist in the turn. On the other hand, when catalyst flows from a 45° line, the fluidization media is added to smooth the turn and to penetrate the denser catalyst layer at the wall to allow easier entrance. A smooth, stable flow of catalyst into vertical standpipes is very important. Therefore, fluidization taps are either doublets or triplets

Two locations merit special notice: •

The regenerated catalyst standpipe handles catalyst without any coke and is at high temperatures. Catalyst at these conditions is inherently more difficult to maintain fluidized.

•

The second location to note is the second stage cyclone dip leg aeration. Instrument purges provide a large part of the required aeration. The fluidization in the slanted portions of the diplegs is very important. The penetration of the dense catalyst layer near the regenerator wall is necessary to ensure smooth flow of fines returning to the regenerator. Without proper aeration in the diplegs the cyclones may flood and catalyst losses will increase.

3.3.5. Special Valves Two types of valves are used in the R2R process: catalyst slide valves and plug valve. Slide valves are carefully designed with abrasion resistant protection for improving the valves reliability. Internal insulation allows to use carbon steel for the body of the valves. The valves are provided with appropriate purges, on the stem and body, to clear catalyst particles from the valves. Internal inlet shapes are designed to provide smooth operation. The plug valve design includes a stuffing box, an insulation sleeve and an air purge which provides efficient protection against catalyst blockage. Thrust limiter and seat and plug angles have been optimized to overcome the thermal expansion of the air lift. All valves are provided with independent hydraulic oil system to ensure a reliable and stable operation.

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Regenerated Catalyst Slide Valve SV-1501 Location

Bottom of withdrawal well

Fluid

FCC Catalyst

Purpose

To regulate the amount of hot regenerated catalyst flowing from the withdrawal well to the reactor riser, thereby controlling the reactor outlet temperature.

Direction of Flow

Vertical Down

Inlet Pressure (kg/cm2g) Normal: 2.66 / Max.: 3.06 Pressure Drop (kg/cm2g) 0.48 Fluid Temperature (°C)

Normal: 712 / Max.: 815 Spent Catalyst Slide Valve SV-1502

Location

Bottom of spent catalyst stand pipe

Fluid

FCC Catalyst

Purpose

To control the level in the stripper D-1501 by regulating the flow of spent catalyst flowing from the bottom of the stripper to the 1st stage regenerator D-1502 via the spent catalyst stand-pipe.

Direction of Flow

Vertical Down

Inlet Pressure (kg/cm2g) Normal: 2.69 / Max.: 3.09 Pressure Drop (kg/cm2g) 0.41 Fluid Temperature (°C)

Normal: 545 (650°C for 6 hours during start-up) / Max.: 511 Flue Gas Double Disc Slide Valve SV-1503

Location

Flue Gas outlet of 1st regenerator

Fluid

1st Regenerator Flue Gas

Purpose

To reduce the pressure of the flue gas leaving the 1st stage regenerator to the CO combustor H-1503, thereby controlling the pressure in D-1502.

Direction of Flow

Vertical Down

Operating Temperature (°C)

678 / 730

Inlet Pressure (kg/cm2g)

Normal: 2.13 / Max.: 2.53

Outlet Pressure (kg/cm2g)

0.085

Valve Pressure Drop (kg/cm2g)

1.28 / 1.57

Variable Orifice Pressure Drop 0.765 / 0.875 (kg/cm2g) Total Pressure Drop (kg/cm2g)

2.045 / 2.445

Flowrate wet basis (kg/h)

Normal: 282,084 / Min.: 178,544 Page 139 of 323


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Flue Gas Double Disc Slide Valve SV-1504 Location

Flue Gas outlet of 2nd regenerator

Fluid

2nd Regenerator Flue Gas

Purpose

To control the 2nd stage regenerator pressure (and maintaining the adequate ΔP across the 2 regenerators) by regulating the flow of flue gas leaving D-1503 to the waste heat boiler H-1503.

Direction of Flow

Vertical Down


Normal: 772 / Max.: 840


Normal: 1.24 / Max.: 1.64


0.085

Valve Pressure Drop (kg/cm2g)

0.68 / 0.95

Variable Orifice Pressure Drop 0.475 / 0.605 (kg/cm2g) Total Pressure Drop (kg/cm2g)

1.155 / 1.555

Flowrate wet basis (kg/h)

Normal: 138,674 / Min.: 86,941 Air Lift Plug Valve PV-1501

Location

Bottom head of the 1st regenerator

Fluid

Combustion air from blower

Purpose

To control the catalyst level in the first regenerator by allowing the transfer of catalyst from the 1st regenerator to the 2nd regenerator.

Regenerator Pressure at valve Normal: 2.56 / Max.: 2.92 (kg/cm2g) Catalyst Flow (Ton/min)

Normal: 43.61

Pressure Drop (Catalyst Side) 0.35 (kg/cm2g) Catalyst Temperature (°C)

Normal: 646

Air temperature (°C)

Normal: 216 / Max.: 238

Air Flowrate (kg/hr)

47,832

Inlet Air Pressure (kg/cm2)

2.46

COB/WHB 1st Regenerator Flue Gas Block Valve and Bypass Valve BV-1501 A/B Fluid

Flue gas from the 1st regenerator

Service

This system of 2 valves is installed on the flue gas line coming from the first regenerator. It allows to isolate the Page 140 of 323


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COB/WHB 1st Regenerator Flue Gas Block Valve and Bypass Valve BV-1501 A/B COB/WHB and bypass the flue gas to the Electrostatic Precipitator in case of trip Operating conditions for Design Case (Mixed Crude Max Gasoline) Operating Temperature (°C)

Normal: 678 / Max.: 730


0.085


0.055

Valves Pressure Profile

Block Valve (A)

Block Valve (B)

Normal Situation (kg/cm2):

Nil

0.03

Trip Situation (kg/cm2g):

2.68

2.68

Flowrate wet basis (kg/hr)

282084

Catalyst Concentration in Flue 446.4 Gas (mg/Nm3) COB/WHB 2nd Regenerator Flue Gas Block Valve and Bypass Valve BV-1502 A/B Fluid

Flue gas from the 2nd regenerator

Service

This system of 2 valves is installed on the flue gas line coming from the second regenerator. It allows to isolate the COB/WHB and bypass the flue gas to the Electrostatic Precipitator in case of trip

Operating conditions for Design Case (Mixed Crude Max Gasoline) Operating Temperature (°C)

Normal: 772 / Max.: 840


0.085


0.055

Valves Pressure Profile

Block Valve (A)

Block Valve (B)

Normal Situation (kg/cm2):

Nil

0.03

Trip Situation (kg/cm2g):

1.7

1.7

Flowrate wet basis (kg/hr)

138,674

Catalyst Concentration in Flue 665.5 Gas (mg/Nm3)

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3.3.6. Air Heaters 2 air heaters H-1501 and H-1502 are provided downstream of the air blower C1501. The purpose of H-1501 and H-1502 is to preheat the combustion air supplied to the air rings of 1st regenerator and the 2nd regenerator respectively. In order to burn the coke off the spent catalyst. These heaters are also used during start-up of the plant to dry-out the regenerators as well as to heat-up the catalyst. H-1501 Heater Data Type

Air Heater – Horzontal

Type of Fuel Gas

Propane (LPG)

Air Allowable Pressure Drop (kg/cm2g)

0.05

Chamber External Diameter (mm)

2624

Chamber Length (mm)

6950

Internal Design Pressure (kg/cm2)

5.2

Internal Operating Pressure (kg/cm2g)

2.98

Design Temperature (°C)

350


BH MG

BH MG

MC MG

MC MD

Inlet

238

232

216

223

Outlet

651

636

683

646


180946

166001

261266

214783

Burner Data Number of Burners

1

Burner Type

Low NOx Forced Draft

Firing Position

Horizontal Fired

Connection to heater

Flanged

Design Burner Duty (MW)

46.57

Normal Burner Duty (MW)

44.36

MIN. Burner Duty (MW)

4.65

Excess Air at Design Capacity

20%

Max Flame Dimension (mm)

Length: 5500

Diameter: 1800

Pilot/Ignition Data Type

Forced draft with compressed air

Pilot Liberation (kW)

30

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H-1501 Fuel Gas Pressure Required (kg/cm2g)

0.5

Compressed air pressure required (kg/cm2g)

2

Ignition Method

High tension, by electric spark rod

Emission Levels NOx (mg/Nm3)

140

CO (mg/Nm3)

30

H-1502 Heater Data Type

Air Heater – Horzontal

Type of Fuel Gas

Propane (LPG)

Air Allowable Pressure Drop (kg/cm2g)

0.05

Chamber External Diameter (mm)

2000

Chamber Length (mm)

7800

Internal Design Pressure (kg/cm2)

5.2

Internal Operating Pressure (kg/cm2g)

2.03


350


BH MG

BH MG

MC MG

MC MD

Inlet

232

238

216

223

Outlet

713

695

762

712


38773

31685

79610

57261

Burner Data Number of Burners

1

Burner Type

Low NOx Forced Draft

Firing Position

Horizontal Fired

Connection to heater

Flanged

Design Burner Duty (MW)

14.22

Normal Burner Duty (MW)

13.55

MIN. Burner Duty (MW)

1.42

Excess Air at Design Capacity

20%

Max Flame Dimension (mm)

Length: 3500

Diameter: 1200

Pilot/Ignition Data Type

Forced draft with compressed air Page 143 of 323


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H-1502 Pilot Liberation (kW)

30

Fuel Gas Pressure Required (kg/cm2g)

0.5

Compressed air pressure required (kg/cm2g)

2

Ignition Method

High tension, by electric spark rod

Emission Levels NOx (mg/Nm3)

140

CO (mg/Nm3)

30

3.3.7. CO Boiler / Waste Heat Boiler Package H-1503 The purpose of the CO Boiler is: •

To completely convert as efficiently as possible the CO of the 1st regenerator into CO2. This conversion will be accomplished by firing auxiliary fuel gas in order to achieve the SOX emission specification.

•

To recover a maximum of heat from the resultant products of combustion, for the following services: o Preheating of the boiler feed water fed to the Economizer o Steam Generation of the CO Boiler itself o Superheating of the different steam production of the main fractionator section as required.

In case of emergency, the CO boiler can be bypassed while the unit is still operating at full capacity. H-1503 consists of the following elements: 1) CO incinerator with forced draft fans, where the CO contained in the flue gas fed from the 1st regenerator is converted into CO2 2) Waste Heat Boiler, where the flue gas from the CO incinerator is routed along with the flue gas from the 2nd regenerator. The Waste Heat Boiler recovers the heat of these flue gas streams to produce superheated HP and MP steam through the following elements: a. HP Superheater and HP de-superheater b. MP Superheater and MP de-superheater c. HP Generator d. Economizer e. Steam Drum D-1512 f. HP BFW Preheater E-1534

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The following elements are also provided in H-1503 package: •

Phosphate dosing package A-1502 comprising of the Phosphate tank A1502-TK-01 and the Phosphate injection pumps A-1502-P-01 A/B

•

Continuous and intermittent blowdown drums D-1531 and D-1532 respectively.

•

Stack

•

Water Sprayers

•

Flue Gas Block valves: o COB/WHB 1st regenerator flue gas block valve BV-1501 A o COB/WHB 2nd regenerator flue gas block valve BV-1501 B

•

Flue Gas Bypass valves o COB/WHB 1st regenerator flue gas bypass valve BV-1502 A o COB/WHB 2nd regenerator flue gas bypass valve BV-1502 B

The auxiliary burners and forced draft fans provided with H-1503 are designed for the production of 250 ton/hr of superheated steam under normal operation. One is motor driven for normal operation. The second one, in standby, is HP-LP back pressure turbine driven. Both blowers are equipped with auto-start device. Part of the generated superheated HP steam from H-1503 is supplied to the turbine driver of the forced draft fan.

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Design

DATE: 06/12/07

Normal

Start-up (Fres

CO Max

CO Min

Bach HO MG

Bach Ho MD

Mix Crude MG

Mix Crude MD

LPG/H2 rich fu gas firing only

Flowrate 9kg/h)

310292

310292

194650

178544

383084

231506

-

Temperature (°C)

730

730

641

631

678

646

-

Combustion Air (kg/h)

146,168

96674

224520

235302

140077

178120

315000 / 21116

Fuel / Normal Gas (kg/h)

703

1560

7621

8346

3788

5987

8072 / 3044

Heat Release (kW)

9260

20560

100100

109960

49900

78880

102300 / 70000

Total Flowrate (kg/h)

457163

408527

426790

439192

425948

415613

323073 / 21421

Temperature (°C)

1183

100

1178

1173

1130

1197

1000 / 1000

Residence Time (sec.)

0.9

1.1

1.0

1.0

1.0

1.0

-

CO content (mg/Nm3)

<300

<300

<300

<300

<300

<300

-

NOx content (mg/Nm3)

<1000

<1000

<1000

<1000

<1000

<1000

-

152541

152541

94603

86941

138674

114689

-

772

772

733

720

772

734

-

609,704

561068

521393

526133

564622

530302

323073 / 21421

N2

72.49

71.59

72.26

72.44

72.00

71.95

75.70 / 73.45

CO2

13.36

14.17

11.38

10.76

13.48

12.63

5.00 / 1.33

1st Regeneration gas

CO Oxidizer (CO Boiler)

2

nd

Regeneration Gas

Flowrate (kg/h) Temperature (°C) CO oxidizer + 2

nd

Regeneration Gas

Flowrate (kg/hr) Composition (mol %)

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DOC NO: 8474L-015-A5016-0000-001-005 REV: A

Design

DATE: 06/12/07

Normal

Start-up (Fres

CO Max

CO Min

Bach HO MG

Bach Ho MD

Mix Crude MG

Mix Crude MD


SOx

0.07

0.06

0.01

0.01

0.05

0.05

0.00 / 0.00

H2O

12.29

12.39

12.66

12.66

12.69

13.16

7.09 / 12.82

O2 CO

1.78

1.78

4.13

4.13

1.77

2.21

12.21 / 12.40

<300

<300

<300

<300

<300

<300

-

<1000

<1000

<1000

<1000

<1000

<1000

-

WHB Inlet

1080

938

1097

1098

1042

1097

1000 / 1000

WHB Outlet

326

309

318

314

318

313

297 / 280

Economizer Outlet

242

235

237

236

238

237

227 / 214

1st Regenerator gas inlet

1075 min

910 min

733 min

728 min

898 min

774 min

-

2nd Regenerator gas inlet

966 min

808 min

700 min

697 min

823 min

726 min

-

WHB inlet

923

767

680

679

787

701

220 / 98

WHB Outlet

728

616

534

528

624

551

172 / 76

Economizer Outlet

291

246

213

209

249

220

68 / 30

Economizer (kg/hr)

238600

183553

211153

211153

211153

211153

115696 / 76868

Generator (Total)

6949530

5346210

6150000

6150000

6150000

6150000

2528741 / 1691

Steam @ Generator Out

231651

178207

205000

205000

205000

205000

112327 / 74629

Import HP steam

61019

18092

10285

18092

61019

57527

-/-

NOx Flue Gas Temperature (°C)

Flue Gas Pressure (mm H2O g)

BFW & Steam Flowrate

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Design

DATE: 06/12/07

Normal

Start-up (Fres

CO Max

CO Min

Bach HO MG

Bach Ho MD

Mix Crude MG

Mix Crude MD


Total HP steam

292670

196299

215285

223092

266019

262527

112327 / 74629

Import MP Steam

14788

27666

8631

27666

14788

37331

-/-

Blowdown

6949

5346

6153

6153

6153

6153

3370 / 2239

Economizer Inlet

165

165

165

165

165

165

165 / 165

Economizer Outlet

219

222

216

214

219

214

214 / 212

Generator Inlet

257.7

257.7

257.7

257.7

257.7

257.7

257.7 / 257.7

HP steam Outlet

422

435

459

453

416

424

483 / 497

HP steam after desuperheater

380

380

380

380

380

380

380 / 380

MP steam Outlet

311

274

315

276

303

264

-

MP steam after desuperheater

250

250

250

250

250

250

-

BFW Preheater Inlet

50

50

50

50

50

50

50

HP steam after desuperheater

42.3

42.3

42.3

42.3

42.3

42.3

42.3

MP steam after desuperheater

14.1

14.1

14.1

14.1

14.1

14.1

-

BFW & Steam/Temperature (°C)

BFW & Steam Pressure (kg/cm2g)

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Heating Tube Design

HP superheater

MP superheater

HP generator

HP Economizer

Material (ASTM)

SA335 GrP9

SA106 GrB

SA 106 GrB

SA 106 GrB

PWHT

Yes

No

No

No

Tube type

Bare

Bare

Bare

Bare

Outside diameter (mm)

60.3

60.3

60.3

60.3

Thickness (mm)

6.35 Avg wall

5.54 Avg wall

5.54 Avg wall

5.54 Avg wall

Orientation

Vertical

vertical

Vertical

Horizontal

Layout

Staggered

Staggered

Staggered

Staggered

Flow pass No.

88

30

Screen: 192 / Main: 1536

34

Effective Length (m)

13.99

13.99

13.99

10.55

Number of tubes per row

22

30


34

Number of Row

16

4


26

Heating area (m2)

933

318


1769

Guide/Support Space (m)

2.4

2.3

2.4

2.3

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Steam Drum D-1512 Design Pressure (kg/cm2g)

49.92


283

Material Shell / heads (ASTM)

516 Gr.70

I.D. (mm)

2000

TL to TL Length (mm)

17500

Holding Time

5 minutes (NLL to Empty)

PSV

2 Burner

Number

5

Heat Release per Burner (kW)

23700

Turn Down / Gas

5:1

Turn Down / Oil

3:1

Gas Pressure (kg/cm2)

2.0 at burner

Oil Pressure (kg/cm2g)

10.3 at burner

Steam Pressure 9kg/cm2g)

11.3 at burner

Steam Consumption

265 kg/hr per burner for peak firing Fan

Number

2 (one operation + one standby)

Design/Normal Air Flow (kg/h)

315000 / 262500

Design/Normal Outlet Pressure (kg/cm2g)

1030/715

Operation range

120% to 30% (by volume)

Speed (RPM)

1485

BHP (kW)

683

Motor Rated (kW)

1230

Turbine (Rated / Normal) (kW)

1165 / 1059

Steam Consumption at rated (kg/h)

34300

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Soot Blower Type

Retractable

Number

52 Total

Min Clearance to Tube (mm)

550 MIN.

Max Row of Tube

8

Steam Consumption (kg/hr each)

4536

Motor (kW/each)

0.75

3.3.8. Electrostatic Precipitator X-1507 The Electrostatic Precipitator is provided to decrease catalyst dust from the flue gas from the Regenerator via COB/WHB package, to meet the environmental specification. The dust fine content at precipitator outlet shall not exceed 50 mg/Nm3 dry basis. The principle of operation is to provide high voltage electric for collection of dust by corona effect. The electrostatic precipitator comprises of 2 electrostatic precipitators (ESP), ESP 1 and ESP 2, in parallel and ash handling facilities. The flue gas inlet and outlet of each ESP is provided with an expansion joint and a motorized inlet damper. Dust laden flue gas from the waste heat boiler H-1503 is directed through the energized fields of the precipitator in which the discharge and collector electrodes are situated. A dedicated transformer rectifier se applies a variable, negative potential, high DC voltage to each field of the discharge electrodes. The collecting electrodes within each field are supported directly from the casing steelwork and are therefore at positive or earth potential. Each ESP of the package X-1507 comprises of 2 systems of discharge and collecting electrodes: first are the inlet discharge and collector electrodes, and downstream of them are the outlet discharge and collector electrodes. Each system is provided with its own dedicated transformer. Commencing from the minimum setting, the voltage is steadily increased until a current begins to flow from the discharge electrodes to the collecting electrodes. This is called “corona discharge”. Increasing the voltage further causes this current to rise until a maximum point is reached at which sparking or flashover occurs between the electrodes. The gas flowing between the electrodes becomes ionized by the corona current and the dust particles become negatively charged. The electrostatic field causes the charged particles to migrate to the earthed collector sheets where they adhere and give up their negative charge. The optimum electrical precipitator conditions are at the point where the voltage is just below that at which sparking takes place. A low rate of sparking is desirable and this is used as a basis for the design of the automatic voltage controller (AVC) that optimizes the output from each transformer rectifier set. The optimum voltage varies considerably with changing gas and dust conditions but the ESP will Page 151 of 323


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typically operate at 55 kV on clean ambient air and at between 50 kV and 65 kV on dust laden flue gases at normal operating temperatures. As dust cannot accumulate indefinitely on the discharge and collecting electrode systems without a loss of precipitator performance, they must be rapped on a regular basis. Each electrode (discharge and collector) within each ESP has its own individually sequenced rapping equipment comprising of a geared drive motor, chain driven cam shaft and a series of hammers arranged to operate singularly in sequence across the width of the precipitator. The dust released when the discharge and collecting electrodes are sequentially rapped falls into the hoppers below each respective field where the ash is collected and subsequently removed by an ash conveying system. Each ESP is provided with 4 hoppers, 2 for the inlet field and 2 for the outlet field. The dust is conveyed by means of air preheated in the steam air preheater X1507-E-01. The conveying air flows trough the bottom of each of the 8 hoppers in series. The dust collected is then sent to the bag filter X-1507-F-01 operated under a vacuum and provided with steam coil. Heated air is also provided from a steam air heater X-1507-E-02 to help remove any moisture from the dust. The heated air is sucked by the ash vacuum pumps X-1507-P-01 A/B to the air water separators X-1507-S-01 A/B where the separated water is finally sent to the oily water sewer. The dried dust retained by the bag filter then falls into the transfer hopper X-507TK-02 where it undergoes another stage of drying by means of heated air from X1507-E-02 and the a steam coil. The ashes finally falls into the Ash Storage Silo X-1507-TK-01, where ash is stored under warm and fluidized conditions by means of a steam coil and heated air introduced at the bottom of the silo. The ash storage silo X-1507-TK-01 is provided with a vent filter X-1507-F-02 and an exhaust fan X1507 to vent the air out of the silo. Ash is finally removed from the bottom of the silo and is discharged into flexible bags. There is a tendency for a small proportion of the liberated dust to be re-entrained into the gas flow during rapping and this is minimized by maintaining a low gas velocity within the treatment fields. Additional design features such as the use of vertical channel profiles on the collector electrodes, adjustable rapping intensity and reduced rapping frequency in the outlet fields also assist the overall efficiency of the precipitator. X-1507 Design Volume (Am/s)

301.18

Operating Gas Temperature (°C)

326

Gas Pressure in inlet duct (kg/cm2g)

0.055

3

Inlet dust load (mg/Nm ) (dry)

Normal: 370

Upset: 1700 mg/Nm3

Outlet Dust Emission (mg/Nm3) (dry)

Normal ≤ 50

Upset: 180 mg/Nm3 Page 152 of 323


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X-1507 One ESP: 200 Gas Moisture Content (% v/v wet)

12.30

ESP Pressure Drop (Flange to Flange) (kg/cm2g)

0.020

Casing design pressure (kg/cm2g)

0.200

3.3.9. Main Fractionator The purpose of the main fractionator T-1501 is to separate the different products contained in the effluents leaving the disengager/stripper D-1501 in the reaction section. The Main fractionator can be divided into 5 zones (from bottom to top): •

Slurry & Quench zone (bottoms)

•

Heavy Cycle Oil (HCO)

•

Light Cycle Oil (LCO)

•

Heavy Naphta (HVN)

•

Overheads (OVHD) Main Fractionator

Height (TL to TL) (mm):

64100

Internal Diameter (mm):

Top to bed #5: 7400

Internals:

5 beds + 30 trays

Bed Height (mm)

2000

Bottom: 3700

Packing Type / Material: Bed #1

Structured / 11/13 Cr

Bed #2

Structured / 11/13 Cr

Bed #3

Structured / SS TP 304

Bed #4

Structured / SS TP 304

Bed #5

Grid / SS TP 304

Trays

11/13 Cr

Loading Point:

Below bed #5 Bach Ho MG

Bach Ho MD

Mixed MG

Mixed MD

Bottoms temperature (°C)

340

340

340

340

Top Temperature (°C)

102

96

103

100

Bottoms Pressure (kg/cm2g)

1.15

1.15

1.15

1.15

Top Pressure (kg/cm2g)

0.85

0.85

0.85

0.85

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Main Fractionator T-1501 Section

Operating Temp. (°C)

Design Temp. (°C)

Insulation Thickness (mm)

Material

Bottom section, up to HCO PA return (top of Bed #3)

520

545

210

1 ¼ CR 0.5 Mo

Top of Bed #3 up to LCO PA return (top of Bed #2)

315

340

100

Carbon Steel

Top of Bed #2 up to HVN PA return (top of Bed 1)

215

250

60

Carbon Steel

Top Section

150

200

30

HIC Resistant Carbon

Figure 44: Main Fractionator Page 154 of 323


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3.3.10. Stripper T-1552 & Primary Absorber T-1551 In the primary absorber T-1551, most of the propane, propylene, butane and butylene are recovered from the gas stream fed from the high pressure separator drum D-1553. The overhead liquid from the bottom of the fractionation section is fed to the top tray of T-1551. For other than Bach Ho MG, gasoline is also recycle from the bottom of the bottom of the debutanizer in order to obtain the required recovery of C3 and C4. The purpose of the stripper T-1551 is to strip H2S, C2 and lighter from the LPG and gasoline mixture which is fed to the top tray from the HP separator D-1553. The heat required for stripping is provided by 2 reboilers in series, working on debutanizer bottoms (1st one) and LCO pumparound (2nd one). The primary absorber and the stripper are physically located in the same vessel, with T-1551 on top of T-1552. Primary Absorber T-1551 Height (TL to TL) (mm)

23700

Internal Diameter (mm)

2400

Number of trays / Type

31 / valve

Material

Shell / Internals: Wet H2S resistant CS Trays: 11/13 Cr

Parameter

Bach Ho MG

Bach Ho MD

Mixed MG

Mixed MD

FG Product Flow (kg/hr)

13817

12519

18619

14509

Liquid Flow Out (kg/hr)

160094

127834

159206

126788

Top pressure (kg/cm2g)

14.8

14.8

14.8

14.8

Bottom Pressure (kg/cm2g)

15.1

15.1

15.1

15.1


49

48

51

50

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Figure 45: Primary Absorber T-1551 Page 156 of 323


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Stripper T-1552 Height (TL to TL) (mm)

32360


Tray #1 to Tray#30: 3700 Bottoms: 5000

Number of trays / type

30 / valve

Material

Shell / Internals: Wet H2S resistant CS Trays: 11/13 Cr

Parameter

Bach Ho MG

Bach Ho MD

Mixed MG

Mixed MD

Flow IN (kg/hr)

297311

243294

295531

244437

Product Flow (kg/hr)

267774

220591

264456

220318

Ovhd Gas Flow (kg/hr)

29537

22703

31075

24119


15.7

15.7

15.7

15.7


16.0

16.0

16.0

16.0


59

60

59

20

Bottom Temperature (°C)

122

126

120

122

Page 157 of 323


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Figure 46: Stripper T-1552 Page 158 of 323


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3.3.11. Debutanizer T-1554 The purpose of the debutanizer is to separate LPG from the gasoline in the liquid stream fed from the stripper bottoms. The heat required for the separation is provided by the reboilers E-1560 A/B using HCO pumparound as heating medium. Debutanizer T-1554 Height (TL to TL) (mm)

34550


Tray #1 to #21: 3300 Tray #22 to #40: 4000

Number of trays / type

40 / Valve

Material

Shell / Internals: Killed Carbon Steel Trays: 11/13 Cr

Parameter

Bach Ho MG

Bach Ho MD

Mixed MG

Mixed MD

Stripper Bottoms Flow IN (kg/hr)

267774

220591

264456

220318

Reflux Flow IN (kg/hr)

113168

106325

107154

100630

Gasoline Flow (kg/hr)

190498

163547

187358

159741


11.7

11.7

11.7

11.7


12.1

12.1

12.1

12.1


68

68

68

68


178

171

180

172

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Figure 47: Debutanizer T-1554 Page 160 of 323


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3.3.12. LPG Amine Absorber The purpose of the LPG absorber is to remove H2S in the LPG stream from the debutanizer by contacting the LPG with lean amine (DEA) from the ARU. LPG and amine are flows in counter-current flow in this packed tower. LPG Absorber T-1556 Height (TL to TL) (mm)

14100


2700

Number of Packing Beds / Type

2 / PALL RINGS

Packing Beds Height (mm)

3500

Material

Shell: Wet H2S resistant Killed Carbon Steel Internals: Stainless Steel 304L Packing: Stainless Steel 304L

Parameter

Bach Ho MG

Bach Ho MD

Mixed MG

Mixed MD

LPG Flow IN (kg/hr)

77276

57044

77098

60577

DEA Flow IN (kg/hr)

31606

23331

31533

24776

DEA Flow OUT (kg/hr)

31631

23352

32055

25269

LPG Product Flow (kg/hr)

77251

57023

76576

60084


17.9

17.9

17.9

17.9


19.7

19.7

19.7

19.7

Temperature (°C)

50

50

50

50

Page 161 of 323


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Figure 48: LPG Absorber T-1556 Page 162 of 323


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3.3.13. Secondary Absorber T-1553 The purpose of the secondary absorber is to recover light fractions from the overhead gas fed from the primary absorber T-1551 by using heavy naphta from the fractionation section as lean oil. Lean oil and overhead gas flow counter in this tower. Secondary Absorber T-1553 Height (TL to TL) (mm)

17950


1400

Number of Tray / Type

20 / Valve

Material

Shell / Internals: Wet H2S resistant Carbon Steel Trays: 11/13 Cr

Parameter

Bach Ho MG

Bach Ho MD

Mixed MG

Mixed MD

Primary Absorber OVHD (kg/hr)

13817

12519

18619

14509

Lean Sponge Oil (kg/hr)

34993

34990

34996

34990


14.4

14.4

14.4

14.4


14.7

14.7

14.7

14.7


47

45

58

59


50

47

60

59

Page 163 of 323


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Figure 49: Secondary Absorber T-1553 Page 164 of 323


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3.3.14. Fuel Gas Absorber T-1555 The purpose of the fuel gas absorber is to remove H2S and CO2 from the gas fed from the secondary absorber by contact with lean amine (DEA) in counter current flow. The fuel gas absorber is provided with FG absorber feed KO drum D-1557 and FG absorber outlet KO drum D-1559 to remove any entrained/condensed liquid in the gas. The above 3 vessels are physically located in one unique vessel with T-1555 in between D-1557 (below T-1555) and D-1559 (above T-1555). Fuel Gas Absorber T-1555 Height (TL to TL) (mm)

18100


1300

Number of Tray / Type

20 / Valve

Material

Shell / Internals: Wet H2S resistant Carbon Steel Trays: Stainless Steel 304L

Parameter

Bach Ho MG

Bach Ho MD

Mixed MG

Mixed MD

Treated Fuel Gas OUT (kg/hr)

9812

8661

13231

9720

Lean Amine IN (kg/hr)

18776

18127

44919

40654

Rich Amine OUT (kg/hr)

19225

18630

46090

41743


13.7

13.7

13.7

13.7


13.9

13.9

13.9

13.9


56

56

55

55

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Figure 50: Fuel Gas Absorber T-1555 Page 166 of 323


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3.3.15. Slurry Separator The Slurry Separator is provided to decrease catalyst fine in the Fractionator Bottom and produce Clarified Oil for fuel oil production (backflush oil recycled to the riser). The design capacity is 30.7 ton/hr of slurry oil. The catalyst fine in the slurry oil is maximum 4,300 PPM at peak, and outlet catalyst fine maximum is targeting to 100 PPM. The Slurry Separator package consist 10 module filters with automatic backwashing facilities by flushing oil. Bach Ho MD

Parameter

Mixed Crude MG

Slurry

HCO Backflush

Slurry

HCO Backflush

Normal Flowrate (kg/hr)

27930

3000

30674

3000

Design Flowrate (% normal)

120

120

-


170

170 (controllable)

170

170 (controllable)

Operating Pressure (kg/cm2g)

12.9

4.5

12.9

4.5

Pressure Drop (kg/cm2g)

2.0

3.0

2.0

3.0

Sulphur Content (wt%)

0.1

1.03

Catalyst Fines Content (wt.ppm) Inlet (average)

1100-1700

Inlet (Peak)

4300

Outlet (Peak)

100

LCO For Cleaning Operating Temperature (°C)

150


220

Operating Pressure (kg/cm2g)

6.0

Design Pressure (kg/cm2g)

17.0

Page 167 of 323


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Figure 51: General Arrangement of X-1504

3.3.16. Air Blower, C-1501 The air Blower C-1501 is a centrifugal compressor to supply the necessary amount of air to burn all the coke off the catalyst and some of the resulting CO to CO2. Depending upon the mode of operation and other factors such as feed quality, the required air amounts to the regenerator is supplied from this Air Blower. The design capacity is 340,483 NM3/h, and 25 MW shaft power. The machine type is axial compressors with steam condensing turbine driven. The capacity of air flow rate is mainly controlled by speed of turbine. C-1501 is provided with an antisurge system. The manufacturer of the compressor is MAN TURBO AG, model: AG090.

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The major operating conditions are as follows: Parameter

Design

Mix MG

Mix MD

Bach Ho MG

Bach Ho MD

Flowrate (Nm3/h)

340,432

309,483

254,808

213,247

195,748

Suction Pressure (kg/cm2g)

1.008

1.008

1.008

1.008

1.008

Suction Temp. (°C)

36

36

36

36

36

Discharge Pressure (kg/cm2g)

4.66

4.26

4.26

4.26

4.26

Discharge Temp. (°C)

227

210

223

232

238

The following are design data for the turbine of C-1501: Parameter

Value

First Critical Speed of C-1501 (RPM)

2179

First Critical Speed of Turbine (RPM)

2324

Normal Speed (RPM)

4400

Rated Speed (RPM)

4,661 (100%)

Min. Continuous Speed (RPM)

3,263 (70%)

Max. Continuous Speed (RPM)

4,894 (105%)

Trip Speed (RPM)

5,383 (115%)

Page 169 of 323


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Figure 52: Combustion Air Blower Page 170 of 323


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3.3.17. Wet Gas Compressor C-1551 The Wet Gas Compressor is a multi-stage centrifugal compressor to boost-up the main fractionator overhead gas pressure from atmospheric level to 14-15 kg/cm2g for Gas Recovery Section. The machine consists two stages compressor, with external cooling (interstage cooler E-1551 and trim cooler E-1552). The Wet Gas Compressor is driven by condensing steam turbine. The driver capacity is 8,100 kW. The capacity is mainly controlled by turbine speed, and the wet gas compressor is provided with an anti-surge control system. The manufacturer of the wet gas compressor is Elliott/Ebara, Model: 56M81. The major operating conditions are as follows: Bach Ho MG

Parameter

Mixed Crude MG

Normal

Design

Normal

Design

Flowrate (Nm3/h)

65326

75127

67578

77715

Wet Flow (kg/hr)

138964

159809

139263

160152

MW

47.68

47.68

46.19

46.19

Suction Pressure (kg/cm2A)

1.33

1.33

1.33

1.33

Suction Temperature (°C)

1st Stage

41.9

41.9

41.9

41.9

2

Discharge Pressure (kg/cm g)

5.13

5.09

5.2

5.19

Discharge Temperature (°C)

96.5

97

98.7

99.5

Flowrate (Nm3/h)

43794

50363

48195

55424

Wet Flow (kg/hr)

80749

92861

86739

99750

MW

41.33

41.33

40.34

40.34

Suction Pressure (kg/cm2A)

4.43

4.39

4.5

4.49

Suction Temperature (°C)

41.9

41.9

41.9

41.9

Discharge Pressure (kg/cm2g)

17.1

17.1

17.1

17.1

Discharge Temperature (°C)

111.3

112

112

112.6

2nd Stage

The following are design data of the turbine of C-1551: Parameter

Value

Normal Speed (RPM)

5,134

Rated Speed (RPM)

5,458

Max. Continuous Speed (RPM)

5,731 Page 171 of 323


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Parameter

Value

Trip Speed (RPM)

6,304

st

DATE: 06/12/07

1 Critical Speed (RPM)

2,600-2,700

2nd Critical Speed (RPM)

11,000

Page 172 of 323


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Figure 53: Wet Gas Compressor Page 173 of 323


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TRAINING MODULE


Course Content: Section 1 - General Description Section 2 - Process Flow Description Section 3 - Process Control Section 4 - Safeguarding Devices

X

Section 5 - Fire & Gas Systems Section 6 - Quality Control Section 7 - Cause & Effects Section 8 - Operating Procedures Section 9 - HSE Section 10 - Reference Document Index

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SECTION 4 : SAFEGUARDING DEVICES 4.1. Alarms and Trips Refer to attached list: Unit 015 Alarms & Trips List.xls 4.2. Safeguarding Description The Emergency Shutdown System (ESD) provides trips and interlocks for preventing or controlling emergency situations which could give rise to hazardous situations leading to injuries to personnel, significant economic loss and/or undue environmental pollution. Uncontrolled loss of containment is prevented by the provision of pressure safety relief valves and by the ESD system which automatically bring the relevant part of the Unit to a safe condition. Trip/interlock is composed of one or more initiators and one or more actions for preventing hazards. Each trip/interlock shall be provided with a reset and an operational override for start-up, where necessary. In general, if interlock is invoked, the interlock action shall be held on until all initiators have returned to the safe state and the interlock reset has been pressed. The following is a description of all the safety logics provided in the RFCC unit. For each logic, the first table describes the initiators of the logic. The second table indicate each action taken and what are the initiators triggering each action.

4.2.1. Logic UX-001 – Reaction Stop Initiators: No.

Initiator Tag No.

P&ID

Description

1

UXHS-001A

121

Hardwire ESD switch active

2

UXHS-001B

121

Hardwire ESD switch active (ESD Bypass switch)

3

FXALL-405

121

Feed Flow Low Low (time delay of 10 seconds)

4

UX-002

121

Logic UX-002 activated: Catalyst Circulation Stopped

5

XHSC-002A

121

Software switch active (DCS operation is not allowed when UX-001 is activated)

6

XHSO-002A

121


7

XHSC-003A

122


8

XHSC-003A

122


9

XHSC-004A

122

Software switch active (DCS operation is not allowed when Page 175 of 323


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No.

Initiator Tag No.

P&ID

Description UX-001 is activated)

10

XHSC-004A

122


Actions: No.

Action Tag No.

Initiated by initiator No:

P&ID

Description

1a

XSY-002

1, 2, 3, 4, 5

121

CLOSE XV-002 to stop the .flow of feed to the feed injectors I-1501 A to F

1b

XSY-002

6

121

OPEN XV-002 to allow feed to flow to the feed injectors !-501 A to F

2

FSY-001

1, 2, 3, 4

121

OPEN FV-001 to re-route feed to the feed surge drum

3a

XSY-003

1, 2, 3, 4, 7

122

CLOSE XV-003 to stop the flow of MTC to the MTC injectors I-1502 A to D

3b

XSY-003

8

122

OPEN XV-003 to allow the MTC to flow to the MTC injectors I-1502 A to D

4a

XSY-004

1, 2, 3, 4, 9

122

CLOSE XV-004 to stop the flow of backflush oil to the backflush oil injector I1504

4b

XSY-004

10

122

OPEN XV-004 to the backflush oil to flow to the backflush oil injector I-1504

5

MXS-001

1, 2, 3, 4

121

Trip the metal passivator injection pumps P1502A

6

MXS-002

1, 2, 3, 4

121

Trip the metal passivator injection pumps P1502B

7

MXS-439

1, 2, 3, 4

305

Trip the MTC recycle pump P-1512A

8

MXS-440

1, 2, 3, 4

305

Trip the MTC recycle pump P-1512B

9

MXS-481

1, 2, 3, 4

306

Trip the HCO recycle pump P-1507A (Tripped by UX-423)

10

MXS-482

1, 2, 3, 4

306

Trip the HCO recycle pump P-1507A (Tripped by UX-423)

11

MXS-464

1, 2, 3, 4

324

Trip the backflush oil recycle pump P-1506A (Tripped by UX-424)

12

MXS-465

1, 2, 3, 4

324

Trip the backflush oil recycle pump P-1506B (Tripped by UX-424)

13

FSY-005A

1, 2, 3, 4

121

OPEN FV-005A to allow MP steam to flow to the feed injector I-1501 A

14

FSY-005B

1, 2, 3, 4

121

OPEN FV-005B to allow MP steam to flow Page 176 of 323


No.

Action Tag No.


P&ID

DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Description to the feed injector I-1501 B

15

FSY-005C

1, 2, 3, 4

121

OPEN FV-005C to allow MP steam to flow to the feed injector I-1501 C

16

FSY-005D

1, 2, 3, 4

121

OPEN FV-005C to allow MP steam to flow to the feed injector I-1501 C

17

FSY-005E

1, 2, 3, 4

121

OPEN FV-005E to allow MP steam to flow to the feed injector I-1501 E

18

FSY-005F

1, 2, 3, 4

121

OPEN FV-005F to allow MP steam to flow to the feed injector I-1501 F

19

FSY-007A

1, 2, 3, 4

122

OPEN FV-007A to allow MP steam to flow to the Stabilization injector I-1503 A

20

FSY-007B

1, 2, 3, 4

122

OPEN FV-007B to allow MP steam to flow to the Stabilization injector I-1503 B

21

FSY-007C

1, 2, 3, 4

122

OPEN FV-007C to allow MP steam to flow to the Stabilization injector I-1503 C

22

FSY-007D

1, 2, 3, 4

122

OPEN FV-007D to allow MP steam to flow to the Stabilization injector I-1503 D

23

UXA-001B

1, 2, 3, 4

121

Activate the reaction stop alarm (ADP)

24

FIC-001

1, 2, 3, 4

121

FIC-001 is forced to manual mode and output 100% to OPEN FV-001

25

FIC-003 A/B/C/D/E/F

1, 2, 3, 4

111

FIC-003 A/B/C/D/E/F is forced to manual mode and output 0% to CLOSE FV-003 A/B/C/D/E/F respectively

26

FIC-005 A/B/C/D/E/F

1, 2, 3, 4

111

FIC-005 A/B/C/D/E/F is forced to manual mode and output 100% to OPEN FV-005 A/B/C/D/E/F respectively

27

FIC-007 A/B/C/D

1, 2, 3 ,4

111

FIC-007 A/B/C/D is forced to manual mode and output 100% to OPEN FV-007 A/B/C/D

28

FIC-010 A/B/C/D

1, 2, 3 ,4

111

FIC-010 A/B/C/D is forced to manual mode and output 100% to OPEN FV-010 A/B/C/D

29

FIC-012

1, 2, 3, 4

122

FIC-012 is forced to manual mode and output 0% to CLOSE FV-012

Reset: •

DCS software switch UHSR-001 (PID No.121) resets all above actions.

•

XV-002, XV-003 and XV-004 need to be reset locally by XHSR-002, XHSR003 and XHSR-004 respectively.

Page 177 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

4.2.2. Logic UX-002: Catalyst Circulation Stops Initiators: No.

Initiator Tag No.

P&ID

Description

1

UXHS-002A

125


2

UXHS-002B

125

Hardwire ESD switch active (bypass switch)

3

PDXLL-064

124

D-1501 Stripper Differential Pressure low low (2 out of2 voting system)

4

PDXLL-104

125

Spent Catalyst Slide Valve SV-1502 differential pressure low low (2 out of 2 voting system)

5

LXALL-010

131

Withdrawal well level low low (10 seconds average is used as input)

6

PDXLL-242

131

Hot regenerated catalyst slide valve SV-1501 differential pressure low low (10 seconds average is used as input)

7

FXALL-170

132

Low low air flow to first regenerator heater (10 seconds offdelay timer)

8

FXALL-171

132

Low low air flow to the 2nd regenerator heater H-1502

9

FXALL-172

132

Low low air flow to the 1st regenerator D-1502

10

PXALL-363

138

Low low pressure of MP steam supply

11

UX-005

132

MAB Protection active

Actions: No.

Action Tag No.


P&ID

Description

1

USY-1502

ALL

125

CLOSE the spent catalyst slide valve SV1502, and generate a discrepancy alarm

2

USY-017

ALL

131

CLOSE the regenerated catalyst slide valve SV-1501, and generate a discrepancy alarm

3

USY-016

ALL

127

CLOSE the Air lift plug valve PV-1501 of the first regenerator

4

UX-001

ALL

121

Activate the Logic UX-001: Reaction Stop

5

UX-008

ALL

201

Activate the logic UX-008: COB/WHB 1st regenerator flue gas bypass operation

6

UX-010

ALL

202

Activate the logic UX-010: COB/WHB 2nd regenerator flue gas bypass operation

7

UXA-002B

ALL

125

Activate catalyst circulation stop alarm (ADP)

8

LIC-002

ALL

124

LIC-002 switch to manual mode and output 0% to CLOSE SV-1502

9

LIC-003

ALL

124

LIC-003 switch to manual mode and output Page 178 of 323


No.

Action Tag No.


P&ID

DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Description 0% to CLOSE SV-1502

10

LIC-004

ALL

126

LIC-004 switch to manual mode and output 0% to CLOSE PV-1501

11

LIC-007

ALL

129

LIC-007 switch to manual mode and output 0% to CLOSE PV-1501

12

PDIC-103

ALL

125

PDIC-103 switch to manual mode and output 0% to CLOSE SV-1502

13

TIC-015

ALL

123

TIC-015 switch to manual mode and output 0% to CLOSE SV-1501

14

TIC-020

ALL

123

TIC-020 switch to manual mode and output 0% to CLOSE SV-1501

Reset: DCS software reset switch UHSR-002 resets actions 1 to 6.

4.2.3. Logic UX-003: First Regenerator Air Heater Trip Initiators: No.

Initiator Tag No.

P&ID

Description

1

UXHS-003A

133


2

TXAHH-069

133

High high temperature in the first regenerator heater H1501

3

PXALL-321

134

Low low pressure of fuel gas supply from the fuel gas header

4

FXALL-170

132

Low low combustion air flow to first regenerator heater H1501

5

BXALL-003

133

No pilot flame in H-1501

6

BXALL-004

133

No main flame in H-1501

7

XS-801

132

Main Air Blower Trip (logic UX-801 activated)

8

UXHS-003B

133

Local panel ESD hardwire switch active

9

UXHS-003C

133


Actions: No.

Action Tag No.


P&ID

Description

1

XSY-016

ALL

133

CLOSE XV-016 to stop the fuel gas supply to the 1st regenerator heater H-1501 Page 179 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

No.

Action Tag No.


P&ID

Description

2

XSY-017

ALL

133

CLOSE XV-017 to stop the fuel gas supply to the 1st regenerator heater H-1501

3

XSY-019

ALL

133

OPEN XV-019 to vent the fuel gas to flare

4

UXA-003B

1 to 8

133

Activate the first regenerator heater H-1501 trip alarm (ADP)

5

TIC-068

ALL

133

TIC-068 switch to manual mode and output 0% to CLOSE TV-068

Once all the initiators are healthy, the logic UX-003 can be reset by: •

DCS software switch UHSR-003 resets actions 1, 2 and 3.

•

The valves XV-016, XV-017 and XV-019 need to be reset locally by means of the local hardwire switch XHSR-016, XHSR-017, XHSR-019

4.2.4. Logic UX-004: Second Regenerator Air Heater Trip Initiators: No.

Initiator Tag No.

P&ID

Description

1

UXHS-004A

134


2

TXAHH-072

134

High high temperature in the second regenerator heater H1502

3

PXALL-321

134

Low low pressure of fuel gas supply from the fuel gas header

4

FXALL-171

132

Low low combustion air flow to first regenerator heater H1502

5

BXALL-001

134

No pilot flame in H-1501

6

BXALL-002

134

No main flame in H-1501

7

XS-801

132

Main Air Blower Trip (logic UX-801 activated)

8

UXHS-004B

134


9

UXHS-004C

134


Actions: No.

Action Tag No.


P&ID

Description

1

XSY-014

ALL

134

CLOSE XV-014 to stop the fuel gas supply to the 2nd regenerator heater H-1502

2

XSY-015

ALL

134

CLOSE XV-015 to stop the fuel gas supply to the 2nd regenerator heater H-1502 Page 180 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

No.

Action Tag No.


P&ID

Description

3

XSY-020

ALL

134

OPEN XV-020 to vent the fuel gas to flare

4

UXA-004B

1 to 8

134

Activate the second regenerator heater H1501 trip alarm (ADP)

5

TIC-071

ALL

134

TIC-071 switch to manual mode and output 0% to CLOSE TV-071


DCS software switch UHSR-004 resets actions 1, 2 and 3.

•

The valves XV-014, XV-015 and XV-020 need to be reset locally by means of the local hardwire switch XHSR-014, XHSR-015, XHSR-020

4.2.5. Logic UX-005: Air Blower Protection Initiators: No.

Initiator Tag No.

P&ID

Description

1

UXHS-005A

132


2

UXHS-005B

132

Hardwire ESD switch active (ESD bypass switch)

3

XS-801

132

Air Blower trip active (logicUX-801 active)

Actions: No.

Action Tag No.


P&ID

Description

1

XSY-163

1&3

133

CLOSE 1st Regenerator air ring assisted check valve CV-1501 and generate discrepancy alarm.

2

XSY-165

1&3

133

CLOSE 2nd Regenerator air ring assisted check valve CV-1502 and generate discrepancy alarm.

3

XSY-167

1&3

132

CLOSE air lift assisted check valve CV1503 and generate discrepancy alarm.

4

XSY-168

1&3

132

CLOSE other blower air users assisted check valve CV-1504 and generate discrepancy alarm.

5

UX-002

1&3

125

Activate the logic UX-002: Catalyst circulation stop

6

XS-802

ALL

132

OPEN the air blower blow-off valves (logic UC-802)

Page 181 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Once all the initiators are healthy, the logic UX-005 can be reset by DCS software switch UHSR-005. In case of air blower ESD or automatic shutdown, the following actions will be done automatically: 1) 015-XV-800 turbine chest valve is closed (only for ESD) 2) 015-SV-802 turbine control valve is closed (only for ESD) 3) 015-UV-822 blower blow off valve is open 4) 015-UV-823 blower blow off valve is open 5) 015-UV-824 blower blow off valve is open 6) 015-UV-825 blower interstage blow-off flap is open 7) 015-ZC-826 blower guide vanes are moved in start-up position (normal position) 8) The flow controller 015-FIC-161 is switched off. 9) Turning gear is switched on by SSXX 803A. Note: For a complete description of the air blower interlocks, refer to the blower vendor cause & effect diagram, doc. No. 8474L-015-A3505-1040-001-063.

4.2.6. Logic UX-008: COB/WHB 1st Regenerator Flue Gas Bypass Operation Initiators: No.

Initiator Tag No.

P&ID

Description

1

UXHS-008

201

DCS software switch active (hardwire signal from DCS to ESD)

2

TXAHH-089 A/B

201

1st regenerator flue gas bypass temperature high high (1 out of 2 voting system)

3

UX-002

125

Logic UX-002 active: Catalyst circulation stop

4

XS-941

203

Logic UX-907 active: COB/WHB trip

5

MZSO-024B

201

1st regenerator flue gas bypass valve BV-1501B fully open

6

MZSO-023B

201

1st regenerator flue gas block valve BV-1501A fully open

7

XHSO-058AA

201

DCS software switch active (DCS operation is not allowed when UX-008 is tripped)

8

XHSC-058AA

201


9

XHSO-058BA

201


10

XHSC-058BA

201

DCS software switch active (DCS operation is not allowed Page 182 of 323


No.

Initiator Tag No.

P&ID

DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Description when UX-008 is tripped)

Actions: No.

Action Tag No.


P&ID

Description

1a

MXSY-024

1, 2, 3, 4

201

OPEN the first regenerator flue gas bypass valve BV-1501B

1b

MXSY-024

6

201

ALLOW the opening of the first regenerator flue gas bypass valve BV-1501B

2a

MXSY-023

1, 2, 3

201

CLOSE the first regenerator flue gas block valve BV-1501A

2b

MXSY-023

5

201

ALLOW the closure of the first regenerator flue gas block valve BV-1501A

3a

XSY-058A

1, 2, 3, 7

201

OPEN the LP BFW injection valve XV-058A in bypass line (start flue gas bypass cooling)

3b

XSY-058A

8

201

CLOSE the LP BFW injection valve XV058A in bypass line (stop flue gas bypass cooling)

4a

XSY-058B

1, 2, 3, 9

201

OPEN the LP BFW injection valve XV-058B in bypass line (start flue gas bypass cooling)

4b

XSY-058B

10

201

CLOSE the LP BFW injection valve XV058B in bypass line (stop flue gas bypass cooling)

5

XSY-059

1, 2, 3

201

OPEN the atomizing steam injection valve XV-059 in bypass line


DCS software switch UHSR-008

•

The valves XV-058A, XV-058B and XV-059 need to be reset locally by means of the local hardwire switch XHSR-058A, XHSR-058B and XHSR059 respectively.

4.2.7. Logic UX-009: Steam Drum D-1512 overfilling protection Initiators: No.

Initiator Tag No.

P&ID

Description

1

XS-944

202

H-1503 hardwire trip switch active

Page 183 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Actions: No.

Action Tag No.


P&ID

Description

1

XSY-062

1

205

CLOSE XV-062 to stop the supply of BFW to D-1512

Once all the initiators are healthy, the logic UX-009 can be reset by DCS software switch UHSR-009

4.2.8. Logic UX-010: COB/WHB 2nd Regenerator Flue Gas Bypass Operation Initiators: No.

Initiator Tag No.

P&ID

Description

1

UXHS-010

202

DCS software switch active (hardwire signal from DCS to ESD)

2

TXAHH-082 A/B

202

2nd regenerator flue gas bypass temperature high high (1 out of 2 voting system)

3

UX-002

125

Logic UX-002 active: Catalyst circulation stop

4

XS-941

203

Logic UX-907 active: COB/WHB trip

5

MZSO-026B

202

2nd regenerator flue gas bypass valve BV-1502B fully open

6

MZSO-025B

202

2nd regenerator flue gas block valve BV-1502A fully open

7

XHSO-056AA

202


8

XHSC-056AA

202


9

XHSO-056BA

202


10

XHSC-056BA

202


Actions: No.

Action Tag No.


P&ID

Description

1a

MXSY-026

1, 2, 3, 4

202

OPEN the 2nd regenerator flue gas bypass valve BV-1502B

1b

MXSY-026

6

202

ALLOW the opening of the 2nd regenerator flue gas bypass valve BV-1502B

2a

MXSY-025

1, 2, 3

202

CLOSE the 2nd regenerator flue gas block valve BV-1502A

2b

MXSY-025

5

202

ALLOW the closure of the 2nd regenerator Page 184 of 323


No.

Action Tag No.


P&ID

DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Description flue gas block valve BV-1502A

3a

XSY-056A

1, 2, 3, 7

202

OPEN the LP BFW injection valve XV-056A in bypass line (start flue gas bypass cooling)

3b

XSY-056A

8

202

CLOSE the LP BFW injection valve XV056A in bypass line (stop flue gas bypass cooling)

4a

XSY-056B

1, 2, 3, 9

202

OPEN the LP BFW injection valve XV-056B in bypass line (start flue gas bypass cooling)

4b

XSY-056B

10

202

CLOSE the LP BFW injection valve XV056B in bypass line (stop flue gas bypass cooling)

5

XSY-057

1, 2, 3

202




•

The valves XV-056A, XV-056B and XV-057 need to be reset locally by means of the local hardwire switch XHSR-056A, XHSR-056B and XHSR057 respectively.

Note: For a detailed description of the COB/WHB trip, refer to the cause & effect matrix of H-1503, doc No. 8474L-015-A3505-0160-001-156.

4.2.9. Logic UX-013: Economizer Bypass Cooling Initiators: No.

Initiator Tag No.

P&ID

Description

1

XS-943

205

Logic UX-906 active: Economizer bypass

2

XHSO-060AA

205

DCS Software Switch Active

3

XHSC-060AA

205


4

XHSO-060BA

205


5

XHSC-060BA

205


Actions:

Page 185 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

No.

Action Tag No.


P&ID

Description

1a

XSY-060A

1&2

205

OPEN the LP BFW injection valve XV-060A in the bypass line

1b

XSY-060A

3

205

ALLOW the opening of the LP BFW injection valve XV-060A in the bypass line

2a

XSY-060B

1&4

205

OPEN the LP BFW injection valve XV-060B in the bypass line

2b

XSY-060B

5

205

ALLOW the opening of the LP BFW injection valve XV-060B in the bypass line

3

XSY-061

1

205


Once all the initiators are healthy, the logic UX-013 can be reset by •


•

The valves XV-060A, XV-060B and XV-061 need to be reset locally by means of the local hardwire switch XHSR-060A, XHSR-060B and XHSR061 respectively

4.2.10. Logic UX-421: Feed Surge Drum D-1513 overfilling protection Initiators: No.

Initiator Tag No.

P&ID

Description

1

LXAHH-404 A/B/C

301

High high level in the feed surge drum D-1513 (2 out of 3 voting system)

Actions: No.

Action Tag No.


P&ID

Description

1

XSY-404

1

301

Close XV-404 to the stop the flow of residue to D-1513

Once all the initiators are healthy, the logic UX-421 can be reset by DCS software switch UHSR-421.

4.2.11. Logic UX-422: Feed Pumps P-1501 A/B Protection Initiators: No.

Initiator Tag No.

P&ID

Description

1

LXALL-403

301

Low low level in the feed surge drum D-1513 Page 186 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Actions: No.

Action Tag No.


P&ID

Description

1

MXS-435

1

301

Feed Pump P-1501 A tripped

MXS-436

1

301

Feed Pump P-1501 B tripped


4.2.12. Logic UX-423: T-1501 & P-1507 A/B inventory isolation Initiators: No.

Initiator Tag No.

P&ID

Description

1

UXHS-423A

306


2

UXHS-423B

306

Hardwire LOCAL switch active

3

XZSM-406

306

70% limit switch of P-1507A suction valve XV-406 active

4

XZSO-406

306

OPEN limit switch of P-1507A suction valve XV-406 active

5

XZSM-405

306

70% limit switch of P-1507B suction valve XV-405 active

6

XZSO-405

306

OPEN limit switch of P-1507B suction valve XV-405 active

7

UXHS-423C

306

Hardwire local switch active

8

UXHS-423D

306


9

UXHS-423E

306


Actions: No.

Action Tag No.


P&ID

1a

MXS-481

1, 2, 3, 7, 8, 9 306

TRIP the HCO recycle pump P1507 A

1b

MXS-481

4

ALLOW the HCO recycle pump P1507 A to be restarted:

306

Description

The pump is tripped when XV is less than 70% open and can only be restarted when XV is fully open. 2a

MXS-482

1, 2, 5, 7, 8, 9 306

TRIP the HCO recycle pump P1507 B

2b

MXS-482

6

ALLOW the HCO recycle pump P1507 B to be restarted:

306

The pump is tripped when XV is less than Page 187 of 323


No.

Action Tag No.


P&ID

DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Description 70% open and can only be restarted when XV is fully open.

3

XSY-405

1, 2, 7, 8, 9

306

CLOSE P-1507B suction motor operated valve XV-405

4

XSY-406

1, 2, 7, 8, 9

306

CLOSE P-1507A suction motor operated valve XV-406

5

XSY-407

1, 2, 7, 8, 9

306

CLOSE P-1507B discharge motor operated valve XV-407

6

XSY-408

1, 2, 7, 8, 9

306

CLOSE P-1507A discharge motor operated valve XV-408

7

XXA-405

1, 2, 7, 8, 9

306

Activate XV-405 trip alarm

8

XXA-406

1, 2, 7, 8, 9

306


9

XXA-407

1, 2, 7, 8, 9

306


10

XXA-408

1, 2, 7, 8, 9

306



DCS software switch UHSR-423;

•

The motor operated valves must be reset locally: XV-405/406/407/408 are reset by XHSR-405/406/407/408 respectively.

4.2.13. Logic UX-424: T-1501 & P-1508 A/B inventory isolation Initiators: No.

Initiator Tag No.

P&ID

Description

1

UXHS-424A

308


2

UXHS-424B

308


3

XZSM-409

308


4

XZSO-409

308


5

XZSM-410

308


6

XZSO-410

308


7

UXHS-424C

308


8

UXHS-424D

308


9

UXHS-424E

308


Actions:

Page 188 of 323


P&ID

DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

No.

Action Tag No.


1a

MXS-444

1, 2, 3, 7, 8, 9 308

TRIP the HCO pumparound pump P1508 A

1b

MXS-444

4

ALLOW the HCO pumparound pump P1508 A to be restarted:

308

Description

The pump is tripped when XV is less than 70% open and can only be restarted when XV is fully open. 2a

MXS-445

1, 2, 5, 7, 8, 9 308

TRIP the HCO pumparound pump P1508 B

2b

MXS-445

6

ALLOW the HCO pumparound pump P1508 B to be restarted:

308

The pump is tripped when XV is less than 70% open and can only be restarted when XV is fully open. 3

XSY-409

1, 2, 7, 8, 9

308


4

XSY-410

1, 2, 7, 8, 9

308


5

XSY-411

1, 2, 7, 8, 9

308


6

XSY-412

1, 2, 7, 8, 9

308


7

XXA-409

1, 2, 7, 8, 9

308


8

XXA-410

1, 2, 7, 8, 9

308


9

XXA-411

1, 2, 7, 8, 9

308


10

XXA-412

1, 2, 7, 8, 9

308




•


4.2.14. Logic UX-425: Slurry pumps P-1519 A/B/C protection Initiators: No.

Initiator Tag No.

P&ID

Description

1

LXALL-414

310

Low low level in the main fractionator T-1501

Actions: Page 189 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

No.

Action Tag No.


P&ID

Description

1

XSY-451

1

321

Activate logic UX-432 CLOSE XV-451 to stop the flow of slurry product to D-1515

2

FIC-462

1

321

FIC-462 switch to manual mode and output 0% to close FV-462


4.2.15. Logic UX-426: T-1501 & P-1519 inventory isolation Initiators: No.

Initiator Tag No.

P&ID

Description

1

UXHS-426A

311


2

UXHS-426B

311


3

XZSM-413

311


4

XZSO-413

311


5

XZSM-414

311


6

XZSO-414

311


7

XZSM-415

311

70% limit switch of P-1519C suction valve XV-415 active

8

XZSO-415

311

OPEN limit switch of P-1519C suction valve XV-415 active

9

HS-419

311

DCS software switch active (DCS/Local operation is not allowed when UX-426 is tripped)

10

XHSO-419B

311

LOCAL software switch active (DCS/Local operation is not allowed when UX-426 is tripped)

11

XHSC-419B

311


12

HS-421

311


13

XHSO-421B

311


14

XHSC-421B

311


15

HS-423

311


16

XHSO-423B

311

LOCAL software switch active (DCS/Local operation is not allowed when UX-426 is tripped) Page 190 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

No.

Initiator Tag No.

P&ID

Description

17

XHSC-423B

311


18

UXHS-426C

311

LOCAL hardwire switch active

19

UXHS-426D

311


20

UXHS-426E

311


21

UXHS-426F

311


22

UXHS-426G

311


Actions: No.

Action Tag No.


P&ID

Description

1a

XSY-419

1, 2, 3, 9, 11, 18, 19, 20, 21, 22

311

CLOSE the slurry pumparound pump P1519A turbine HP steam valve XV-419

1b

XSY-419

10

311

OPEN the slurry pumparound pump P1519A turbine HP steam valve XV-419

1c

XSY-419

4

311

ALLOW the opening of the slurry pumparound pump P-1519A turbine HP steam valve XV-419: Turbine of pump is automatically stopped when XV is less than 70% open and can only be restarted when XV is fully open.

2a

XSY-421

1, 2, 5, 12, 14, 18, 19, 20, 21, 22

311

CLOSE the slurry pumparound pump P1519B turbine HP steam valve XV-421

2b

XSY-421

13

311

OPEN the slurry pumparound pump P1519B turbine HP steam valve XV-421

2c

XSY-421

6

311

ALLOW the opening of the slurry pumparound pump P-1519B turbine HP steam valve XV-421: Turbine of pump is automatically stopped when XV is less than 70% open and can only be restarted when XV is fully open.

3a

XSY-423

1, 2, 7, 15, 17, 18, 19, 20, 21, 22

311

CLOSE the slurry pumparound pump P1519C turbine HP steam valve XV-423

3b

XSY-423

16

311

OPEN the slurry pumparound pump P1519C turbine HP steam valve XV-423

3c

XSY-423

8

311

ALLOW the opening of the slurry pumparound pump P-1519B turbine HP Page 191 of 323


No.

Action Tag No.


P&ID

DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Description steam valve XV-423: Turbine of pump is automatically stopped when XV is less than 70% open and can only be restarted when XV is fully open.

4

XSY-413

1, 2, 18, 19, 20, 21, 22

311


5

XSY-414

1, 2, 18, 19, 20, 21, 22

311


6

XSY-415

1, 2, 18, 19, 20, 21, 22

311

CLOSE P-1519C suction motor operated valve XV-415

7

XSY-416

1, 2, 18, 19, 20, 21, 22

311


8

XSY-417

1, 2, 18, 19, 20, 21, 22

311


9

XSY-418

1, 2, 18, 19, 20, 21, 22

311

CLOSE P-1519C discharge motor operated valve XV-418

10

XXA-413

1, 2, 18, 19, 20, 21, 22

311


11

XXA-414

1, 2, 18, 19, 20, 21, 22

311


12

XXA-415

1, 2, 18, 19, 20, 21, 22

311


13

XXA-416

1, 2, 18, 19, 20, 21, 22

311


14

XXA-417

1, 2, 18, 19, 20, 21, 22

311


15

XXA-418

1, 2, 18, 19, 20, 21, 22

311




•

The motor operated valves must be reset locally: XV-413/414/415/416/417/ 418 are reset by XHSR-413/414/415/416/417/418 respectively.

4.2.16. Logic UX-427: T-1504 & P-1509 A/B inventory isolation Initiators:

Page 192 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

No.

Initiator Tag No.

P&ID

Description

1

UXHS-427A

316


2

UXHS-427B

316


3

XZSM-430

316


4

XZSO-430

316


5

XZSM-431

316


6

XZSO-431

316


7

LXALL-432

316

Low low level in the HCO stripper T-1504

8

UXHS-427C

316


9

UXHS-427D

316


10

UXHS-427E

316


Actions: No.

Action Tag No.


P&ID

Description

1a

MXS-446

1, 2, 3, 7, 8, 9, 10

316

TRIP the HCO product pump P-1509 A

1b

MXS-446

4

316

ALLOW the HCO product pump P-1509 A to be restarted: The pump is tripped when XV is less than 70% open and can only be restarted when XV is fully open.

2a

MXS-447

1, 2, 5, 7, 8, 9, 10

316

TRIP the HCO product pump P-1509 B

2b

MXS-447

6

316

ALLOW the HCO product pump P-1509 B to be restarted: The pump is tripped when XV is less than 70% open and can only be restarted when XV is fully open.

3

XSY-430

1, 2, 8, 9, 10

316


4

XSY-431

1, 2, 8, 9, 10

316


5

XSY-432

1, 2, 8, 9, 10

316


6

XSY-433

1, 2, 8, 9, 10

316


7

XXA-430

1, 2, 8, 9, 10

316


8

XXA-431

1, 2, 8, 9, 10

316

Activate XV-431 trip alarm Page 193 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

No.

Action Tag No.


P&ID

Description

9

XXA-432

1, 2, 8, 9, 10

316


10

XXA-433

1, 2, 8, 9, 10

316




•


4.2.17. Logic UX-428: Heavy Naphta Product Pumps P-1515 A/B protection Initiators: No.

Initiator Tag No.

P&ID

Description

1

LXALL-440

317

Low low level in the heavy naphta stripper T-1502

Actions: No.

Action Tag No.


P&ID

Description

1

MXS-450

1

317

TRIP the heavy naphta product pump P1515A

2

MXS-451

1

317

TRIP the heavy naphta product pump P1515B


4.2.18. Logic UX-429: LCO Stripper Pumps P-1511 A/B protection Initiators: No.

Initiator Tag No.

P&ID

Description

1

LXALL-437

318

Low low level in the LCO stripper T-1503

Actions: No.

Action Tag No.


P&ID

Description

1

MXS-452

1

318

TRIP the LCO stripper pump P-1511A

2

MXS-453

1

318

TRIP the LCO stripper pump P-1511B Page 194 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07


4.2.19. Logic UX-430: D-1514, P-1516 A/B & P-1518 A/B inventory isolation Initiators: No.

Initiator Tag No.

P&ID

Description

1

UXHS-430A

320


2

UXHS-430B

320


3

XZSM-444

320

70% limit switch of P-1516 A/B & P-1518 A/B suction shutoff valve XV-444 active

4

XZSO-444

320

OPEN limit switch of P-1516 A/B & P-1518 A/B suction shut-off valve XV-444 active

5

LXALL-444

320

Low low level in the main fractionator reflux drum D-1514

6

XHSO-444B

320


7

XHSC-444B

320


Actions: No.

Action Tag No.


P&ID

Description

1a

MXS-456

1, 2, 3, 5

320

TRIP the fractionator reflux pump P-1516A

1b

MXS-456

4

320

Allow the fractionator reflux pump P-1516A to be restarted: The pump is tripped when XV is less than 70% open and can only be restarted when XV is fully open.

2a

MXS-457

1, 2, 3, 5

320

TRIP the fractionator reflux pump P-1516B

2b

MXS-457

4

320

Allow the fractionator reflux pump P-1516B to be restarted: The pump is tripped when XV is less than 70% open and can only be restarted when XV is fully open.

3a

MXS-460

1, 2, 3, 5

320

TRIP the overhead liquid pump P-1518A

3b

MXS-460

4

320

Allow the overhead liquid pump P-1518A to be restarted: The pump is tripped when XV is less than 70% open and can only be restarted when XV is fully open.

4a

MXS-461

1, 2, 3, 5

320

TRIP the overhead liquid pump P-1518B Page 195 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

No.

Action Tag No.


P&ID

Description

4b

MXS-461

1, 2, 3, 5

320

Allow the overhead liquid pump P-1518B to be restarted: The pump is tripped when XV is less than 70% open and can only be restarted when XV is fully open.

5a

XSY-444

1, 2, 7

320

CLOSE P-1516 A/B & P-1518 A/B suction shut-off valve XV-444

5b

XSY-444

6

320

OPEN P-1516 A/B & P-1518 A/B suction shut-off valve XV-444

6

XXA-444

1, 2, 7

320




•

The shut-off valve XV-444 must be reset locally XHSR-444 respectively.

4.2.20. Logic UX-431: D-1524, P-1517 A/B inventory isolation Initiators: No.

Initiator Tag No.

P&ID

Description

1

LXALL-447

320

Low low level in the main fractionator reflux drum boot

2

UXHS-431A

320


3

UXHS-431B

320


4

XZSM-445

320

70% limit switch of P-1517 A/B suction shut-off valve XV445 active

5

XZSO-445

320

OPEN limit switch of P-1517 A/B suction shut-off valve XV445 active

6

XHSO-445B

320


7

XHSC-445B

320


Actions: No.

Action Tag No.


P&ID

Description

1a

MXS-458

1, 2, 3, 5

320

TRIP the overhead sour water pump P1517A

1b

MXS-458

4

320

ALLOW the overhead sour water pump P1517A to be restarted: The pump is tripped when XV is less than Page 196 of 323


No.

Action Tag No.


P&ID

DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Description 70% open and can only be restarted when XV is fully open.

2a

MXS-459

1, 2, 3, 5

320

TRIP the overhead sour water pump P1517B

2b

MXS-459

4

320

ALLOW the overhead sour water pump P1517B to be restarted: The pump is tripped when XV is less than 70% open and can only be restarted when XV is fully open.

3a

XSY-445

2, 3, 7

320

CLOSE P-1517 A/B suction shut-off valve XV-445

3b

XSY-445

6

320

OPEN P-1517 A/B suction shut-off valve XV-445

4

XXA-445

2, 3, 7

320




•

The shut-off valve XV-445 must be reset locally XHSR-445 respectively.

4.2.21. Logic UX-432: D-1515 overfilling protection Initiators: No.

Initiator Tag No.

P&ID

Description

1

LXAHH-478

321

Low low level in D-1515

Actions: No.

Action Tag No.


P&ID

Description

1

XSY-451

1

321

CLOSE XV-451 to stop the flow of slurry product to D-1515; Activate logic UX-425

2

FIC-462

1

321


Reset: Once all the initiators are healthy, the logic UX-432 can be reset by DCS software switch UHSR-432.

Page 197 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

4.2.22. Logic UX-433: Slurry Product Pumps P-1504 A/B protection Initiators: No.

Initiator Tag No.

P&ID

Description

1

LXALL-450

321

Low low level in D-1515

Actions: No.

Action Tag No.


P&ID

Description

1

MXS-462

1

321

TRIP the slurry product pump P-1504A

2

MXS-463

1

321

TRIP the slurry product pump P-1504B


4.2.23. Logic UX-434: Backflush Oil Recycle Pumps P-1506 A/B protection Initiators: No.

Initiator Tag No.

P&ID

Description

1

LXALL-458

324

Low low level in the backflush oil receiver D-1517

Actions: No.

Action Tag No.


P&ID

Description

1

MXS-464

1

324

TRIP the Backflush Oil Recycle Pump P1506A

2

MXS-465

1

324

TRIP the Backflush Oil Recycle Pump P1506B



Initiator Tag No.

P&ID

Description

1

LXAHH-459

324

High high level in the backflush oil receiver D-1517 Page 198 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Actions: No.

Action Tag No.


P&ID

Description

1

XSY-459

1

324

CLOSE XV-459 to stop the flow of HCO product from E-1510 to D-1517


4.2.25. Logic UX-436: Backflush Oil Pumps P-1505 A/B protection Initiators: No.

Initiator Tag No.

P&ID

Description

1

LXALL-462

325

Low low level in the backflush oil draw off drum D-1516

Actions: No.

Action Tag No.


P&ID

Description

1

MXS-466

1

325

TRIP the Backflush Oil Pump P-1505A

2

MXS-467

1

325

TRIP the Backflush Oil Pump P-1505B



Initiator Tag No.

P&ID

Description

1

LXAHH-463

325

High high level in the backflush oil draw off drum D-1516

Actions: No.

Action Tag No.


P&ID

Description

1

FSY-467

1

325

CLOSE FV-467 to stop the flow of HCO product from E-1510 to D-1516

Page 199 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

No.

Action Tag No.


P&ID

Description

2

FIC-467

1

325



4.2.27. Logic UX-438: HCO Flushing Oil Pumps P-1521 A/B protection Initiators: No.

Initiator Tag No.

P&ID

Description

1

LXALL-468

326

Low low level in HCO flushing oil drum D-1518

2

HS-468

326


3

XHSO-468B

326

Hardwire local switch active (DCS operation is not allowed when UX-438 is tripped)

4

XHSC-468B

326

Hardwire local switch active (DCS operation is not allowed when UX-438 is tripped)

5

PAL-487

326

Low flushing oil pressure at the discharge of P-1521 A/B

6

XHSM-468B

326


Actions: No.

Action Tag No.


P&ID

Description

1a

XSY-468

1, 2, 4

326

CLOSE XV-468 to stop the MP steam supply to the turbine of P-1521A

1b

XSY-468

3, 5

326

OPEN XV-468 to allow the MP steam supply to the turbine of P-1521A

1c

XSY-468

6

326

ACTIVATE the HCO flushing oil pump P1521A

2

MXS-468

1

326

TRIP the HCO flushing oil pump P-1521B


Page 200 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

4.2.28. Logic UX-439: LCO Flushing Oil Pumps P-1522 A/B protection Initiators: No.

Initiator Tag No.

P&ID

Description

1

LXALL-471

327

Low low level in the LCO Flushing Oil Drum D-1519

Actions: No.

Action Tag No.


P&ID

Description

1

MXS-469

1

327

TRIP the LCO Flushing Oil Pumps P-1522A

2

MXS-470

1

327

TRIP the LCO Flushing Oil Pumps P-1522B



Initiator Tag No.

P&ID

Description

1

LXAHH-485

329

High high level in the light slops drum D-1522

Actions: No.

Action Tag No.


P&ID

Description

1

XSY-485

1

329

CLOSE XV-485 to stop the flow of light slops to D-1522

2

LIC-484

1

329

LIC-484 switch to manual mode and output 0% to close LV-484 on the light slops line from storage.


4.2.30. Logic UX-441: Light Slops Pumps P-1526 A/B protection Initiators:

Page 201 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

No.

Initiator Tag No.

P&ID

Description

1

LXALL-486

329

Low low level in the light slops drum D-1522

Actions: No.

Action Tag No.


P&ID

Description

1

MXS-473

1

327

TRIP the Light Slops Pumps P-1526 A

2

MXS-474

1

327

TRIP the Light Slops Pumps P-1526 B

Reset: Once all the initiators are healthy, the logic UX-441can be reset by DCS software switch UHSR-441.


Initiator Tag No.

P&ID

Description

1

LXAHH-491

330

High high level in the heavy slops drum D-1523

Actions: No.

Action Tag No.


P&ID

Description

1

XSY-491

1

330

CLOSE XV-491 to stop the flow of heavy slops to D-1523

2

LIC-490

1

330

LIC-490 switch to manual mode and output 0% to close LV-490 on the heavy slops line from storage.


4.2.32. Logic UX-443: Heavy Slops Pumps P-1527 A/B protection Initiators: No.

Initiator Tag No.

P&ID

Description

1

LXALL-492

330

Low low level in the heavy slops drum D-1523

Page 202 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Actions: No.

Action Tag No.


P&ID

Description

1

MXS-475

1

330

TRIP the Heavy Slops Pumps P-1527 A

2

MXS-476

1

330

TRIP the Heavy Slops Pumps P-1527 B


4.2.33. Logic UX-444: Tempered Water Pumps P-1528 A/B Protection Initiators: No.

Initiator Tag No.

P&ID

Description

1

LXALL-498

331

Low low level in the tempered water surge drum D-1524

Actions: No.

Action Tag No.


P&ID

Description

1

MXS-478

1

331

TRIP the Tempered Water Pump P-1528A

2

MXS-479

1

331

TRIP the Tempered Water Pump P-1528B


4.2.34. Logic UX-705: C-1551 Isolation and Protection Initiators: No.

Initiator Tag No.

P&ID

Description

1

UXHS-705AA

402

ESD hardwire switch active

2

UXHS-705B

402


3

LXAHH-704 A/B/C

401

High high level in the 1st stage KO drum D-1551 (2 out of 3 voting system)

4

LXAHH-709 A/B/C

403

High high level in the interstage KO drum D-1552 (2 out of 3 voting system)

5

XS-861

403

Activate the logic UX-861: TRIP the wet gas compressor due to low low speed. XS-861 ALLOW the closing of the MOVs when C-1551 Page 203 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

No.

Initiator Tag No.

P&ID

Description rotating speed is less than 250 RPM. C-1551 cannot be restarted until MOVs are opened fully.

6

TXAHH-631

402

C-1551 discharge temperature high high

7

TXAHH-632

402

C-1551 discharge temperature high high

8

MZSO-703B

402

OPEN limit switch of MOV-703

9

MZSO-704B

402


10

MZSO-705B

402


11

MZSO-706B

402


Actions: No.

Action Tag No.


P&ID

Description

1

XS-862

1, 2, 3, 4, 6, 402 7, 8, 9, 10, 11

ACTIVATE C-1551 trip

2a

MXSY-703

1, 2

402

CLOSE C-1551 first stage suction valve MOV-703

2b

MXSY-703

5

402

ALLOW the closing of C-1551 first stage suction valve MOV-703

3a

MXSY-704

1, 2

402

CLOSE C-1551 first stage discharge valve MOV-704

3b

MXSY-704

5

402

ALLOW the closing of C-1551 first stage discharge valve MOV-704

4a

MXSY-705

1, 2

402

CLOSE C-1551 second stage suction valve MOV-705

4b

MXSY-705

5

402

ALLOW the closing of C-1551 second stage suction valve MOV-705

5a

MXSY-706

1, 2

402

CLOSE C-1551 second stage discharge valve MOV-706

5b

MXSY-706

5

402

ALLOW the closing of C-1551 second stage discharge valve MOV-706


4.2.35. Logic UX-706: Interstage drum pump P-1551 A/B Protection Initiators:

Page 204 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

No.

Initiator Tag No.

P&ID

Description

1

LXALL-707

403

Low low level in the interstage KO drum D-1552

Actions: No.

Action Tag No.


P&ID

Description

1

MXS-714

1

403

TRIP the interstage KO drum pump P1551A

2

MXS-715

1

403

TRIP the interstage KO drum pump P1551B


4.2.36. Logic UX-707: HP separator drum D-1553 Interface Isolation Initiators: No.

Initiator Tag No.

P&ID

Description

1

LXALL-716

404

Low low level in HP separator drum D-1553

Actions: No.

Action Tag No.


P&ID

Description

1

XSY-716

1

404

CLOSE XV-716 to stop the sour water draw off from D-1553

2

LIC-714

1

404

LIC-714 switch to manual mode and output 0% to close LV-714


4.2.37. Logic UX-708: HP separator drum D-1553 Inventory Isolation Initiators: No.

Initiator Tag No.

P&ID

Description

1

UXHS-708A

404


2

UXHS-708B

404


3

XZSM-719

404

70% limit switch of the stripper feed pumps suction valve Page 205 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

No.

Initiator Tag No.

P&ID

Description XV-719 active

4

XZS0-719

404

OPEN limit switch of the stripper feed pumps suction valve XV-719 active

5

LXALL-719

404

Low low level in the HP separator drum D-1553

6

XHSO-719B

404


7

XHSC-719B

404


Actions: No.

Action Tag No.


P&ID

Description

1a

MXS-717

1, 2, 3, 5

404

TRIP the Stripper Feed Pump P-1553A

1b

MXS-717

4

404

ALLOW the stripper feed pump P-1553A to be restarted: The pump is tripped when XV is less than 70% open and can only be restarted when XV is fully open.

2a

MXS-718

1, 2, 3, 5

404

TRIP the Stripper Feed Pump P-1553B

2b

MXS-718

4

404

ALLOW the stripper feed pump P-1553B to be restarted: The pump is tripped when XV is less than 70% open and can only be restarted when XV is fully open.

3

XSY-719

1, 2, 6, 7

404

CLOSE the stripper feed pumps suction valve XV-719

4

XXA-719

1, 2, 6, 7

404



4.2.38. Logic UX-709: Lean Oil Coalescer Interface Isolation Initiators: No.

Initiator Tag No.

P&ID

Description

1

LXALL-725

407

Low low interface level in D-1556

Actions:

Page 206 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

No.

Action Tag No.


P&ID

Description

1

XSY-725

1

407

CLOSE XV-725 to stop the sour water draw off from D-1556

2

LIC-723

1

407

LIC-723 switch to manual mode and output 0% to close LV-723 on the sour water draw off line


4.2.39. Logic UX-710: T-1555 Interface Isolation Initiators: No.

Initiator Tag No.

P&ID

Description

1

LXALL-732

408

Low low interface level in T-1555

Actions: No.

Action Tag No.


P&ID

Description

1

XSY-732

1

408

CLOSE XV-732 to stop the rich amine draw off from T-1555

2

LIC-730

1

408

LIC-730 switch to manual mode and output 0% to close LV-730 on the lean amine return to ARU


4.2.40. Logic UX-712: Debutanizer T-1554 Inventory Isolation Initiators: No.

Initiator Tag No.

P&ID

Description

1

UXHS-712A

409


2

UXHS-712B

409


3

XZSM-738

409

70% limit switch of the gasoline recycle pumps suction valve XV-738 active

Page 207 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

No.

Initiator Tag No.

P&ID

Description

4

XZS0-738

409

OPEN limit switch of the stripper feed pumps suction valve XV-738 active

5

LXALL-738

409

Low low level in the Debutanizer T-1554

6

XHSO-738B

409


7

XHSC-738B

409


Actions: No.

Action Tag No.


P&ID

Description

1a

MXS-720

1, 2, 3, 5

406

TRIP the gasoline recycle pump P-1554A

1b

MXS-720

4

406

ALLOW the gasoline recycle pump P-1554A to be restarted: The pump is tripped when XV is less than 70% open and can only be restarted when XV is fully open.

2a

MXS-721

1, 2, 3, 5

406

TRIP the gasoline recycle pump P-1554B

2b

MXS-721

4

406

ALLOW the gasoline recycle pump P-1554B to be restarted: The pump is tripped when XV is less than 70% open and can only be restarted when XV is fully open.

3

XSY-738

1, 2, 6, 7

409

CLOSE XV-738 on the debutanizer bottom line

4

XXA-738

1, 2, 6, 7

404


Reset: Once all the initiators are healthy, the logic UX-712 can be reset by: •


•

XV-738 need to be reset locally by means of the local hardwire switch XHSR-738.

4.2.41. Logic UX-713: D-1554 Interface Isolation Initiators: No.

Initiator Tag No.

P&ID

Description

1

LXALL-741

410

Low low interface level in debutanizer reflux drum D-1554



DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

No.

Action Tag No.


P&ID

Description

1

XSY-741

1

410

CLOSE XV-741 to stop the sour water draw off from D-1554 boot

Reset: Once all the initiators are healthy, the logic UX-713 can be reset by DCS software UHSR-713.

4.2.42. Logic UX-714: Debutanizer Reflux Drum D-1554 Inventory Isolation Initiators: No.

Initiator Tag No.

P&ID

Description

1

UXHS-714A

410


2

UXHS-714B

410


3

XZSM-744

410

70% limit switch of the debutanizer OVHD pumps suction valve XV-744 active

4

XZS0-744

410

OPEN limit switch of the debutanizer OVHD pumps suction valve XV-744 active

5

LXALL-744

410

Low low level in the Debutanizer Reflux Drum D-1554

6

XHSO-744B

410


7

XHSC-744B

410


Actions: No.

Action Tag No.


P&ID

Description

1a

MXS-722

1, 2, 3, 5

410

TRIP the debutanizer OVHD pump P-1556A

1b

MXS-722

4

410

ALLOW debutanizer OVHD pump P-1556A to be restarted: The pump is tripped when XV is less than 70% open and can only be restarted when XV is fully open.

2a

MXS-723

1, 2, 3, 5

410

TRIP the debutanizer OVHD pump P-1556B

2b

MXS-723

4

410

ALLOW the debutanizer OVHD pump P1556B to be restarted: The pump is tripped when XV is less than 70% open and can only be restarted when XV is fully open.

Page 209 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

No.

Action Tag No.


P&ID

Description

3

XSY-744

1, 2, 6, 7

410

CLOSE XV-744 in the debutanizer OVHD pumps suction line

4

XXA-744

1, 2, 6, 7

410


5

LIC-739

1, 2, 3, 4, 5

410

LIC-739 switch to manual and output 0% to close LV-739



•

XV-744 need to be reset locally by means of the local hardwire switch XHSR-744

4.2.43. Logic UX-715: T-1556 Interface Isolation Initiators: No.

Initiator Tag No.

P&ID

Description

1

LXALL-748

411

Low low interface level in LPG Amine Absorber T-1556

Actions: No.

Action Tag No.


P&ID

Description

1

XSY-748

1

411

CLOSE XV-748 to stop the rich amine draw off from T-1556 back to the ARU.

2

LIC-746

1

411

LIC-746 switch to manual mode and output 0% to close LV-746.


4.2.44. Logic UX-716: LPG amine coalescer D-1555 Interface Isolation Initiators: No.

Initiator Tag No.

P&ID

Description

1

LXALL-751

411

Low low interface level in LPG Amine Coalescer D-1555



DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

No.

Action Tag No.


P&ID

Description

1

XSY-751

1

411

CLOSE XV-751 to stop the rich amine draw off from D-1555.

2

LIC-749

1

411

LIC-749 switch to manual mode and output 0% to close LV-749 on the rich amine drawoff line.


4.2.45. Logic UX-717: LPG amine absorber T-1556 depressurization Initiators: No.

Initiator Tag No.

P&ID

Description

1

UXHS-717A

411


2

UXHS-717B

411


Actions: No.

Action Tag No.


P&ID

Description

1

XSY-752

1

411

OPEN XV-752 to depressurize to flare.

2

FSY-723

1

411

CLOSE FV-723 to stop the feed flow to T1556


DCS software UHSR-716;

•


4.2.46. Logic UX-718: Fuel Gas Absorber Outlet KO Drum D-1559 Interface Isolation Initiators: No.

Initiator Tag No.

P&ID

Description

1

LXALL-735

408

Low low interface level in Fuel Gas Absorber Outlet KO Drum D-1559

Page 211 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Actions: No.

Action Tag No.


P&ID

Description

1

XSY-735

1

408

CLOSE XV-735 to stop the rich amine draw off from D-1559.

2

LIC-733

1

408

LIC-733 switch to manual mode and output 0% to close LV-733 on the rich amine drawoff line.


4.2.47. Logic UX-719: D-1553 depressurization Initiators: No.

Initiator Tag No.

P&ID

Description

1

UXHS-719A

408


2

UXHS-719B

408


Actions: No.

Action Tag No.


P&ID

Description

1

XSY-733

1

408

OPEN XV-733 to depressurize to flare.


DCS software UHSR-719;

•


4.2.48. Logic UX-861 Wet Gas Compressor C-1551 Protection Initiators: No.

Initiator Tag No.

P&ID

Description

1

XS-862

092

C-1551 Process conditions

2

PAL-867

037

Low pressure of the lube oil supply to C-1551

3

HS-868

092

C-1551 Local/Remote Switch

Page 212 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

No.

Initiator Tag No.

P&ID

Description

4

LAH-861

037

High level in the rundown tank of C-1551

5

PAL-868

092

C-1551 control oil supply pressure low

6

ZAC-865

092

C-1551 T&T valve full close limit switch

7

PDAL-585

037

C-1551 buffer gas supply differential pressure low

8

UXHS-863

092

C-1551 Emergency Stop

9

UXHS-705 AB

092

C-1551 trip signal from ESD console

10

PALL-866

037

C-1551 lube oil supply pressure low low

11

PDAHH-863A

037

C-1551 Primary Seal Vent Pressure (FE) High High

12

PDAHH-863B

037

C-1551 Primary Seal Vent Pressure (DE) High High

13

SAHH-862

092

C-1551 overspeed trip active

14

XS-871

092

Governor fault

15

UXS-865A/B

037

Compressor Axial Disp. High high

16

UXS-866A/B

092

Turbine axial disp. High high

17

SSLL-861

092

C-1551 turbine speed low

18

PAL-861

037

C-1551 Separation gas supply pressure low

19

PAL-599

037

C-1551 secondary gas supply pressure low

20

LAL-862

038

C-1551 oil reservoir level low

21

PAL-862

038

C-1551 Lube/control oil header pressure low

22

LAL-863

039

C-1551 Surface condenser Level low

23

LALL-863/866

039

C-1551 Surface condenser Level low low

24

LAH-863

039

C-1551 Surface condenser Level high

Actions: No.

Action Tag No.


P&ID

Description

1

YL-861

1, 2, 3, 4, 5, 6, 7

-

ALLOW the wet gas compressor C-1551 to be restarted

2

UXA-861

1, 8, 9, 10, 11, 12, 13, 14, 15, 16

-

TRIP the wet gas compressor C-1551 and generate a common trip alarm

3

UXA-861

1, 8, 9, 10, 11, 12, 13, 14, 15, 16

-

C-1551 common trip alarm (first out)

4

-

17

-

CLOSE the process MOV

5

YL-876, 877

18, 19, 20

-

ALLOW the oil pump to be started

Page 213 of 323


No.

Action Tag No.

6

DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07


P&ID

Description

21

-

AUTO START the standby pump

7

YL-876, 877

22

-

ALLOW the condensate pump to be started

8

MGL-876, 877

23

-

TRIP the condensate pump

9

-

24

-

AUTO START the condensate pump

4.3. Safeguarding Equipment 4.3.1. Pressure Safety Devices Over pressuring of the equipment occurs in many ways. The basic cause of power pressure is imbalance in heat and material flow in the equipment or piping. Pressure safety devices have been installed to protect and/or section against over pressure. Here is the list of the pressure safety valves found in the RFCC:

TAG No.

Description

015-PSV -570 015-PSV -571 015-RO -732 015-PSV -701-A 015-PSV -701-B 015-PSV -705-B 015-PSV -705-A 015-PSV -008-A 015-PSV -008-B 015-PSV -008-C 015-PSV -008-D 015-PSV -008-E 015-PSV -008-F

Breather Valve Breather Valve Breather Valve Relief Valve (Pilot) Relief Valve (Pilot) Relief Valve (Pilot) Relief Valve (Pilot) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring)

Type RV RV RV RV RV RV RV RV RV RV RV RV RV

Location MC RECYCLE PUMP P1512A MC RECYCLE PUMP P1512B INTER STAGE DRUM PUMP P-1551B PG FROM INTERSTAGE KO DRUM D-1552 PG FROM INTERSTAGE KO DRUM D-1552 HP SEP D-1553 VAPOR TO T-1551 HP SEP D-1553 VAPOR TO T-1551 BLOWER AIR TO CATALYST LINES BLOWER AIR TO CATALYST LINES BLOWER AIR TO CATALYST LINES BLOWER AIR TO CATALYST LINES BLOWER AIR TO CATALYST LINES BLOWER AIR TO CATALYST LINES

PID:

Setting (kg/cm2g)

637 637 637 403 403 404 404 132 132 132 132 132 132 Page 214 of 323


TAG No.

Description

015-PSV -008-G 015-PSV -006 015-PSV -005 015-PSV -009 015-PSV -007-A 015-PSV -007-B 015-PSV -362-A 015-PSV -362-B 015-PSV -359 015-PSV -401-A 015-PSV -401-B 015-PSV -406-A 015-PSV -406-B 015-PSV -406-C 015-PSV -408-A 015-PSV -408-B 015-PSV -409-A 015-PSV -409-B 015-PSV -412-A 015-PSV -412-B 015-PSV -638-A 015-PSV -638-B 015-PSV -704-A 015-PSV -704-B

Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring)

Type RV RV RV RV

DOC NO: 8474L-015-A5016-0000-001-005 REV: A

Location BLOWER AIR TO CATALYST LINES SPENT CATALYST HOPPER D-1506 AUXILIARY CATALYST HOPPER D-1507 FRESH CATALYST HOPPER D-1505

DATE: 06/12/07

PID: 132 135 136 137

RV

FUEL GAS DRUM D-1509

138

RV

FUEL GAS DRUM D-1509

138

RV RV RV RV RV RV RV RV RV RV RV RV RV RV RV RV RV RV

AIR HEATER FG KO DRUM D-1525 AIR HEATER FG KO DRUM D-1525 CO BOILER FG KO DRUM D-1526 FEED SURGE DRUM D1513 FEED SURGE DRUM D1513 DISCHARGE TO PSV408A/B DISCHARGE TO PSV408A/B DISCHARGE TO PSV408A/B DISCHARGE FROM PSV406A/B/C DISCHARGE FROM PSV406A/B/C HCO RECYCLE MP STEAM GEN E-1508 HCO RECYCLE MP STEAM GEN E-1508 HCO PMPAROUND MP STEAM GEN E-1523 HCO PMPAROUND MP STEAM GEN E-1523 SL FROM LP BLOWDOWN DRUM D-1527 SL FROM LP BLOWDOWN DRUM D-1527 STRIPPER OVHD TO COND E-1554A/B STRIPPER OVHD TO COND E-1554A/B

Setting (kg/cm2g)

206 206 206 301 301 303 303 303 304 304 306 306 308 308 452 452 405 405 Page 215 of 323


TAG No.

Description

015-PSV -709-A 015-PSV -709-B 015-PSV -710-A 015-PSV -710-B 015-PSV -712-A 015-PSV -712-B 015-PSV -714-A 015-PSV -714-B 015-PSV -719-A 015-PSV -719-B 015-PSV -721 015-PSV -722 015-PSV -715-A 015-PSV -715-B 015-PSV -003 015-PSV -416 015-PSV -456 015-PSV -402 015-PSV -415 015-PSV -414 015-PSV -417-A 015-PSV -403 015-PSV -419-A 015-PSV -420-A


Type RV RV RV RV RV RV RV RV RV RV RV RV RV RV RV RV RV RV RV RV RV RV RV RV

DOC NO: 8474L-015-A5016-0000-001-005 REV: A

Location TOP SECONDARY ABSORBER T-1553 TOP SECONDARY ABSORBER T-1553 PL FROM LEAN OIL COALESCER D-1556 PL FROM LEAN OIL COALESCER D-1556 PG FROM FG ABS OUTLET DRUM D-1559 PG FROM FG ABS OUTLET DRUM D-1559 PG FROM TOP DEBUTANIZER TK T-1554 PG FROM TOP DEBUTANIZER TK T-1554 PG FROM LPG AMINE ABS TANK T-1556 PG FROM LPG AMINE ABS TANK T-1556 ANTIFOAMING PUMP P1557 ANTIFOAMING PUMP P1558 DEBUTANIZER REFLUX DRUM D-1554 DEBUTANIZER REFLUX DRUM D-1554 PA TO FIRST REGENERATOR D-1502 SLURRY PUMP AROUND PUMP P-1519C PL TO FEED SURGE DRUM D-1513 FEED FRM LCO PREHT EXCHNG E-1512B SLURRY PUMPAROUND PUMP P-1519B SLURRY PUMPAROUND PUMP P-1519A SLURRY TO SUPPLY PA RETURN LINE FEED FRM LCO PREHT EXCHNG E-1512D SLURRY TO SUPPLY PA RETURN LINE SLURRY HP STEAM GENERATOR E-1503A

DATE: 06/12/07

PID:

Setting (kg/cm2g)

407 407 407 407 408 408 409 409 411 411 411 411 410 410 128 311 301 302 311 311 312 302 312 312 Page 216 of 323


TAG No.

Description

015-PSV -404 015-PSV -420-B 015-PSV -405 015-PSV -418-B 015-PSV -410 015-PSV -418-A 015-PSV -411 015-PSV -421-A 015-PSV -422-A 015-PSV -422-B 015-PSV -424-A 015-PSV -424-B 015-PSV -428-A 015-PSV -428-B 015-PSV -423-A 015-PSV -423-B 015-PSV -426-A 015-PSV -426-B 015-PSV -429-A 015-PSV -429-B 015-PSV -432-A 015-PSV -432-B 015-PSV -432-C 015-PSV -432-D



DOC NO: 8474L-015-A5016-0000-001-005 REV: A

Location PL FROM MP STEAM HTR E-1522 SLURRY HP STEAM GENERATOR E-1503B PL FROM MP STEAM HTR E-1524 SLURRY HP STEAM GEN E-1503A HCO RECYCLE MP STEAM GEN E-1508 SLURRY HP STEAM GEN E-1503A HCO PMPAROUND MP STEAM GEN E-1523 SLURRY FRM PSV417&419 SLURRY HP STEAM GEN. E-1503 C SLURRY HP STEAM GEN. E-1503 C SLURRY HP STEAM GENERATOR E-1505A SLURRY HP STEAM GENERATOR E-1505A SLURRY MP STEAM GENERATOR E-1505A SLURRY MP STEAM GENERATOR E-1505A SLURRY HP STEAM GENERATOR E-1504B SLURRY HP STEAM GENERATOR E-1504B SLURRY MP STEAM GENERATOR E-1505B SLURRY MP STEAM GENERATOR E-1505B HCO LP STEAM GENERATOR E-1510 HCO LP STEAM GENERATOR E-1510 FRACTIONATOR OVHD FRM T-1501 FRACTIONATOR OVHD FRM T-1501 FRACTIONATOR OVHD FRM T-1501 FRACTIONATOR OVHD FRM T-1501

DATE: 06/12/07

PID:

Setting (kg/cm2g)

302 312 302 312 306 312 308 313 313 313 314 314 314 314 315 315 315 315 316 316 319 319 319 319 Page 217 of 323


TAG No.

Description

015-PSV -432-E 015-PSV -432-F 015-PSV -432-G 015-PSV -432-H 015-PSV -434 015-PSV -435-A 015-PSV -435-B 015-PSV -437-A 015-PSV -437-B 015-PSV -436-A 015-PSV -436-B 015-PSV -439 015-PSV -438 015-PSV -440 015-PSV -441 015-PSV -444-A 015-PSV -444-B 015-PSV -445-A 015-PSV -445-B 015-PSV -446-A 015-PSV -446-B 015-PSV -447 015-PSV -448-A 015-PSV -448-B



DOC NO: 8474L-015-A5016-0000-001-005 REV: A

Location FRACTIONATOR OVHD FRM T-1501 FRACTIONATOR OVHD FRM T-1501 FRACTIONATOR OVHD FRM T-1501 FRACTIONATOR OVHD FRM T-1501 CORROSION INHABITOR PUMP P-1520A TOP SLRY DRAWOFF DRUM D-1515 TOP SLRY DRAWOFF DRUM D-1515 SLURRY HP STEAM GENERATOR E-1506A SLURRY HP STEAM GENERATOR E-1506A SLURRY HP STEAM GENERATOR E-1506B SLURRY HP STEAM GENERATOR E-1506B PS FROM SLRY LP STMGEN E-1506A/B PS FROM SLRY LP STMGEN E-1506A/B PL TO SLRY CLF COOLER E-1507B PL TO SLRY CLF COOLER E-1507D TOP BACK FLSH OIL RECV DRM D-1517 TOP BACK FLSH OIL RECV DRM D-1517 TOP FLSH OIL DRAWOFF DRM D-1517 TOP FLSH OIL DRAWOFF DRM D-1517 TOP HCO FLSHOIL DRUM D-1518 TOP HCO FLSHOIL DRUM D-1518 SL FRM HCO FLSHOIL PUMP P-1521A TOP LCO FLUSH OIL DRUM D-1519 TOP LCO FLUSH OIL DRUM D-1519

DATE: 06/12/07

PID:

Setting (kg/cm2g)

319 319 319 319 319 321 321 322 322 322 322 322 322 323 323 324 324 325 325 326 326 326 327 327 Page 218 of 323


TAG No.

Description

015-PSV -454-A 015-PSV -454-B 015-PSV -457-A 015-PSV -457-B 015-PSV -458-A 015-PSV -458-B 015-PSV -459-A 015-PSV -459-B 015-PSV -001-A 015-PSV -001-B 015-PSV -494-A 015-PSV -494-B 015-PSV -002 015-PSV -538-A 015-PSV -529 015-PSV -530 015-PSV -531 015-PSV -532 015-PSV -533 015-PSV -534 015-PSV -535 015-PSV -536 015-PSV -537 015-PSV -566



DOC NO: 8474L-015-A5016-0000-001-005 REV: A

Location LCO PRODUCT LP STEAM GENTR E-1513 LCO PRODUCT LP STEAM GENTR E-1513 LIGHT SLOPS DRUM D1522 LIGHT SLOPS DRUM D1522 HEAVY SLOPS DRUM D1523 HEAVY SLOPS DRUM D1523 TPW FROM TPW SURGE DRUM D-1524 TPW FROM TPW SURGE DRUM D-1524 METAL PASSVTR PUMP DISCH P-1502A METAL PASSVTR PUMP DISCH P-1502B CLARIFIED OIL TO STORAGE CLARIFIED OIL TO STORAGE MP STEAM FRM STM INJECTION POINTS HCO FLUSH OIL TO LP FLH HDR LCO PUMPAROUND PUMP P-1510A LCO PUMPAROUND PUMP P-1510A LCO PUMPAROUND PUMP P-1510A LCO PUMPAROUND PUMP P-1510A LCO PUMPAROUND PUMP P-1510B LCO PUMPAROUND PUMP P-1510B LCO PUMPAROUND PUMP P-1510B LCO PUMPAROUND PUMP P-1510B LCO STROPPER PUMP P1511A LCO STROPPER PUMP P1511A

DATE: 06/12/07

PID:

Setting (kg/cm2g)

328 328 329 329 330 330 331 331 121 121 323 323 123 326 637 637 637 637 637 637 637 637 637 637 Page 219 of 323


TAG No.

Description

015-PSV -567 015-PSV -568 015-PSV -569 015-PSV -572 015-PSV -573 015-PSV -574 015-PSV -575 015-PSV -576 015-PSV -579 015-PSV -602 015-PSV -603 015-PSV -605 015-PSV -606 015-PSV -607 015-PSV -608 015-PSV -609 015-PSV -611 015-PSV -613 015-PSV -615 015-PSV -617 015-PSV -619 015-PSV -620 015-PSV -621 015-PSV -623


Type RV RV RV RV

DOC NO: 8474L-015-A5016-0000-001-005 REV: A

Location LCO STROPPER PUMP P1511B LCO STROPPER PUMP P1511B MC RECYCLE PUMP P1512A MC RECYCLE PUMP P1512B

DATE: 06/12/07

PID: 637 637 637 637

RV

LEAN OIL PUMP P-1513A

637

RV


637

RV


637

RV


637

RV

FRACTIONATOR REFLUX PUMP P-1516A

637

RV

LEAN OIL PUMP P-1513B

637

RV


637

RV


637

RV


637

RV RV RV RV RV RV RV RV RV RV RV

NAPHTHA PUMP AROUND PUMP P-1514A NAPHTHA PUMP AROUND PUMP P-1514A NAPHTHA PUMP AROUND PUMP P-1514A NAPHTHA PUMP AROUND PUMP P-1514A NAPHTHA PUMP AROUND PUMP P-1514B NAPHTHA PUMP AROUND PUMP P-1514B NAPHTHA PUMP AROUND PUMP P-1514B NAPHTHA PUMP AROUND PUMP P-1514B HVN PRODUCT PUMP P1515A HVN PRODUCT PUMP P1515A HVN PRODUCT PUMP P1515B

Setting (kg/cm2g)

637 637 637 637 637 637 637 637 637 637 637 Page 220 of 323


TAG No.

Description

Type

015-PSV -625 015-PSV -627 015-PSV -629 015-PSV -631 015-PSV -632 015-PSV -633 015-PSV -634 015-PSV -635 015-PSV -636 015-PSV -637 015-PSV -640 015-PSV -641 015-PSV -642 015-PSV -643 015-PSV -644 015-PSV -649

Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring)

015-PSV -752

Relief Valve (Spring)

RV

015-PSV -754


RV

015-PSV -762 015-PSV -764 015-PSV -766 015-PSV -767 015-PSV -768

Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring)

RV RV RV RV RV RV RV RV RV RV RV RV RV RV RV RV

RV RV RV RV RV

DOC NO: 8474L-015-A5016-0000-001-005 REV: A

Location HVN PRODUCT PUMP P1515B HCO FLUSHING OIL PUMP P-1521A HCO FLUSHING OIL PUMP P-1521A HCO FLUSHING OIL PUMP P-1521B HCO FLUSHING OIL PUMP P-1521B LCO FLUSHING OIL PUMP P-1522A LCO FLUSHING OIL PUMP P-1522B HEAVY SLOPS PUMP P1527A HEAVY SLOPS PUMP P1527B FRACTIONATOR REFLUX PUMP P-1516B OVERHEAD SOUR WATER PUMP P-1517A OVERHEAD SOUR WATER PUMP P-1517B OVERHEAD LIQUID PUMP P-1518A OVERHEAD LIQUID PUMP P-1518A OVERHEAD LIQUID PUMP P-1518B OVERHEAD LIQUID PUMP P-1518B DEBUTANIZER OVERHEAD PUMP P1556A DEBUTANIZER OVERHEAD PUMP P1556B INTER STAGE DRUM PUMP P-1551A INTER STAGE DRUM PUMP P-1551B KO DRUM LIQUID PUMP P-1552A KO DRUM LIQUID PUMP P-1552B STRIPPER FEED PUMP P1553A

DATE: 06/12/07

PID:

Setting (kg/cm2g)

637 637 637 637 637 637 637 637 637 637 637 637 637 637 637 637 637 637 637 637 637 637 637 Page 221 of 323


TAG No.

Description

Type

015-PSV -771 015-PSV -773 015-PSV -774 015-PSV -720-A 015-PSV -720-B 015-PSV -425-A 015-PSV -425-B 015-PSV -427-A 015-PSV -427-B 015-PSV -011-A 015-PSV -011-B 015-PSV -390-A 015-PSV -390-B 015-PSV -391-A 015-PSV -391-B 015-PSV -417-B 015-PSV -419-B 015-PSV -538-B 015-PSV -421-B 015-PSV -004-A 015-PSV -004-B

Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring)

015-PSV -783


RV

015-PSV -784


RV

RV RV RV RV RV RV RV RV RV

DOC NO: 8474L-015-A5016-0000-001-005 REV: A

Location STRIPPER FEED PUMP P1553B GASOLINE RECYCLE PUMP P-1554A GASOLINE RECYCLE PUMP P-1554B P-1603B DISCHARGE LINE P-1604A DISCHARGE LINE PS FRM STMGEN E-1504B AND E-1505B PS FRM STMGEN E-1504B AND E-1505B PS FRM STMGEN E-1504A AND E-1505A PS FRM STMGEN E-1504A AND E-1505A

DATE: 06/12/07

Setting (kg/cm2g)

PID: 637 637 637 411 411 315 315 314 314

RV

126

RV

126

RV

307

RV

307

RV

317

RV

317

RV

312

RV

312

RV

326

RV

313

RV

123

RV

123 8474L-015PID-0041653 8474L-015PID-0041653 Page 222 of 323


TAG No.

Description

015-PSV -869 015-PSV -313 015-PSV -314 015-PSV -801 015-PSV -005-S 015-PSV -639 015-PSV -702 015-PSV -706 015-PSV -708 015-PSV -713 015-PSV -711 015-PSV -716 015-PSV -717 015-PSV -718 015-PSV -431 015-PSV -413 015-PSV -430 015-PSV -433 015-PSV -442 015-PSV -443

Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Spring) Relief Valve (Thermal) Relief Valve (Thermal) Relief Valve (Thermal) Relief Valve (Thermal) Relief Valve (Thermal) Relief Valve (Thermal) Relief Valve (Thermal) Relief Valve (Thermal) Relief Valve (Thermal) Relief Valve (Thermal) Relief Valve (Thermal) Relief Valve (Thermal) Relief Valve (Thermal) Relief Valve (Thermal) Relief Valve (Thermal)

Type

DOC NO: 8474L-015-A5016-0000-001-005 REV: A

Location

DATE: 06/12/07

PID:

Setting (kg/cm2g)

RV RV

654

RV

654

RV

654

RV

136

RV RV RV RV RV RV RV RV RV RV RV RV RV RV RV

CWS TO BLOWDOWN COOLER E-1532 CWS TO WET GAS COMP CLR E-1552A/B CWS TO STRIPPER CONDNSR E-1554A-D CWS TO GASOLINE COOLER E-1559 CWS TO LEAN OIL COOELR E-1564 CWS TO FUEL GAS COOLER E-1565 CWS TO DBTR CONDNSR E-1561A/B CWS TO LPG COOELR E1562 CWS TO LEAN AMINE COOLER E-1566 CWS TO HVN TRIM COOLER E-1518 BFB FROM LCO PA BFW HTR E-1511 BFB FROM HVN BFW HEATER E-1516 CWS TO OVRHD TRM CONDSR E-1520A-H TPW FROM SLRY CLF COOLER E-1507B TPW FROM SLRY CLF COOLER E-1507D

452 403 404 406 407 408 410 411 411 328 307 317 319 323 323

For further details, refer to the Flare Discharge Summary of the RFCC: Doc. No. 8474L015-NM-0006-701.

Page 223 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

TRAINING MODULE


Course Content: Section 1 - General Description Section 2 - Process Flow Description Section 3 - Process Control Section 4 - Safeguarding Devices Section 5 - Fire & Gas Systems

X

Section 6 - Quality Control Section 7 - Cause & Effects Section 8 - Operating Procedures Section 9 - HSE Section 10 - Reference Document Index

Page 224 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

SECTION 5 : FIRE & GAS SYSTEMS 5.1. Fire & Gas detection Refer to the following documents: 8474L-015-DW-1950-021

Fire & Gas Detector Layout RFCC/LTU/NTU units

8474L-015-DW-1960-001

Escape Route Layout RFCC/LTU/NTU units

8474L-015-DW-1514-610

Fire and gas Cause and Effect Chart Area 3

5.2. Fire Protection Refer to the following documents: 8474L-015-DW-1933-001 Fire Protection Layout RFCC/LTU/NTU units 8474L-015-DW-1933-011 Safety Equipment Layout RFCC/LTU/NTU units

Page 225 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

TRAINING MODULE


Course Content: Section 1 - General Description Section 2 - Process Flow Description Section 3 - Process Control Section 4 - Safeguarding Devices Section 5 - Fire & Gas Systems Section 6 - Quality Control

X

Section 7 - Cause & Effects Section 8 - Operating Procedures Section 9 - HSE Section 10 - Reference Document Index

Page 226 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

SECTION 6 : QUALITY CONTROL This section outlines the sampling schedule and analytical methods that the licensor suggests for monitoring the feed and product quality. The feed must be analyzed to be certain that it conforms to the quality of the feed that was used for the design. This is important for setting the operating severity level and for monitoring the catalyst activity. The products must be analyzed to ensure that the unit is producing on grade materials. The analytical results will often determine whether the material has to be "off-graded", or whether the material is acceptable for the next processing step. Therefore, it is obvious that ever precaution should be taken to make the sample representative of the original material. That is, it must be like all the rest of the material being processed or the material collected in the vessel. The analytical results reported by the laboratory can be no better than the sample submitted. An analysis or test however, efficiently carried out, will be rendered valueless if the sample has been improperly taken. Absolute verification of out-of-specification batches of material must be made by resampling and repeating the analysis before the material is off-graded. 6.1. Sampling Analysis For proper control of the unit it is essential to run laboratory tests on a regular basis. The following tests are recommended as a minimum.

6.1.1. Feed Oil Analysis

Method

Frequency

Gravity

ASTM D 1298/D 4052

Daily

ASTM Distillation

ASTM D 1160

Daily

Viscosity

ASTM D 445

Daily

Sulfur

ASTM D 4294

Daily

Nitrogen

ASTM D 4629

Daily

Conradson carbon residue (CCR)

ASTM D 189

Daily

Metals

ASTM D 5863 / D 5708 /D 5185

Weekly

Aniline point

ASTM D 611

Weekly

6.1.2. Catalyst Analysis

Method

Frequency

Spent Catalyst

Carbon

Element Analyser

Daily

1st regenerator catalyst

Carbon

ASTM D 3178 or equivalent

Daily

2nd regenerator catalyst

Carbon

ASTM D 3178 or equivalent

Daily Page 227 of 323


Analysis Fresh Catalyst

DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Method

Frequency

Particle Size MAT Activity Surface Area Pore Volume Bulk Density Metals

By catalyst vendor By catalyst vendor By catalyst vendor By catalyst vendor

Rare Earths

6.1.3. Light Cycle Oil Analysis

Method

Frequency

Specific Gravity

ASTM D 1298 / D 4052

Daily

Distillation

ASTM D 86

Daily

Sulfur

ASTM D 4294

Daily

Nitrogen

ASTM D 4629

Daily

Color

ASTM D 1500

Daily

Flash Point

ASTM D 93

Daily

Cloud Point

ASTM D 2500

Daily

Water

ASTM D 4377 / E 0203

Daily

Viscosity at 50°C

ASTM D 445

Daily

Pour Point

ASTM D 97

Daily

Analysis

Method

Frequency

Specific Gravity

ASTM D 1298 / D 4052

At Request

Distillation

ASTM D 86 / D 1160

At Request

Viscosity

ASTM D 445

At Request

Sulfur

ASTM D 4294

At Request

Analysis

Method

Frequency

Specific Gravity

ASTM D 1298 / D 4052

Daily

Distillation

ASTM D 1160

At Request

6.1.4. Heavy Cycle Oil

6.1.5. Clarified Oil

Page 228 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Analysis

Method

Frequency

Viscosity at 100°C

ASTM D 445

At request

Pour Point

ASTM D 97

Daily

Flash Point

ASTM D 93

At Request

Sulfur

ASTM D 4294

Daily

Water & Sediment

ASTM D 1796

Daily

Catalyst Loading (Ash)

ASTM D 482

Daily

Analysis

Method

Frequency

Catalyst Loading

ASTM D 482

Daily

Analysis

Method

Frequency

Composition

Gas Chromatograph

Daily

H2S

Draeger Tube

Daily

Analysis

Method

Frequency

Specific Gravity

ASTM D 1298 / D 4052

Daily

Distillation

ASTM D 86

Daily

Sulfur

ASTM D 4294

Daily

RON

ASTM D 2699

Daily

MON

ASTM D 323

Daily

Analysis

Method

Frequency

Composition

Gas Chromatograph

Daily

C5 (mol%)

ASTM D 2163

Daily

C2 (mol%)

ASTM D 2163

Daily

Specific Gravity

ASTM D 1657

As required

6.1.6. Slurry

6.1.7. Absorber Gas

6.1.8. Heavy Naphta

6.1.9. LPG

Page 229 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

6.1.10. Sour Water Analysis

Method

Frequency

pH

ASTM D 1293

At request

Copper

ASTM D 1688

At request

Iron

ASTM D 1068

At request

Phenols

ASTM D 1783

At request

Cyanides

ASTM D 4282

At request

Sulfides

ASTM D 4658

At request

Ammonia

ASTM D 4658

At request

Hydrocarbons

ASTM D 3921

At request

6.1.11. Sampling Connections For the sampling connections details per type (as listed below), refer to the following P&ID’s: •

8474L-015-PID-0021-611

Sampler Details (1/3)

•

8474L-015-PID-0021-612


•

8474L-015-PID-0021-613


Connection Type

Tag

Service

PID

SC-413

Sour water from T-1501 overhead sour water pumps P-1517A/B to SWS (unit 18)

320

SC-412

Heavy naphta from heavy naphta trim cooler E-1518 to gasoline treating

328

SC-706

Gasoline from gasoline cooler E1559 to gasoline treating

406

SC-704

Sour water from HP separator drum D-1553 to SWS

404

SC-709

Rich Sponge Oil from Secondary Absorber T-1553 to lean oil/rich oil cooler E-1563

407

SC-710

Sour water from lean oil coalescer D-1556 to SWS

407

SC-712

Rich amine from fuel gas

408

Type 1A: Low temperature liquid sample and low pour point products (gasoline, diesel) Operating Temperature ≤ 50°C Operating Pressure ≤ 8.16 kg/cm2g Type 1B: Low temperature liquid sample Operating Temperature ≤ 50°C Operating Pressure > 8.16 kg/cm2g Type 2: Low temperature gas and flashing liquid sample service Operating Temperature ≤ 50°C

Page 230 of 323


Connection Type

Tag

DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Service absorber T-1555 to ARU (unit 19)

PID

SC-713

Off gas from fuel gas absorber outlet KO drum D-1559 to fuel gas 408 system

SC-715

Sour water from Debutanizer Reflux Drum D-1554 to SWS

410

SC-716

LPG from LPG cooler E-1562 to LPG amine absorber T-1556

411

SC-717

Rich amine from LPG amine absorber T-1556 to ARU (unit 19)

411

SC-419

LCO product from LCO air cooler E-1514 to storage

328

SC-418

LCO Product at the outlet of LCO air cooler E-1514

328

SC-421

LCO product from LCO air cooler E-1514 to LCO HDT

328

SC-701

Wet gas from 1st stage KO drum outlet to wet gas compressor C1551 (1st stage)

401

SC-702

Wet gas from interstage KO drum outlet to C-1551 (2nd Stage)

403

SC-703

Stripper overhead from T-1552 to stripper condensers E-1554 A-D

404

Type 4A:

SC-705

405

Low temperature gas and flashing liquid sample service

HP separator vapour from D-1553 to primary absorber T-1551

SC-707

Primary absorber overhead from T-1551 to secondary absorber

407

SC-711

Fuel gas from secondary absorber T-1553 to fuel gas cooler E-1565

408

SC-714

Fuel gas from fuel gas inlet absorber KO drum D-1557 to fuel gas absorber inlet

408

SC-718

LPG from LPG amine coalescer to LPG treating unit

411

SCC-401

Residue feed from feed surge drum D-1513 to feed pumps P1501 A/B suction

301

Type 3A: Low temperature liquid sample Operating Temperature ≤ 50°C Operating Pressure ≤ 8.16 kg/cm2g Type 3A: Low temperature liquid sample Operating Temperature ≤ 50°C Operating Pressure > 8.16 kg/cm2g

Operating Temperature ≤ 50°C

Type 5A: High temperature liquid sample and

Page 231 of 323


Connection Type low pour point products

DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Tag

Service

PID

SCC-411

Continuous blowdown from LCO LP steam generator E-1510

316

SCC-415

Continuous blowdown from slurry LP steam generator E-1506 B

322

SCC-416

Continuous blowdown from slurry LP steam generator E-1506 A

322

SCC-417

Clarified Oil from the slurry clarified oil coolers E-1507 A-D to storage

323

SCC-422

HCO from the HCO LP steam generator E-1510 to the HCO flushing oil drum D-1518

316

SCC-402

Continuous blowdown from HCO recycle MP steam generator E1508

306

SCC-403

Continuous blowdown from HCO pumparound MP steam generator E-1523

308

SCC-404

Continuous blowdown from the Slurry HP steam generator E1503A

312

Type 5B:

SCC-405

312

High Temperature Liquid Sample and low pour point products with jacketed cooler

Continuous blowdown from the Slurry HP steam generator E1503B

SCC-406

Continuous blowdown from the Slurry HP steam generator E1503C

313

SCC-407

Continuous blowdown from slurry HP steam generator E-1504B

315

SCC-408

Continuous blowdown from slurry HP steam generator E-1504A

314

SCC-409

Continuous blowdown from slurry MP steam generator E-1505B

315

SCC-410

Continuous blowdown from slurry MP steam generator E-1505A

314

SCC-420

Continuous blowdown from the LCO product LP steam generator E-1513

328

SC-414

Slurry product from the slurry draw-off drum to the slurry MP steam generators E-1506 A/B

321

Operating Temperature > 50°C Operating Pressure ≤ 8.16 kg/cm2g

Operating Temperature > 50°C Operating Pressure > 8.16 kg/cm2g

Type 7: High Temperature Liquid Sample and high pour point products

Page 232 of 323


Connection Type

DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Tag

Service

PID

SCC-708

Stripper T-1552 bottoms to Debutanizer T-1554

405

SC-101

Cold condensate leaving the turbine ST-1501 of the air blower C-1501

132

Operating Temperature > 50°C Type 8: High Temperature gas & flashing liquid sample service Operating Temperature > 50°C Type 15: Low temperature liquid sample Operating Temperature < 50°C 6.2. On-line analyzers All the on-line analysers of the RFCC are dedicated to the control of the flue gas composition, to ensure the environmental specifications are satisfied prior to discharging to atmosphere. The main components of the regenerator flue gases are as follow: Parameter

Value Range

O2 (vol%)

0 to 5

CO (vol%)

0.01 to 8

CO2 (vol%)

5 to 20

N2 (vol%)

60 to 80

H2O (vol%)

5 to 20

SOx (vol ppm)

50 to 1000

NOx (vol ppm)

20 to 400

Catalyst fines (mg/Nm3)

200 to 3000

Temperature (°C)

620 to 840

Pressure (kg/cm2g)

0.05 to 3.7

Measures of O2, CO and CO2 content are necessary for operating the unit. They are made continuously. Dry and particle-free samples are required for both types of analysers. Measures of SOx and NOx content are necessary for pollution control. They can be made continuously or from time to time. The regenerator flue gas sampling sets 2 problems: •

Elimination of catalyst fines which concentration can reach 3000 mg/Nm3

•

Elimination of water which concentration can reach 20 vol%

Page 233 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

To overcome this, the sampling system comprises of the following steps: •

Primary filtration in which the solid particles are eliminated at a temperature over the flue gas dew point (250°C (min.) to 840°C(max.)) in order to avoid plugging and mud build up. So the filtration chamber is equipped with superheated MP steam tracing and heat conservation.

•

Carrying system: the sample is carried in stainless steel or monel tube traced with MP steam from the filtration chamber to the conditioning system. The sample is carried at temperature over the dew point in order to avoid acid condensation in the pipe due to SOx.

•

Conditioning system, where the sample is cooled down. It goes through a separator from condensates extraction. The condensates are drawn off by a peristaltic pump in the bottom of the conditioning device. In case of flue gas at atmospheric pressure the sample is compressed by a diaphragm pump prior to being dried. In case of flue gas under pressure, the sample is expanded after drying.

•

Analysers: o O2 content is measured by paramagnetic type analyser o CO and CO2 content is measured by infrared photometric type analyser o SOx content is measured by infrared photometry o NOx is measured by chemiluminescence

Service

Physical property analyzed

AI-004

Paramagnetic type O2 analyzer

1st regenerator flue gas

AI-005

Infrared photometric type CO2 analyzer

Analyzer tag

Description

Design Value PID:

CO Min.

Norm al

CO Max.

O2 content

0.0 Mol%

0.0 Mol%

0.0 Mol%

-


CO2 content

11.57 Mol%

9.94 Mol%

8.0 Mol%

-

AI-006

Infrared photometric type CO analyzer


CO content

4.63 Mol%

6.26 Mol%

8.00 Mol%

-

AI-007


2nd regenerator flue gas

CO content

0.00 Mol%

Page 234 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Design Value AI-008



CO2 content

16.98 Mol%

-

AI-009



O2 content

1.85 Mol%

-

AI-011


CO Boiler Flue Gas

CO content

<300 ppm vol

<300 ppm vol

-

AI-012


CO Boiler Flue Gas

CO2 content

13.56 Mol%

14.17 Mol%

-

AI-013


CO Boiler Flue Gas

O2 content

1.78 Mol%

1.78 Mol%

-

AI-018


Flue gas inlet to stack

O2 content

1.78 Mol%

1.78 Mol%

205

AI-019

Infrared Spectrophotometer


SOx content

0.05 Mol%

0.06 Mol%

205

AI-020

Chemiluminescence type analyzer


NOx content

<1000 ppm vol

<1000 ppm vol

205

For further details refer to the process data sheet of the RFCC analyzers, doc. No. 8474L-015-PDS-AE-001.

Page 235 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

TRAINING MODULE


Course Content: Section 1 - General Description Section 2 - Process Flow Description Section 3 - Process Control Section 4 - Safeguarding Devices Section 5 - Fire & Gas Systems Section 6 - Quality Control Section 7 - Cause & Effects

X

Section 8 - Operating Procedures Section 9 - HSE Section 10 - Reference Document Index

Page 236 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

SECTION 7 : CAUSES AND EFFECT

7.1. Cause & Effect Matrix: Refer to the following documents: •

Cause and Effect Chart, Doc. No. 8474L-015-DW-1514-602

•

Fire & gas Cause and Effect Chart for Area 3, Doc. No. 8474L-015-DW-1514-610

Note: The cause & effect matrix Doc. No. 8474L-015-DW-1514-602 details the safety trips and protection evoked in the safeguards narrative in section 4 of this document. The fire & gas cause and effect chart deals with all the fire & gas detection system in the area 3 (units 015, 016 and 017). 7.1.1. Example from Cause and Effect Chart To better understand how the Cause & Effect Matrix can be interpreted, an example is given, which details the information that can be extracted from a sheet of the Cause & Effect Diagram. It shall be read in conjunction with the corresponding sheet of the Cause & Effect Diagram. 7.1.1.1. Sheet 18: UX-426: T-1501 & P-1519 inventory isolation The following table describes all the causes activating the logic UX-426: No.

Initiator Tag No.

P&ID

Description

1

UXHS-426A

311


2

UXHS-426B

311


3

XZSM-413

311


4

XZSO-413

311


5

XZSM-414

311


6

XZSO-414

311


7

XZSM-415

311

70% limit switch of P-1519C suction valve XV-415 active

8

XZSO-415

311

OPEN limit switch of P-1519C suction valve XV-415 active

9

HS-419

311


10

XHSO-419B

311


11

XHSC-419B

311


12

HS-421

311

DCS software switch active (DCS/Local operation is not allowed when UX-426 is tripped) Page 237 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

No.

Initiator Tag No.

P&ID

Description

13

XHSO-421B

311


14

XHSC-421B

311


15

HS-423

311


16

XHSO-423B

311


17

XHSC-423B

311


18

UXHS-426C

311


19

UXHS-426D

311


20

UXHS-426E

311


21

UXHS-426F

311


22

UXHS-426G

311


Depending on which initiators are active, the logic UX-0426 may generate the effects detailed in the following table. For each effect, the corresponding initiators are indicated by a letter at the junction between the cause and the effect. The letter tells which can of action is taken. For example “A” indicates the activation of a device/system, “C” and “O” indicate the closing and opening of a valve respectively. No.

Action Tag No.


P&ID

Description

1a

XSY-419

1, 2, 3, 9, 11, 18, 19, 20, 21, 22

311

CLOSE the slurry pumparound pump P1519A turbine HP steam valve XV-419

1b

XSY-419

10

311

OPEN the slurry pumparound pump P1519A turbine HP steam valve XV-419

1c

XSY-419

4

311

ALLOW the opening of the slurry pumparound pump P-1519A turbine HP steam valve XV-419: Turbine of pump is automatically stopped when XV is less than 70% open and can only be restarted when XV is fully open.

2a

XSY-421

1, 2, 5, 12, 14, 18, 19, 20, 21, 22

311

CLOSE the slurry pumparound pump P1519B turbine HP steam valve XV-421

2b

XSY-421

13

311

OPEN the slurry pumparound pump PPage 238 of 323


No.

Action Tag No.


P&ID

DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Description 1519B turbine HP steam valve XV-421

2c

XSY-421

6

311


3a

XSY-423

1, 2, 7, 15, 17, 18, 19, 20, 21, 22

311

CLOSE the slurry pumparound pump P1519C turbine HP steam valve XV-423

3b

XSY-423

16

311

OPEN the slurry pumparound pump P1519C turbine HP steam valve XV-423

3c

XSY-423

8

311


4

XSY-413

1, 2, 18, 19, 20, 21, 22

311


5

XSY-414

1, 2, 18, 19, 20, 21, 22

311


6

XSY-415

1, 2, 18, 19, 20, 21, 22

311

CLOSE P-1519C suction motor operated valve XV-415

7

XSY-416

1, 2, 18, 19, 20, 21, 22

311


8

XSY-417

1, 2, 18, 19, 20, 21, 22

311


9

XSY-418

1, 2, 18, 19, 20, 21, 22

311

CLOSE P-1519C discharge motor operated valve XV-418

10

XXA-413

1, 2, 18, 19, 20, 21, 22

311


11

XXA-414

1, 2, 18, 19, 20, 21, 22

311


12

XXA-415

1, 2, 18, 19, 20, 21, 22

311


13

XXA-416

1, 2, 18, 19, 20, 21, 22

311


14

XXA-417

1, 2, 18, 19, 20, 21, 22

311


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DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

No.

Action Tag No.


P&ID

Description

15

XXA-418

1, 2, 18, 19, 20, 21, 22

311




•

The motor operated valves must 413/414/415/416/417/ 418 are 413/414/415/416/417/418 respectively.

be reset locally: XVreset by XHSR-

The C&E chart also indicates the Maintenance Override Switches (MOS) and Operation Override Switches (OOS) associated with the instrument triggering the logic and allowing the operator to bypass the conditions tripping the system: Instrument

OOS

MOS

UXHS-426A

N/A

N/A

UXHS-426B

N/A

N/A

XZSM-413

N/A

XZHS-413-A

XZSO-413

N/A

XZHS-413-B

XZSM-414

N/A

XZHS-414-A

XZSO-414

N/A

XZHS-414-B

XZSM-415

N/A

XZHS-415-A

XZSO-415

N/A

XZHS-415-B

HS-419

N/A

N/A

XHSO-419B

N/A

N/A

XHSC-419B

N/A

N/A

HS-421

N/A

N/A

XHSO-421B

N/A

N/A

XHSC-421B

N/A

N/A

HS-423

N/A

N/A

XHSO-423B

N/A

N/A

XHSC-423B

N/A

N/A

UXHS-426C

N/A

N/A

UXHS-426D

N/A

N/A

UXHS-426E

N/A

N/A Page 240 of 323


UXHS-426F

N/A

N/A

UXHS-426G

N/A

N/A

DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

When no OOS or MOS are available, then the condition leading to the activation of the logic cannot be bypassed.

Page 241 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

TRAINING MODULE


Course Content: Section 1 - General Description Section 2 - Process Flow Description Section 3 - Process Control Section 4 - Safeguarding Devices Section 5 - Fire & Gas Systems Section 6 - Quality Control Section 7 - Cause & Effects Section 8 - Operating Procedures

X

Section 9 - HSE Section 10 - Reference Document Index

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DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

SECTION 8 : OPERATING PRACTICES 8.1. Normal Operation 8.1.1. Operating conditions The following is a narrative of the main process conditions of the RFCC unit in steady state and FOR THE BACH HO MAX DISTILLATE CASE ONLY. It also details the line up during normal operation. For a complete description of the Heat and material Balance & Operating Conditions of the unit 015, refer to the following process flow diagrams: 8474L-015-PFD-0010-101


8474L-015-PFD-0010-102


8474L-015-PFD-0010-103


8474L-015-PFD-0010-104


8474L-015-PFD-0010-105


8474L-015-PFD-0010-106


8474L-015-PFD-0010-107


8474L-015-PFD-0010-111


8474L-015-PFD-0010-112


8474L-015-PFD-0010-113


8474L-015-PFD-0010-114


8474L-015-PFD-0010-115


8474L-015-PFD-0010-116


8474L-015-PFD-0010-117


Normal operation Narrative Feed Section Drawing to be inserted here Figure 54: Feed Preheat Section Refer to P&ID’s: 8474L-015-PID-0021-301 / 302 / 303 / 304 / 121 407,000 kg/hr of long residue is fed directly to the feed surge drum D-1513 from the Crude Unit (CDU) through XV-404, at 115°C and 4.5 kg/cm2g. The feed surge drum pressure is maintained at 1.0 kg/cm2g by either admitting Fuel Gas via PV403A or venting excess off gas to the Flare header via PV-403B. From D-1513, the feed flows to the suction of the Feed Pump on duty P-1501A via TI-403. P1501A pumps the feed to the LCO pumparound feed preheat exchangers E-1512

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A-D, through FIC-403. A slip stream of the feed is recycled back to the feed surge drum via FV-403. The total duty of E-1512A-D is 14.79 MW. The LCO PA feed preheat exchangers are constituted of 2 branches, in which the feed flows in parallel: •

1st Branch: Part of the feed is heated against LCO PA in the shell side of E1512A before flowing to the shell side of E-1512B via TW-404. The preheated feed then exits the shell side of E-1512B via TZ-405.

•

2nd Branch: The remaining part of the feed flows through the shell side of the E-1512C. The feed leaving the shell side of E-1512C flows through TW406 to the shell side of E-1512D and exits via TW-407.

The preheated feed leaving the shell side of E-1512B and E-1512D is recombined and flows through TI-408 and PI-408 to the shell side of the MP steam feed heater E-1522. MP steam is supplied to the tube side of E-1522 via FV-410. The duty of E-1522 is 3.77 MW. Then the feed flows to the shell side of the HP steam feed heater E-1524 via TI-409. HP steam is fed to the tube side of the exchanger via FV-411. The heated residue feed leaving E-1524 then flows to the 1st feed preheat slurry exchangers E-1502 A/B/C, via TI-410, TIC-411, PI-409 and PV-410. The feed flows through the shell side of these exchangers according to the following sequence: E-1502A (shell side), TW-412, E-1502B (shell side), TW-533, E-1502C (shell side). The total duty of E-1502 A-C is 19.95 MW. Upstream of E-1502A, a slip stream flows through the bypass line of the slurry feed preheat exchangers via TV-002. The heated feed leaving the shell side of E-1502C then flows to the 2nd feed preheat slurry exchangers E-1501 A/B via TI-421. Upstream of E-1501 A/B, the feed is equally split into 2 streams flowing in parallel to the shell side E-1501A and E-1501B. The total duty of the 2nd feed preheat slurry exchangers is 6.75 MW. The feed leaving E-1501A and E-1501B flows through TW-534 and TW-535 respectively before being recombined and mixed with the feed bypass from E1524. The total preheated feed then flows towards the reactor riser via PIC-410, TI-414, FIC-001, TI-001. Downstream of TI-001, HCO recycle from E-1508 flows into the preheated feed line via FIC-002 and FV-002. The temperature of the total feed is 290°C. The total feed flows to the feed line static mixer M-1501 via FXA-405 and XV-002. Metal passivator, from the metal passivator drum D-1508, is NOT injected into the feed line at the inlet of M-1510, since it is required for the Mixed Crude Case Only. Reaction Section Drawing to be inserted here Figure 55: Reaction Section – Bach Ho Maximum Distillate Case Refer to P&ID’s: 8474L-015-PID-0021-121 / 122 / 138 Downstream of the static mixer M-1501, the feed mixture flows to each feed injectors I-1501 A-F via TI-003, FIC-003A-F, FV-003A-F and PG-003A-F. Page 244 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

The feed should be split evenly between the feed nozzles as observed by individual flow indicators. Pressures PG-003A-F on each feed nozzle should be monitored as a verification of flow and indication of nozzle condition. 162,000 kg/hr of Dispersion steam is supplied to each of the six feed nozzles to promote atomization and vaporization of the feed. MP steam at 250°C flows to each of the six feed nozzles via TI-004, PI-004, FIC-005 A-F, FV-005 A-F and PG005A. 2,790 kg/hr of stabilization steam is supplied to the stabilization injectors I-1503 A to D at the bottom of the riser. The MP steam at 250°C is supplied from the MP steam header to each of the 4 injectors via TI-007, FIC-007 A to D, FV-007 A to D and PG-007 A to D. MTC is NOT required for Bach Ho crude operation and is only used when on mixed crudes and in high gasoline make modes. In such a case, MTC recycle is pumped from the tray #19 of the main fractionator T-1501 by means of the duty MTC recycle pump P-1512A to the MTC injectors I-1502 A to D. These injectors are located downstream of the feed injectors. The pressure at the pump discharge can be checked locally via PG-413. From the pump discharge, the MTC recycle flows to each of the 4 MTC injectors I-1502 A to D via FI-009, PI-009, XV-003, TI031, FIC-010 A to D, FV-010 A to D and PG-010 A to D. the flow is evenly split between each of the 4 MTC injectors. Even though MTC is not required for the Bach Ho Crude operation, a total of 660 kg/hr of MTC dispersion steam is injected to the 4 MTC injectors I-1502 A to D. The MP steam at 250°C flows from the MP steam header to the each of the injectors via TI-010, FIC-011 A to D, FV-011 A to D and PG-011 A to D. Finally, 6,875 kg/hr of backflush oil at 170°C is pumped by P-1506A from the backflush oil receiver D-1517 to the riser, downstream of the MTC injectors. Backflush oil flows from P-1506A discharge to the unique backflush oil injector I1504 through XV-004, TI-039, FIC-012, FV-012 and PG-009. The pressure at the pump discharge can be monitored locally by means of PG-477. 200 kg/hr of MP dispersion steam is also injected into the backflush oil injector: The MP steam at 250°C flows to the injector via FIC-013, FV-013, TI-006 and PG012. Riser/Reactor Refer to P&ID’s: 8474L-015-PID-0021-122 / 123 / 138 The sensible heat, heat of vaporization and heat of reaction required by the feed is supplied by the hot regenerated catalyst. From the withdrawal well, 35.77 Ton/min of hot regenerated catalyst flows to the riser wye via the Regenerated Catalyst Slide Valve SV-1501. The riser outlet temperature (TIC-020) is controlled by the amount of regenerated catalyst admitted to the riser through SV-1501. The catalyst flowing from the withdrawal well is fluidized by the injection of fuel gas from the fuel gas drum D-1509 and thru PCV-013, downstream of SV-1501. Fuel gas is injected at several locations from SV-1501 to the riser wye.

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DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

In the wye section at the base of the riser, 500 kg/hr of steam are injected via a steam ring to keep the regenerated catalyst in a fluid state at all times: the MP steam flows from the header to the ring via TI-011, FT/FI-006, and PG-006. The small droplets of feed contact hot regenerated catalyst in a counter current way and vaporize immediately. The vaporized oil intimately mixes with the catalyst particles and cracks into lighter, more valuable products along with slurry oil, coke and gas. The cracking reactions take place during the 2 seconds residence time in the riser as the reaction mixture (composed of the products and the catalyst) accelerates toward the Riser Outlet Separator System (ROSS) at the top of the riser. The catalyst is quickly separated from the hydrocarbon/steam vapors in the ROSS separator located at the end of the riser. After exiting the ROSS separator, the vapours pass through the 6 Disengager Cyclones CY-1501 A/B/C/D/E/F to complete the separation of catalyst from vapours. The ROSS separator and disengager cyclones CY-1501A-F separate the product vapors from spent catalyst and return the catalyst to the stripper bed. 544,699 kg/hr reactor product vapours at 505°C, containing a small amount of inerts, catalyst and steam, flow to the bottom of the main fractionator T-1501, via TI-022 and MOV-011. The reactor pressure "floats on" the main fractionator pressure and as such is not directly controlled at the main fractionator reflux drum D-1514. The reactor temperatures are monitored by means of TI-005 (downstream of the stabilization injectors), TI-008 (downstream of the feed injectors) and TI-009 (downstream of the MTC injectors). The riser outlet temperature indicated by TI021 and controlled by TIC-020 is 505°C. 300 kg/hr of anti-coking steam is provided at the top of the disengager/stripper cyclones. The MP steam at 250°C is supplied from the MP steam header to the ring via FIC-033, FV-033 and PG-041. Stripper Refer to P&ID’s: 8474L-015-PID-0021- 123 / 138 Catalyst exiting the ROSS separator is pre-stripped with 900 kg/hr of MP steam from a steam ring located immediately at the exit of the separator diplegs. This is an important feature for reducing coke yield. MP steam at 250°C is supplied from the header via FIC-032, FV-032 and PG-040. The catalyst is further stripped by 7000 kg/hr of steam at 250°C from the main steam ring as the catalyst flows down the Disengager/stripper D-1501. MP steam at 250°C is supplied from the header to the main ring via FIC-030, FV-030 and PG-038. 2 additional rings are also provided in addition to the main ring: •

The upper ring, above the main ring, achieves a second stage of prestripping. For this, 3400 kg/hr of MP steam at 250°C are supplied from the steam header to the upper ring via FIC-031, FV-031 and PG-039.

Page 246 of 323


•

DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

The lower ring is located in the bottom head of the stripper to achieve a stable fluidization at the inlet of the spent catalyst standpipe. For this, 2700 kg/hr of MP steam at 250°C are supplied from the steam header to the fluffing ring via FIC-029, FV-029 and PG-037. The steam rate for this ring is part of the total steam required for good stripping but its prime function is to aerate the catalyst entering the spent catalyst standpipe. This is important for adequate head build-up to maintain an adequate slide valve differential pressure for controlling the stripper level.

The total steam flow is designed to provide about 6 kg of steam per ton of catalyst circulated. The contact between catalyst and steam is enhanced by the presence of fluidized bed packing permitting cross and counter current flow of steam and catalyst. The fluidized bed packing is located between the main ring and the lower ring. It allows efficient contact between the catalyst and steam to displace the volatile hydrocarbons contained on and in the catalyst particles before they enter the 1st stage regenerator D-1502, where coke will be burnt off. The temperature in the stripper is monitored via (from top to bottom): TI-018, TI019, TI-016, TI-017, TI-014 and TI-013. Spent Catalyst Transfer Refer to P&ID’s: 8474L-015-PID-0021-125 / 138 Downstream of the main ring, stripped catalyst flows down the spent catalyst standpipe. The spent catalyst is aerated by means of fuel gas flowing through PCV-071 and PG-072 from the fuel gas drum D-1509. This fuel gas drum is supplied with fuel gas from the fuel gas header. D-1509 is also supplied in fuel gas from D-1559 in the gas recovery section, on pressure control with PIC-367 acting on PV-367A. The fuel gas pressure in D-1509 can be monitored locally with PG368. The total flow of FG leaving the drum D-1509 to various locations in the reaction section (for fluidization or aeration purpose) is monitored by FI-203. Nitrogen is also supplied via PCV-089, PG-090 and FI-021 for catalyst aeration. This aeration help maintain proper density and fluid characteristics of the spent catalyst. Fuel gas aeration injectors are distributed all along the spent catalyst stand pipe upstream of the spent catalyst slide valve SV-1502, while 4 Nitrogen aeration injectors are evenly distributed across SV-1502. While aerated, the catalyst flows down through the spent catalyst line expansion joint EX-1501 and then the spent catalyst slide valve SV-1502, which regulates the level of the stripper by regulating the flow of catalyst leaving it. Then the spent catalyst flows into the 1st stage regenerator D-1502 through a distributor which ensures that the entering coke-laden catalyst is spread across the regenerator bed. Catalyst Regeneration Section Page 247 of 323


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The first stage regenerator D-1502 burns 50 to 80% of the coke and the remainder is burned in the second stage regenerator D-1503. Air blower and air heaters Refer to P&ID’s: 8474L-015-PID-0021-128 / 130 / 134 / 132 / 133 / 138 / 206 The combustion air required for the combustion reactions in the 1st and 2nd catalyst regenerators D-1502 and D-1503 is supplied by the steam turbine driven air blower C-1501. Atmospheric air is introduced to the air blower C-1501 through an intake filter and silencer F-1501. At C-1501 discharge, the blower air at 238°C is distributed, via PT-834, PG-356 and PIC-311, to a header system providing combustion air to the downstream equipment as follow: •

166,001 kg/hr of combustion air at 238°C is supplied to the first regenerator air heater H-1501 via FIC-161, PV-311 and the first regenerator air ring assisted check valve CV-1501. In H-1501 bower air is heated up by fuel gas combustion. The air heater is supplied with fuel gas from the air heater fuel gas KO drum D-1525 via XV016 and XV-017. The air heater fuel gas KO drum D-1525 is supplied with pilot fuel gas from the battery limits via PV-371B in normal operation. Preheated air leaves the 1st regenerator heater and is supplied to the inner air rings and outer air rings at the bottom of the 1st Catalyst Regenerator D1502 via PG-314, TI-067, TIC-068 and TXA-069. The outer air ring and inner air ring are designed to handle about 70% and 30% of the combustion air to the first stage regenerator D-1502 respectively.

•

31,685 kg/hr of combustion air at 238°C is supplied to the 2nd regenerator air heater H-1502 via FIC-164, FV-164 and the 2nd regenerator air ring assisted check valve CV-1502. In H-1502, air is heated up by fuel gas combustion. The air heater is supplied with fuel gas from the air heater fuel gas KO drum D-1525 via XV-014 and XV-015. The air heater fuel gas KO drum D-1525 is supplied with pilot fuel gas from the battery limits via PV371B in normal operation. Preheated air is then supplied to the unique air ring located at the bottom of the 2nd regenerator D-1503 via PG-317, TI-070, TIC-071 and TXA-072.

•

47,832 kg/hr of blower air at 238°C is also used as lift air and is supplied to the bottom of the lift line of the 1st regenerator in order to transfer partly regenerated catalyst from D-1502 to D-1503. Air is supplied from the discharge header of the air blower C-1501 via FIC-166, FV-166 and the air lift assisted check valve CV-1503. Air is injected through the hollow stem of the plug valve PV-1501 which regulates the amount of catalyst transferred to the 2nd stage regenerator.

•

514 kg/hr of blower at 238°C is also injected in the catalyst loading line at the bottom of the 1st regenerator D-1502 as fluidizing medium. Air is supplied from the discharge header of the air blower C-1501 via FT/FI-071 and PG-114. Page 248 of 323


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DATE: 06/12/07

•

1029 kg/hr of blower at 238°C is also injected in the catalyst loading line at the bottom of the 2nd regenerator D-1503 as fluidizing medium. Air is supplied from the discharge header of the air blower C-1501 via FT/FI-097 and PG-166.

•

Finally 336 kg/hr of blower air at 2238°C is supplied in the withdrawal ring of the withdrawal well downstream of the point where the hot regenerated catalyst is discharged to the well, also as fluidizing medium. Air is supplied from the discharge header of the air blower C-1501 via FIC-169, FV-169 and PG-239.

First stage regenerator Refer to P&ID’s: 8474L-015-PID-0021-126 / 127 / 128 / 201/ 203 Spent catalyst containing roughly 1 to 1.5 wt % coke flows from the spent catalyst distributor and is spread across the bed in the first stage regenerator D-1502. Plant air (primary) is provided along the outlet of the spent catalyst standpipe to help for the catalyst transfer. Plant is supplied from the PA header via PCV-142 and PG-143 to several nozzles disturbed along the outlet of the standpipe. Part of the coke is burned by combustion air supplied from the outer and inner air rings. This regenerator operates in a counter current (air inlet at bottom and spent catalyst inlet at top) to prevent catalyst overheating. In order to limit hydrothermal deactivation of the catalyst, the regeneration conditions are mild: 1st stage regenerator total combustion air is controlled to limit the temperature in this 1st stage to maximum 730°C. For this operating case, the 1st regenerator is operated at 2.28 kg/cm2g. The normal operating temperatures of the 1st stage regenerator are: 636°C (bottom) & 631°C (top). The partially regenerated catalyst flows down through the first stage regenerator bed to the entrance of the air lift. Aeration by a fluffing ring is supplied in the vicinity of the air lift to ensure smooth flow of catalyst to the lift. 574 kg/hr of plant air (primary) is supplied to the fluffing ring via PCV-138, PG-139, FT/FI-070 nad PG-113. The hollow stem plug valve PV-1501 regulates the flow of catalyst to the lift line and is controlled by the level in the first stage regenerator D-1502 via LIC004. 47832 kg/hr of blower air injected through the hollow stem of the plug valve into the air lift to lift the catalyst in a dilute phase up to the second stage regenerator D-1503. 2 stage cyclones (CY-1502A-F / CY-1503A-F) separate entrained catalyst from the flue gas. 178544 kg/hr of flue gas exits the 1st stage regenerator D-1502 towards the CO boiler H-1503 at 631°C via TI-030, analysers AI-004/005/006, the first regenerator flue gas slide valve SV-1503 and the first regenerator flue gas block valve BV-1501A. The temperature in the 1st stage regenerator is monitored with 6 temperature indicators TI-032/033/034/035/036/037 and is averaged by TI-038. Second stage regenerator Refer to P&ID’s: 8474L-015-PID-0021-128 / 129 / 130 / 202 / 203

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The partially regenerated catalyst flows up the lift line through the expansion joint EX-1502 between the regenerators and enters the 2nd stage regenerator D-1503 below the combustion air ring. A distributor at the end of the lift provides for efficient distribution of catalyst and air from the lift. Catalyst is then completely regenerated to less than about 0.05% carbon through combustion at more severe conditions than in the first stage regenerator D-1502. The following are the normal operating conditions of the 2nd regenerator D-1503 for this operating case: •

Pressure: 1.30 kg/cm2g

•

Bottom temperature: 695°C

•

Top temperature: 720°C

4 external refractory lined cyclones CY-1504A-D are used on the 2nd stage flue gas outlet to remove entrained catalyst. The cyclone dip legs are external to the regenerator. Catalyst recovered in the cyclones is returned to the regenerator bed below the normal operating level by way of the diplegs. Aeration with PA is supplied to the diplegs to maintain a smooth fluidized catalyst flow and the diplegs outlets are equipped with flapper (trickle) valves to prevent catalyst and gas backflow into the cyclones. Plant Air (Primary) is supplied to the each dipleg via PCV-164 A to D. 86,941 kg/hr of flue gas leave the 2nd stage regenerator at 720°C and flows to the Waste Heat Boiler H-1503 through TI-064, the flue gas analysers AI-007/008/009, the 2nd Regenerator Flue gas Slide Valve SV-1504, TI-078 and the 2nd Regenerator Flue gas Block Valve BV-1502 A. The temperature in the 2nd stage regenerator is monitored with 4 temperature indicators TI-050/052/058/060 and is averaged by TI-063. Note: The pressure drop across the ring is kept above 0.07 bar at turndown to maintain adequate distribution and prevent intrusion of catalyst into the ring and avoid associated erosion. Regenerated catalyst transfer Refer to P&ID’s: 8474L-015-PID-0021-122 / 129 / 131 / The hot regenerated catalyst flows from the 2nd stage regenerator D-1503 through a lateral into the withdrawal well. In the withdrawal well a stable bed is established at proper standpipe density by introduction of 336 kg/hr of fluidizing air from the withdrawal well ring. A smooth stable flow of catalyst down the standpipe is provided by injection of aeration Plant Air at several elevations on the regenerated catalyst standpipe: PA (primary) is supplied to 2 aeration nozzles on the lateral via PCV-214. PA (primary) is also supplied to 9 aeration nozzles in the upper part of the withdrawal well via PCV-212. Finally, PA (primary) is supplied to 9 aeration nozzles on the lower part of the withdrawal well, upstream of the regenerated catalyst slide valve SV-1501, via PCV-210. Page 250 of 323


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At the bottom of the withdrawal well, the catalyst flows through the regenerated catalyst slide valve SV-1501 to the riser wye at the base of the riser where a steam ring fluidizes the catalyst. The wye steam and fluidization points in the wye section ensure that the catalyst flow to the feed injection point is stable and smooth in order for the feed injection system to perform at its optimum. Catalyst handling The catalyst handling system includes hoppers for storage of fresh catalyst and spent catalyst, loading devices for catalyst addition and a draw-off device for continuous equilibrium catalyst withdrawal. Three hoppers are installed: •

The fresh catalyst hopper D-1505,

•

The spent catalyst hopper D-1506

•

The auxiliary catalyst hopper D-1507, which provides flexibility in the operation for different options: o Storage of imported equilibrium catalyst reused as part of the makeup catalyst, o Storage of excess spent catalyst, o Storage of a 2nd grade of fresh catalyst for make-up.

The spent and fresh catalyst hoppers are sized to contain the entire unit inventory. Each hopper is provided with one cyclone and with aerations in the bottom cone to assist the catalyst circulation to the transfer lines. Catalyst addition Refer to P&ID’s: 8474L-015-PID-0021-126 / 136 Continuous addition of fresh catalyst to the RFCC is essential for at least three reasons: •

To maintain an optimum catalyst activity and selectivity,

•

To keep metals on equilibrium catalyst at an acceptable level,

•

To make up the inventory of circulating catalyst, compensating for catalyst losses.

Two hoppers have been provided for catalyst addition. This allows the addition simultaneously two different types of catalyst. It allows also to load one hopper from a truck using the ejector system while the other hopper can remain pressurized for the normal catalyst addition operation. A catalyst feeder is used to automatically add fresh catalyst at the desired rate. The feeder can be adjusted for batch size and frequency of additions. The catalyst feeders are directly located below the catalyst hoppers. The amount of catalyst introduced to the catalyst feeder is controlled by a weight cell and a diaphragm valve at the catalyst feeder inlet. When the desired weight is in the Page 251 of 323


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loader, the diaphragm valve closes. A switch is then activated which opens fluidizing and pressuring air to the feeder. The feeder pressures up to about 3.5 kg/cm2 g and another diaphragm valve opens which loads the catalyst into the first stage regenerator via TI-024. It is possible to bypass the catalyst make-up feeders during operation for repairs. Catalyst withdrawal Refer to P&ID’s: 8474L-015-PID-0021-126 / 135 As catalyst addition is higher than the catalyst losses from the unit, catalyst must be withdrawn in order to keep the unit inventory. This operation is achieved by a specific continuous draw-off system, X-1501, provided on the first regenerator D1501. Hot catalyst is withdrawn by an ON/OFF valve UV-021 actuated by timer, cooled down through a finned tube and sent to the spent catalyst hopper at a temperature below 400°C. The amount of withdrawn catalyst is controlled by a restriction orifice RO-090. For catalyst conveying and line cleaning, plant air is injected into the catalyst at line downstream of the restriction orifice by another ON/OFF valve UV-022 actuated by timer. The plant air is set in order to limit the catalyst velocity in the draw-off line (10 m/s), to limit the erosion. The total daily amount of catalyst withdrawal is adjusted by timer setting taking into account the operation requirements for the overall catalyst balance. Flue gas treatment Drawing to be inserted here Figure 55: Flue Gas Treatment Section (Bach Ho MD case)

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Figure 56: COB/WHB Package Flow Scheme Page 253 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Refer to P&ID’s: 8474L-015-PID-0021-201 / 202 / 203 / 204 / 205 / 206 / 306 / 308 / 307 / 312 / 313 / 314 / 315 / 317. For H-1503, refer to Vendor P&ID’s: 8474L-015-A0103-0160-001-029 / 030 / 031 / 032 / 033 / 034 / 035 / 142 / 143 / 144. For X-1507, refer to Vendor P&ID’s: 8474L-015-A0103-4240-002-128 / 129 / 130 / 131 / 133. 194,650 kg/hr of flue gas at 631°C coming from the first regenerator are sent to the CO incinerator H-1503 at 0.085 kg/cm2g, via flue gas slide valve SV-1503, TI084 and the flue gas block valve BV-1501A for combustion completion. The incinerator burner is supplied with 172,701 kg/hr of combustion air via the forced draft air fans C-1502 A/B, through XV-914 A/B. Combustion air is sent to the CO air ports of the CO combustor via FV-901 and to the auxiliary burners via FV-902. The flue gas from the CO Boiler is routed to the Waste Heat Boiler H-1503 for HP steam regeneration. 86,941 kg/hr of flue gas at 720°C coming from the second regenerator D-1503 are sent straight to the waste heat boiler H-1503 at 0.085 kg/cm2g, via the second regenerator flue gas slide valve and SV-1504 and the COB/WHB 2nd regenerator flue gas block valve BV-1502 A. 526,133 kg/hr of flue gas exiting the waste heat boiler H-1503 at 314°C are sent to the electrostatic precipitator X-1507 before flowing through the economizer E-1525 section of the COB/WHB package, and then to the stack SK-1501 at 236°C. Heat released in WHB H-1503 is used for HP steam generation: 229,892 kg/hr of HP boiler feed water at 112°C is fed from the battery limits to the heavy naphta boiler feed water heater E-1516 where HP BFW is heated to 114.9°C in the tube side against heavy naphta product. The heated BFW is then sent to the tube side of the LCO Pumparound BFW heater E-1511 via TI-484. There the BFW is heated to 121.4°C against LCO pumparound (shell side) drawn off from the main fractionator. The preheated HP BFW leaving E-1511 via TI-434 is then split into 2 streams: •

18,092 kg/hr of the preheated BFW is fed to the slurry HP Steam Generators E-1504 A/B, via FV-443 and FV-441 respectively. In E-1504 A/B HP steam is generated against slurry pumparound pumped by P-1519 A/B/C from the bottom of the main fractionator. The HP steam leaves E-1504 A & B at 200.9°C via FI-444 and FI-442 respectively. It is then recombined before being fed to the HP steam superheater of the waste heat boiler.

•

211,500 kg/hr of the preheated BFW at 121.4°C is sent to the economiser section of the COB/WHB Package H-1503. The preheated BFW first flows through FV-930 to the tube side of the BFW Preheater E-1534 where it is heated up to 165°C against 19,800 kg/hr of MP steam from the MP steam de-superheater. Then preheated BFW flows through TIC-923A and PP-943 Page 254 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

to the Economizer E-1525. In the economizer, the flue gas coming from the electrostatic precipitator X-1507 is used as heating medium. The steam leaving the economizer is then fed to the Steam Drum D-1512, via PP-942 and TI-924. Phosphate is also injected into the Steam Drum D-1512 by means of the Phosphate injection Pump on duty A-1502-P-01-A from the Phosphate Tank A1502-TK-01. The pressure at the pump discharge is monitored locally with PG940. Boiler water then exits the bottom of the steam drum via 3 lines, the inlet of each being equipped with a vortex breaker, and flows to the 4 Evaporator Coil Banks of the WHB H-1503. In each of the Evaporator Coil Banks, steam is generated (tube side) by means of the flue gas exiting the HP superheater of the WHB H-1503. The mixture of steam and boiler water at the outlet of each evaporator coil bank is then routed back to the steam drum via 4 dedicated lines. Boiler water from the steam drum is also fed to the Screen Steam Generator upstream the HP steam Superheater in the Waste Heat Boiler. The steam/boiler water stream generated by the flue gas exiting the CO Combustion exits the Screen Steam Generator and is routed back to the Steam Drum D-1512. Saturated steam from D-1512 is sent to the HP Steam Superheater after being mixed with 18,092 kg/hr of HP steam from E-1504 A/B. In the Superheater, flue gas exiting the Screen Steam Generator generates Superheated HP steam (tube side). The superheated HP steam generated is then de-superheated by means of HP BFW prior to being sent to the Superheated HP steam header via FI-911B. A continuous blowdown from the steam drum is sent to the continous blowdown drum D-1531. The LP steam recovered in D-1531 is sent to the LP steam header while the water collected is sent to the intermittent blowdown drum D-1532 via LV906. The water in D-1532 is cooled down against cooling water in the Blowdown Cooler E-1533 before being sent to the oily water sewer via TG-926 and TI-925. Superheated MP steam is also generated in the WHB: LP Boiler Feed Water is fed to the following MP steam generators in parallel: •

6,498 kg/hr of LP BFW are fed to the HCO recycle MP steam generator E1508, via FV-415, where LP BFW is heated (shell side) against HCO recycle drawn-off from the main fractionator. MP steam leaves E-1508 via FI-416.

•

7,300 kg/hr of LP BFW is fed to the HCO Pumparound MP steam generator E-1523, via FV-421, where LP BFW is heated (shell side) against HCO pumparound drawn off from the main fractionator. MP steam then leaves E1523 towards the MP steam superheater via FT-422A/B. Page 255 of 323


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DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

13,868 kg/hr of LP BFW are fed to the Slurry MP steam generators E-1505 A/B, via FV-447 and FV-445 respectively. In E-1505 A/B LP Boiler Feed Water is heated (shell side) against slurry from the HP steam generators E1504 A/B. MP steam then leaves E-1505 A and B towards the MP steam superheater via FT-448 and FI-446 respectively.

The MP steam streams leaving in the above exchangers are then recombined and 27,666 kg/hr of MP steam at200.9°C are fed to the MP steam superheater downstream of the 4th Evaporator Coil Bank. There, the MP steam is superheated against the flue gas leaving the evaporator. Superheated MP steam is then desuperheated against LP BFW prior to being discharged to the MP steam header. 526,133 kg/hr of flue gas leaving the WHB H-1503 at 314°C is then routed to the Electrostatic Precipitator X-1507, via PG-382, MOV-003, TT-085, TT-086 and TT092. In X-1507, the content of catalyst dust contained in the flue gas leaving the COB/WHB package is decreased to meet the environmental specification: The dust fine content at precipitator outlet shall not exceed 50 mg/Nm3 dry basis. The flue gas leaving the electrostatic precipitator is then sent to the economizer E1525 through PT-389, ROV-001 and TT-093. The flue leaves the economizer at 236°C and is finally sent to the stack via TT-098A/B, and the analyzers AI-018, AI019, AI-020 and AI-021. Steam Generation Blow-down Operation The following steam blow down is recommended for MPS and HPS steam generator to maintain the quality of the generated steam, which are used for turbine: - Continuous blow down: 3.0 % of BFW feed - Intermittent blow down: 10 % of BFW feed For LPS Generator, the facilities are provided to cover continuous and intermittent operation, but blow down operation is normally not required, since LPS is not used for the turbine. Most of LPS is used for stripping steam or heating steam. Phospate chemical injection is required in case steam generators are operated with blowdown. It intended the dosage of phosphate is to maintain 10-20 wt ppm, referring conductivity of BFW in the generator. Phosphate solution is prepared by injection package X-1510. For COB/WHB package, the operation concept is as same as steam generation of the process heat exchanger that injection of phosphate should be adjusted, referring sampling data of BFW in the steam drum of WHB, and continuous blow down flow rate. Phosphate injection Refer to P&ID’s: 8474L-015-PID-0021-332. Page 256 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Phosphate solution, from the tank TK-1510 in the phosphate injection package X1510, is injected to the BFW fed to the following steam generators: •

Slurry HP steam generators E-1504 A/B by means of the phosphate injection pumps P-1531 D/E respectively. The pressure at the pumps discharge can be monitored locally with PG-638 D/E respectively.

•

Slurry MP steam generators E-1505 A/B by means of the phosphate injection pumps P-1532 A/B respectively. The pressure at the pumps discharge can be monitored locally with PG-639 A/B respectively.

•

HCO LP steam generator E-1510, also from the discharge of the phosphate injection pump P-1532B. The pressure at the pumps discharge can be monitored locally with PG-639 B.

•

HCO pump pumparound MP steam generator E-1523, Slurry LP steam generators E-1506 A/B and LCO product LP steam generator E-1513 by means of the phosphate injection pump P-1532C. The pressure at the pumps discharge can be monitored locally with PG-639 C.

•

HCO recycle MP steam generator E-1508 by means of the phosphate injection pump P-1532D. The pressure at the pumps discharge can be monitored locally with PG-639 D.

Fractionation Section Drawing to be inserted here Figure 57: Fractionation Section – Bach Ho Maximum Distillate Case The operating conditions in the main fractionator T-1501 are: Top Pressure: 0.85 kg/cm2g

Top Temperature: 96°C

Bottom Pressure: 1.15 kg/cm2g

Bottom Temperature: 340°C

Fractionator bottom section Refer to P&ID’s: 8474L-015-PID-0021-303 / 304 / 310 / 311 / 312 / 313 / 314 / 315 / 321 / 322 / 323 / 325 / 544,699 kg/hr of reactor effluent at 505°C from the disengager of the reaction section is sent to the bottom of the main fractionator T-1501 below the Bed #5. 1,040,949 kg/hr of bottom slurry pumparound at 340°C flow to the suction of the Slurry Pumparound Pumps on duty P-1519A/B via TIC-439, TI-438, XV-413 and PG521 for P-1519A, XV-414 and PG-522 for P-1519B. At the discharge of the pumps, the slurry PA flows through PG-431 & XV-416 for P-1519A, PG-432 & XV417 for P-1519B, and FI-423 (on the common discharge header) before being delivered to the following downstream equipment at 339.9°C: In the case of Bach Ho feed, a large proportion of the bottom pumparound duty is used to preheat the feed in the 1st & 2nd Feed Preheat Slurry Exchangers E-1502 A/B/C and E-1501 A/B:

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DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

290,000 kg/hr of Slurry PA are pumped by P-1519 A/B to the shell side of the 2nd feed preheat slurry exchangers E-1501 A & B in parallel. The slurry leaving the shell side of E-1501A flows through TW-529, FIC-406 and FV406, before being mixed with the slurry PA leaving the shell side of E1501B through TW-530, FIC-501 and FV-501. The recombined slurry PA leaving E-1501 A&B then flows to the slurry PA return header, thru TI-422 indicating a normal operating temperature of 309.9°C. The total duty of the 2nd feed preheat slurry exchangers is 6.75 MW.

•

310,000 kg/hr of Slurry PA flow from the discharge of P-1519 A/B to the 1st feed preheat slurry exchangers E-1502 C, B and A in series as follow: the slurry PA flows thru E-1502C (shell side), TW-413, E-1502B (shell side), TW-532, E-1502A (shell side). Downstream of E-1502A, the slurry PA flows through TW-531, and TI-423 indicating a normal operating temperature of 254.4°C before being split into 2 streams: o 220,000 kg/hr of slurry PA flow thru FIC-407 and FV-407 to the slurry quenching header and are returned to the quench zone of the main fractionator T-1501. o 90,000 kg/hr of slurry PA flow thru FIC-408 and FV-408 to the slurry PA return header and are returned to T-1501 above the Bed #5. The total duty of the 1st feed preheat slurry exchangers is 19.95 MW.

The remaining slurry PA, that is 440,949 kg/hr of slurry is supplied to the Slurry HP steam generators E-1504 A/B and the MP steam generators E-1505 A/B divided in 2 branches (A & B) as follow: •

Part of the slurry PA flows through the tube side of E-1504A, exits via TI468, flows through the tube side of E-1505A. Downstream of E-1505A the slurry flows thru TI-469, FIC-438 and FV-438 before being recombined with the Slurry PA leaving the branch B.

•

An equal amount of slurry PA flows through the tube side of E-1504B, exits via TI-466, flows through the tube side of E-1505B. Downstream of E1505B the slurry flows thru TI-467, FIC-437 and FV-437 before being recombined with the Slurry PA leaving the branch A.

The total duty of the Slurry HP steam generators E-1504 A/B is 11.67 MW and the total duty of the MP steam generators E-1505 A/B is 9.22 MW. Once recombined the slurry PA leaving E-1505 A&B flows thru TI-470 indicating a normal operating temperature of 220°C before being split into 2 streams: •

193,021 kg/hr of slurry PA flow thru FIC-439 and FV-439 to the slurry quenching header and are returned to the quench zone of the main fractionator T-1501.

•

17,321 kg/hr of slurry PA flow thru FIC-440 and FV-440 to the slurry PA return header and are returned to T-1501 above the Bed #5.

At the discharge of the slurry PA pumps P-1519 A&B, 204,685 kg/hr of slurry PA bypass is directly returned to the Bed #5 of the main fractionator thru FT-426A/B and FV-426. The total amount of slurry PA return to T-1501, that is 602,006 kg/hr of slurry PA return, is returned to the bed #5 of the main fractionator T-1501 via TI-441. Page 258 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

The total amount of slurry quenching, that is 413,021 kg/hr of slurry, is returned to the quench zone of the main fractionator via TI-440. Note: The slurry HP steam generators E-1503 A-C are bypassed in the Bach Ho operation. 25,930 kg/hr of slurry product at 220°C is taken from the discharge of the MP steam generators E-1505 A/B, downstream of TI-470, and flow to slurry draw-off drum D-1515 via FIC-462, FV-462 and XV-451. D-1515 is operated at 220°C and 1.0 kg/cm2g. The pressure in D-1515 is maintained at 1.0 kg/cm2g by admitting fuel gas thru PV-468A or venting excess off gas thru PV-468B. The slurry product flows to the suction of the Slurry Product Pump on duty P1504A, via TI494 and PG-526, which pumps it to the Slurry LP Steam Generator on duty E-1506 A via PG-469. The duty of E-1506A is 0.879 MW. Downstream of E-1506 A, the cooled slurry flows, via TI-495, TIC-496 and PG574, to the slurry oil pre-filter on duty F-1503A before entering the Slurry Separator X-1504 where catalyst fines are removed. The differential pressure across the filter is monitored with PDI-398 and PDG-395. 27,930 kg/hr of clarified oil leave the slurry separator X-1504 and flow to the tempered water coolers E-1507 B & A in series (C & D are bypassed) before going to storage at 90°C and 8.0 kg/cm2g thru TI-499, FIC-464 and FV-464. The total duty of E-1507 A&B is 1.32 MW. The slurry separator X-1504 consists of 10 modules. These are automatically and sequentially taken out of service for back-flushing while the others remain in service. The modules are back-flushed with Backflush Oil (HCO) from the Backflush Oil Draw Off Drum D-1516. Backflush oil flows from the bottom of D1516 to the suction of P-1505A via TI-503. The backflush oil is pumped by means of the backflush oil pump on duty P-1505A to the slurry separator X-1504 via PG481, FIC-468, FV-468 and UV-460. The flush oil from the separator, containing a high concentration of catalyst fines, goes to back-flush oil receiver D-1517 via XV-459 after being mixed with HCO flowing from E-1510 via FIC-460 and FV-460. The pressure in D-1517 is maintained at 1.0 kg/cm2g by either admitting fuel gas inside the vessel via PV475A or venting excess off gas to the flare via PV-475B. From D-1517, 6,875 kg/hr of backflush oil is returned to the reactor riser by means of the backflush oil recycle pump on duty P-1506A and thru PG-477 and FIC-491. The flow of backflush oil recycle to the backflush oil injectors of the riser is kept constant by controlling the flow of backflush oil sent back to D-1517 via FV-491 from the discharge of P-1506A. The temperature of the recycle oil leaving the bottom of D-1517 is monitored via TI-502. HCO section Refer to P&ID’s: 8474L-015-PID-0021-121 / 308 / 309 / 316 / 317 / 325 / 326 / 409

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DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

HCO products, pumparound and HCO recycle are taken from the draw off tray above the Bed #4 of the main fractionator T-1501. 364,913 kg/hr of HCO pumparound at 337°C flow to the suction of the HCO Pumparound Pump on duty P-1508A via TI-444 and XV-409. HCO PA is pumped via PG-425, XV-411 and FIC-419 to the following equipment in parallel: •

199,500 kg/hr of HCO PA at 337°C are pumped to the tube side of the Debutanizer reboilers E-1560 A & B (equal amount to each exchanger). HCO PA leaves E-1560A via TW-759 and E-1560B via TW-760 before being recombined and sent to the HCO PA return header via FV-722 and TI-761. The duty of the debutanizer reboilers is 18.17 MW.

•

32,842 kg/hr of HCO PA at 337°C are pumped to the shell side of the Heavy Naphtha Stripper Reboiler E-1509 via FIC-454 and FV-454. The HCO PA leaves E-1509 via TI-483 to the PA return header. The duty of E1509 is 2.00 MW.

•

55,121 kg/hr of HCO PA at 337°C are pumped to the tube side of MP Steam Generator E-1523. The HCO PA leaves E-1523 at 220.1°C and flows thru TI-435, FT-420A/B and FV-420 to the HCO PA return header. The duty of E-1523 is 4.83 MW.

•

77,450 kg/hr of HCO bypass is sent directly to the HCO PA return header via FV-419 from the discharge of the HCO PA pump on duty.

HCO PA is then returned to the main fractionator, above the Bed #3, via TIC-446 and TI-445. HCO for flushing oil is also taken from the draw off tray above the Bed #4 of the main fractionator T-1501 and flows thru LV-431 to the HCO stripper T-1504 where it is stripped by means of 788 kg/hr of LP steam at 160°C. LP steam flows from the LP steam header to T-1504 via FIC-449 and FV-449. The stripper vapour leaving T-1504 via TI-471 and PG-443 is returned to T-1501 just below the tray #30. 26257 kg/hr of stripped HCO at 324.2°C flow from the bottom of T-1504 to the suction of HCO product pump on duty P-1509 A, via TI-472 and XV-430. HCO product is pumped thru FIC-474 to the tube side of the LP Steam Generator E1510. Cooled HCO leaves the tube side of E-1510 at 170°C and is split into 2 streams: •

3479 kg/hr of HCO are sent to the backflush oil draw off drum D-1516 (for use in the slurry separator as described above) via FV-467. D-1516 is operated at 170°C and 1.0 kg/cm2 by either admitting fuel gas into the drum via PV-479A or venting excess off-gas to the flare via PV-479B.

•

22,278 kg/hr of HCO product at 170°C are set to the HCO flushing oil drum D-1518 via FIC-469 and FV-469. The pressure in the HCO flushing oil is maintained constant by either admitting fuel gas thru PV-483A or venting excess off-gas to flare via PV-483B. HCO flushing oil flows from the bottom of D-1518 to the suction of the HCO flushing oil pump on duty P-1521A via TI-504. HCO flushing oil is pumped to the HCO flushing oil filter on duty F-1502A via FIC-461, PIA-487 and PG-520. Downstream of FIC-461, a slip stream of the HCO flushing oil is recycled back to D-1518 via FV-461. Page 260 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

Filtered HCO flushing oil then flows thru FI-470 to the HP flush oil header. Part of the HCO flushing oil is sent to the LP Flush Header on pressure control via PV-496. For maximum distillate mode operation, HCO is recycled to the reactor feed. 117,100 kg/hr of HCO recycle is taken from the draw off tray above the Bed #4 and flows to the suction of the HCO recycle pump on duty P-1507A via XV-406. HCO recycle is pumped to the tube side of the HCO recycle MP steam generator E-1508 via PG-411 and XV-408. HCO recycle leaves E-1508 thru TW-424 and PDV-420. Part of the HCO recycle bypasses E-1508 thru TV-425 and is mixed with the HCO leaving E-1508 downstream of PDV-420. The recombined HCO flows at 290°C thru TIC-426, TI-426, FIC-002 and FV-002 to the reaction section where is mixed with the preheated feed upstream of the feed line static mixer M1501. LCO section Refer to P&ID’s: 8474L-015-PID-0021-302 / 307 / 309 / 318 / 328 / 405 LCO product and LCO pumparound are drawn off thru TI-449 from the pumparound draw-off tray below the bed#2 of the main fractionator. 733,664 kg/hr of LCO pumparound at 230.3°C flow to the suction of the LCO Pumparound Pump on duty P-1510A. LCO PA is pumped via PG-422 and FIC417 to the following equipment in parallel: •

91,555 kg/hr of LCO PA at 230.3°C are pumped to the shell side of the LCO PA BFW heater E-1511. LCO PA leaves E-1511 at 194.9°C and flows via TI-432, FT-418 A/B and FV-418 to the LCO PA return header. The duty of E-1511 is 2.24 MW.

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400,000 kg/hr of LCO PA at 230.3°C are pumped to the 2 branches of the LCO pumparound feed preheat exchangers E-1512 A/B/C/D as follow: o 200,000 kg/hr of LCO PA flows to E-1512B (tube side), TW-416, E1512A (tube side) and TW-418 before being recombined with the LCO PA leaving the other branch. o 200,000 kg/hr of LCO PA flows to E-1512D (tube side), TW-417, E1512C (tube side) and TW-419 before being recombined with the LCO PA leaving the other branch. LCO leaving E-1502A and E-1502C is recombined and 400,000 kg/hr of LCO at 176°C flows to the LCO PA return header via FIC-409, TI-420 and FV-409. The total duty of E-1512 A-D is 14.79 MW.

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168,743 kg/hr of LCO PA at 230.3°C are sent to the tube side of the 2nd stripper reboiler E-1557 via FIC-710. The LCO PA leaves E-1557 and flows to the LCO PA return header via TI-730 and FV-710. The duty of E-1557 is 8.97 MW.

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73,366 kg/hr of LCO bypass is sent directly to the LCO PA return header via FV-417 from the discharge of the LCO PA pump on duty.

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DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

HCO PA is then returned to the main fractionator above the Bed #2, via TIC-452 and TI-451. LCO product is taken as a slip stream at the suction of the LCO pumparound pumps P-1510 A/B and is sent to the tray #1 the LCO stripper T-1503, via LV-436, where the LCO is stripped with 300 kg/hr of LP steam. The LP steam flows from the LP steam header to the LCO stripper T-1503 via FIC-452 and FV-452. The stripper vapour leaving T-1503 via TI-475 and PG-448 is returned to T-1501 just below the tray #24. Stripped LCO flows to the suction of the LCO Stripper Pump on duty P-1511 A via TI-476. LCO product is pumped to the tube side of the LCO product LP steam generator E-1513 (duty = 5.65 MW) via PG-449. Downstream of P-1511 A/B, a slip stream of the LCO product is recycled back to the LCO stripper via FT-478. LCO product leaving the tube side of E-1513 at 158°C flows through TI-505 to the LCO air cooler E-1514 (duty = 8.66 MW) and exits via TI-512 before being split into 2 streams: •

139,198 kg/hr of LCO are sent to the storage at 50°C and 6.0 kg/cm2g via FIC-472, FV-472, TI-513, FI-473 and TI-514. For maximum LCO operation (maximum distillate operation), heavy naphtha from the Heavy Naphta Trim Cooler E-1516 is mixed with this stream before it is sent to storage

•

165160 kg/hr of LCO are sent to the LCO HDT at 48.7°C and 6.0 kg/cm2g via FIC-479 and FV-479. For maximum LCO operation (maximum distillate operation), heavy naphtha from the Heavy Naphta Trim Cooler E-1516 is also mixed with this stream before it is sent to the LCO Hydrotreater unit.

MTC and heavy naphtha section Refer to P&ID’s: 8474L-015-PID-0021-305 / 309 / 317 / 328 / 405 / 407 MTC is NOT drawn off from tray #19 of the main fractionator in the Bach Ho Crude operation. Heavy naphtha pumparound and heavy naphta product are drawn off from the draw-off tray below the bed #1 of the main fractionator. 508,243 kg/hr of heavy naphta (HVN) pumparound at 161.6°C flow to the suction of the heavy naphta PA pump on duty P-1514A. HVN PA is pumped via PG-415 and FIC-412 to the following equipment in parallel: •

149,489 kg/hr of HVN PA are pumped to the HVN PA Cooler E-1521 where it is cooled down to 54.9°C. HVN PA leaving E-1521 flows through TI-427, FT-414 A/B and FV-414 to the HVN PA return header. The duty of E-1521 is 9.52 MW.

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50,824 kg/hr of heavy naphta PA are pumped to the stripper feed preheater E-1555 in the gas recovery section via FI-726. The heavy naphta PA leaving E-1555 flows back to the Heavy Naphta PA return header via TI725 and TV-723. The duty of E-1555 is 1.48 MW.

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DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

200,000 kg/hr of heavy naphta PA are pumped to the Propylene Recovery Unit (PRU, unit 21) via TI-413. Heavy naphta PA is returned from the PRU thru TI-428 to the heavy naphta PA return header.

Heavy Naphta PA is then returned thru TIC-430 and TI-429 to the main fractionator T-1501 on top of the bed #1. Heavy naphta product is taken as a slip stream of the pumparound draw-off at the suction of the P-1514 A/B and is sent to the tray #1 of the heavy naphta stripper T1502 via LV-439. T-1502 bottoms flow to the tube side of the reboiler E-1509 via TI-478 where it is heated against HCO PA. Re-boiled heavy naphta is returned t T1502, below the tray #8 via TI-482. The duty of the HVN reboiler E-1509 is 2.00 MW. The stripper vapour leaving T-1502 via TI-477 and PG-451 is returned to the main fractionator above the pumparound bed, Bed #1. 25,962 kg/hr of stripped heavy naphtha flow from the bottom of T-1502 to the suction of the HVN product pump on duty P-1515A. HVN product is pumped to the shell side of the HVN BFW Heater E-1516 via PG-452. In E-1516, HVN is used as heating medium to preheat BFW (tube side) which is then sent to E-1511. The duty of E-1516 is 0.985 MW. Heavy naphta leaving the shell side of E-1516 is then sent to the heavy naphta air cooler E-1517 (duty = 1.69 MW) via TI-479. The heavy naphta leaving E-1517 is then sent thru TI-480 to the HVN Trim Cooler E-1518. The duty of the HVN trim cooler E-1518 is 0.135 MW. 25,962 kg/hr of heavy naphta leaving the trim cooler E-1518 at 40°C flow through FIC-435, FV-433 and TI-485 before being mixed with the LCO product sent to the LCO HDT and storage downstream of the LCO air cooler E-1514. Heavy naphtha is also drawn off at the suction of the HVN PA pumps P-1514 A/B as lean oil for the secondary absorber in the Gas recovery Section. The lean oil is pumped by P-1513A at 9.5 kg/cm2g to the tube side of the Lean Oil / Rich Oil Exchanger E-1563, in the gas recovery section. Top section Refer to P&ID’s: 8474L-015-PID-0021-309 / 319 / 407 Rich oil from the bottom of the secondary absorber in the Gas Recovery Section is fed to tray #9 of the main fractionator. Water accumulated in the partial draw-off accumulator tray, provided below the top tray, is continuously drawn off and flows by gravity to the inlet of overhead condenser E-1519 via TI-458, LV-416. Fractionator overhead section Refer to P&ID’s: 8474L-015-PID-0021-309 / 319 / 320 / 403 / 404 / 405

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DATE: 06/12/07

The overhead vapor from T-1501 flows thru TI-460 and TIC-461 at 96°C and 0.85 kg/cm2g to the overhead condenser E-1519 (total duty = 47.31 MW), comprising of 16 bundles. It is mixed with the water draw-off from the tray #9 of the main fractionator. Corrosion inhibitor is also supplied to the overhead vapour at the inlet of E-1519: 2.5 kg/hr of corrosion inhibitor is supplied from the corrosion inhibitor tank TK-1501 to the inlet of E-1519 by means of the corrosion inhibitor pump on duty P-1520A. Pressure at the pump discharge can be checked locally by means of PG-467. Downstream of the overhead air condenser E-1519, the overhead vapour from T-1501 flows thru TI-536 to the 8 overhead trim condensers E-1520 A to H in parallel (total duty = 16.12 MW). Partly condensed overheads leaving the trim condensers E-1520 A-H flow thru TI-489 to the fractionator reflux drum D1514. The following off-gases are also fed to the reflux drum: •

291kg/hr of off gas from the CDU at 50°C and 0.7 kg/cm2g are also fed to D-1514 via FI-458 and TI-492.

•

243 kg/hr of off gas from the NHT at 40°C and 0.6 kg/cm2g are also fed to D-1514 via FI-457 and TI-491.

The liquid hydrocarbon separated in D-1514 is separated into 2 streams: •

201,987 kg/hr of liquid hydrocarbon flow from the main fractionator reflux drum thru XV-444 and TI-490 to the suction of the fractionator reflux pump on duty P-1516A: Liquid reflux is pumped back to the tray #1 of the main fractionator at 42.2°C via PG-463, FIC-427 and FV-427.

•

84,726 kg/hr of net overhead liquid product flow from the main fractionator reflux drum thru XV-444 and TI-490 to the suction of the overhead liquid pump on duty P-1518A. Net overhead liquid is pumped at 42.5°C, thru FIC455 and FV-455, to the top tray of the primary absorber T-1551. Liquid sent to the primary absorber T-1551 is flow controlled by FIC-455 with FV-455. Excess liquid pumped by P-1518A is sent back to the main fractionator reflux drum D-1514 via FT-477.

The sour water collected in the boot of the fractionator reflux flows to the suction of the overhead sour water pump on duty P-1517A via XV-445. Downstream of P1517 A/B discharge, the flow of sour water is spit into 3 streams: •

30,000 kg/hr of overhead sour water are pumped back to the overhead condenser E-1519, via FIC-459, FV-459 and thru a restriction orifice.

•

28,000 kg/hr of overhead sour water are pumped to the inlet of E-1551, via FIC-703, FV-703 and RO-715A, for mixing with the wet gas from the first stage of C-1551.

•

5252 kg/hr of sour overhead water are pumped to the SWS (unit 18), via FIC-456, FV-456 and TI-736, after being mixed with the sour water collected in the boot of the HP separator drum D-1553.

Finally, 118,909 kg/hr of overhead vapour from D-1514 flows to the first stage KO drum of the wet gas compressor D-1551 at 41.9°C via PIC-458, PG-457, and TI703.

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The main fractionator reflux drum is operated at 42°C and 0.4 kg/cm2g. The pressure in the gas outlet of D-1514 is controlled by PIC-458 by venting excess off-gas thru PV-458 to the flare. Gas Recovery section Drawing to be inserted here Figure 58: Gas Recovery Section – Bach Ho Max. Distillate Case Wet gas compressor and HP condenser Refer to P&ID’s: 8474L-015-PID-0021-401 / 402 / 403 / 404 118,909 kg/hr of wet gas from the Main Fractionator Reflux Drum D-1514 flows to the wet gas compressor first stage knock-out drum D-1551 via PIC-458, PG-457, and TI-703. In D-1551 entrained and condensed liquids are separated. The liquid collected in D-1551 is pumped by either of the KO drum liquid pumps P-1552 A/B back to the fractionator reflux drum D-1514. The first stage KO drum D-1555 is operated at 0.3 kg/cm2g and 42°C. The gas from D-1551 flows to the 1st stage of the compressor C-1551 via FT-701, MOV-703 PG-704, and PT-703. The wet gas exits the first compression stage at 4.1 kg/cm2g and 102°C and flows through PG-706, PT-705, TT-702 and MOV-704 before being split into 2 streams: •

A spill back stream is returned back to E-1519 via FI-704 and UV-701

•

The majority of the wet gas is sent for cooling in the wet gas compressor intercooler E-1551. Before entering the intercooler E-1551, the wet gas is mixed with 28,000 kg/hr of sour water pumped by P-1517A from the boot of the main fractionator reflux drum D-1514. The duty of E-1551 is 8.32 MW.

Downstream of E-1551, the wet gas flow thru TW-720A and TI-704 to each of the two wet gas compressors trim-coolers E-1552 A&B in parallel. The total duty of E1552 A/B is 2.08 MW. Downstream of E-1552 A/B, the wet gas is sent to the interstage KO drum D-1552 via TI-709 indicating a normal operating temperature of 42°C. The inter-stage KO drum D-1552 is operated at 3.4 kg/cm2g. 63,712 kg/hr of wet gas leaving D-1552 at 3.4 kg/cm2g flow to the second stage compressor C-1551 via PG-708, PIC-707, FT-702, MOV-705, TT-710, PG-710 and PT-709. The wet gas leaving the 2nd stage is compressed to 15.9 kg/cm2g. Downstream of the second stage compressor, the majority of the wet gas flows at 114°C and 15.9 kg/cm2g to the HP condenser E-1553, via PG-712, TXA-632, PT711, TT/TI-711 and MOV-706. A slip stream of the compressed wet gas is recycled back to the inlet of E-1551 via FI-705 and UV-702. Before entering the HP condenser, the compressed wet gas is mixed with 83,197 kg/hr of interstage liquid at 42.3°C. The interstage liquid is pumped from the bottom of the interstage KO drum D-1552 to the inlet of the HP condenser E-1553 by means of the interstage pump P-1551A, thru FI-727 and LV-705. The duty of the HP steam condenser E-1553 is 5.59 MW. The partly condensed wet gas stream leaving the HP condenser E-1553 is fed to the stripper condensers E-1554 A/B/C/D via TI-713. Page 265 of 323


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Stripper condenser and high pressure separator drum Refer to P&ID’s: 8474L-015-PID-0021-404 / 405 The following streams are combined before being fed to the stripper condensers E-1554 A/B/C/D: •

127,834 kg/hr of liquid at 56.8°C from the bottom of the primary absorber T1551 via TI-721, FI-708 and LV-710.

•

2071 kg/hr of LPG at 52°C and 20.0 kg/cm2g from the CDU (unit 11) via FI741 and TI-714.

•

22,703 kg/hr of stripper overhead at 59.8°C from the stripper T-1552 via TI722, FIC-709 and PG-717.

The combined stream flows through TI-715 before being split into 2 equal streams, each flowing in one of the 2 parallel branches constituting the stripper condensers E-1554A-D (duty = 4.51 MW): One half of the combined stream flows through the shell side of E-1554B and then E-1554A (shell side) before exiting this branch of the stripper condensers thru TW-716. The other half of the combined stream flows through the shell side of E-1554D and then E-1554C (shell side) before exiting this branch of the stripper condensers thru TW-717. The mixed phase streams leaving E-1554Aand E-1554C are recombined before entering the HP separator drum D1553 via TI-720. The HP separator D-1554 is operated at 15.1 kg/cm2g and 40°C. 30,572 kg/hr of water collected in the boot of the HP separator is sent to the SWS at 40°C and 3.5 kg/cm2g via XV-716, LV-714, FI-712 and TI-736, after mixing with 5252 kg/hr of sour water pumped from the main fractionator reflux drum D-1514 by P-1517A. 243,294 kg/hr of LPG and gasoline mixture at 40°C flow from D-1554, thru XV-719 and TI-726, to the suction of the stripper feed pump on duty P-1553A. This hydrocarbon mix constitutes the feed of the stripper T-1552; It is first pumped to the stripper feed preheater E-1555 via PG-721, FIC-711 and FV-711. The flow of feed to E-1555 is controlled by FIC-711 acting on FV-711. The excess liquid at the pump discharge is recycled to the separator drum D-1554 via FT/FI-728. The duty of the stripper feed preheater is 1.48 MW. Preheated stripper feed leaving E-1555 flows thru TIC-723 and TI-724 to the first tray of the stripper. 25,634 kg/hr of vapour phase from D-1553 is flow thru PG-719, PIC-718 and FI707 to the primary absorber T-1551 (below the last tray). Primary absorber T-1551 Refer to P&ID’s: 8474L-015-PID-0021-404 / 405 Normal operating parameters of the primary absorber for the Bach Ho MD Case: Top Pressure: 14.8 kg/cm2g


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84,726 kg/hr of net overhead liquid product at 42.5°C from the main fractionator reflux drum is pumped by P-1518A, thru FIC-455 and FV-455, to the top tray of the primary absorber T-1551. Downstream of the Gasoline Cooler E-1559, 30,000 kg/hr of gasoline (from the bottom of the debutanizer T-1554) are also recycled to the inlet of the primary absorber T-1551 by means of the duty gasoline recycle pump P-1554A: Gasoline flows to the suction of the pump via PG-728 and is pumped to the inlet of T-1551 for mixing with the net overhead liquid product, via PG-729, FIC-713 and FV-713. This flow of gasoline recycle enables required recovery of C3 and C4. 127,834 kg/hr of bottom rich oil from leaves the bottom of the primary absorber T1551 and flows through TI-721, FI-708 and LV-710, back to the inlet of the stripper condensers E-1554 A-D. 12,519 kg/hr of overheads leave the top of the primary absorber T-1551 at 14.8 kg/cm2g and 48°C and flow thru PG-726, FI-717 and TI-738 to the secondary absorber T-1553, below the tray #20. Stripper Refer to P&ID’s: 8474L-015-PID-0021-404 / 405 / 409 The purpose of the stripper is to remove H2S, C2 and lighter from The LPG and gasoline mixture. Normal operating parameters of the stripper for the Bach Ho MD Case: Top Pressure: 15.7 kg/cm2g




243,294 kg/hr of preheated LPG and gasoline mixture feed leaving E-1555 flows thru TIC-723 and TI-724 to the first tray of the stripper. The necessary heat to perform the stripping operation is supplied by two reboilers in series: The stripper bottoms flow thru TI-727 to the shell side of the first reboiler E-1556 (duty = 4.62) where it is heated up against gasoline form the bottom of the debutanizer T-1554. Stripper bottoms then flow to the shell side of the second reboiler E-1557 (duty = 8.97) where it is heated against 168,743 kg/hr of LCO PA from the main fractionator. The heat input to E-1557 is controlled by the stripper overhead vapor rate FIC-709. This rate, and hence the reboiler duty, is set to meet the C2 specification in the debutanizer overheads. 22,703 kg/hr of overhead vapour leaving the stripper at 59.8°C is returned to and condensed in E-1554 A-D via TI-722, FIC-709 and PG-717. 220,591 kg/hr of stripped LPG and Gasoline leave the bottom of the stripper T1552 at 126°C and flow to the tray #22 of the debutanizer via TI-728, FIC-714 and FV-714

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Secondary absorber T-1553 Refer to P&ID’s: 8474L-015-PID-0021-404 / 407 / 408 The secondary absorber T-1553 recovers gasoline light fractions contained in the overhead gas from primary absorber T-1551. 12,519 kg/hr of overheads leave the top of the primary absorber T-1551 at 14.8 kg/cm2g and 48°C and flow thru PG-726, FI-717 and TI-738 to the secondary absorber T-1553, below the tray #20. The lean oil used for the absorption is a heavy naphtha stream draw-off from the main fractionator T-1501 (draw-off tray below the bed #1) and pumped by P-1513 A to the tube side of the lean oil/rich oil exchanger E-1563 (duty = 1.14 MW). Lean oil then flows thru TI-749 to the shell side of the lean oil cooler E-1564 where it is cooled against cooling water. The duty of E-1564 is 1.36 MW. Cooled lean oil leaving E-1564 then flows through TI-751 and PG-734 to the lean oil coalescer D-1556 where water is separated from the hydrocarbon phase. The sour water collected in the boot of D-1556 is then sent to the SWS via XV-725, LV723, FI-712 and TI-736, after mixing with sour water from the fractionation section, D-1553 and D-1554. 34,990 kg/hr of lean oil at 40.2°C flow from D-1556 to the top tray of the secondary absorber T-1553 via PG-736, FIC-718 and FV-718. Normal operating parameters of the secondary absorber for Bach Ho MD Case: Top Pressure: 14.4 kg/cm2g




The rich oil at 59°C from the bottom of the secondary absorber T-1553 flows thru TI-739 and LV-720 to the lean oil/rich oil exchanger E-1563 where it recovers heat before being recycled to the tray #9 of the Main Fractionator T-1501, via TI-740 and TI-787. The stripped overhead gas leaving T-1553 flows thru TI-741, PIC-733 and PG-766 to the shell side of the fuel gas water cooler E-1565 (duty = 0.042 MW). Cooled fuel gas then flows thru TI-743 to the Fuel Gas Absorber Feed KO Drum D-1557. Fuel gas absorber Refer to P&ID’s: 8474L-015-PID-0021-408 The small amount of liquid in the effluent from E-1565 is separated in the K.O. drum D-1557. The liquid is sent to mixing with rich oil at the inlet of the lean oil/rich oil exchanger E-1563 via LV-726. The FG Absorber Feed KO Drum D-1557 is operated at 40°C and 14.1 kg/cm2g. The overhead gas of the FG absorber feed KO drum is fed to the bottom of the Fuel Gas Absorber T-1555 via TI-744. 18,127 kg/hr of lean amine at 55°C and 22,6 kg/cm2g flow from the ARU (unit 19) thru FIC-719, FV-719 and TI-745 to the top of the fuel gas absorber T-1555. Normal operating parameters of the Fuel Gas Absorber for Bach Ho MD Case: Top Pressure: 13.7 kg/cm2g

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Once treated by the lean amine, the overhead gas is sent to the Fuel Gas Absorber Outlet K.O. drum D-1559, where entrained and condensed liquid are separated. 8661 kg/hr of treated fuel gas leave the top of the FG Absorber Outlet KO Drum D-1559 and flow to the fuel gas system at 4.5 kg/cm2g and 54°C via PG-741, TI-747, FI-720 and PV-733. A total of 18127 kg/hr of rich amine is sent back to the ARU at 64°C and 7.0 kg/cm2g. This stream is composed of: •

Mainly rich amine leaving the bottom of the FG Absorber T-1555 via XV732, LV-730 and TI748;

•

Rich amine separated in the KO drum D-1559 and flowing thru XV-735 and LV-733 to mixing with the rich amine from T-1555 downstream of TI-748.

Debutanizer Refer to P&ID’s: 8474L-015-PID-0021-405 / 406 / 409 / 410 / 411 220,591 kg/hr of stripped LPG and Gasoline leave the bottom of the stripper T1552 at 126°C and flow to the tray #22 of the debutanizer via TI-728, FIC-714 and FV-714 Normal operating parameters of the secondary absorber for Bach Ho MD Case: Top Pressure: 12.1 kg/cm2g




The heat required to perform the separation is provided by the debutanizer reboilers E-1560 A&B: An equal amount of debutanizer bottoms flow to the shell side of each reboiler where it is heated against HCO PA from the main fractionator. Re-boiled bottoms then leave E-1560 A and B and flow thru TI-770 and TI-758 respectively, back to the debutanizer below the bottom tray. The reboilers duty (18.17 MW) is set to ensure that the C4 specification in the gasoline is met. The overhead vapour leaves the debutanizer at 68°C and 11.7 kg/cm2g and flows thru TI-762, PG-744 and PIC-745 to the debutanizer condensers E-1561 A & B in parallel, where the overhead vapour are totally condensed. Condensed overheads are then fed to the debutanizer feed surge drum D-1554. The pressure in T-1554 is controlled with PIC-745 by bypassing part of the overhead vapour around E-1561 A/B to the reflux drum D-1554, via PV-745. The duty of the debutanizer condensers is 16.08 MW. The sour water collected in the reflux drum D-1554 is sent to the SWS via XV-741, LV-739, FI-712 and TI-736, after mixing with sour water from the fractionation section, D-1553 and D-1556.

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DATE: 06/12/07

The hydrocarbon liquid of the debutanizer reflux drum flows thru XV-744 to the suction of the debutanizer overhead pump on duty P-1556A. Downstream of P1556A the hydrocarbon is split into 2 streams: •

106,325 kg/hr of HC are sent to the tray #1 of the debutanizer as a reflux via FIC-721 and FV-721. The reflux rate is flow controlled by FIC-721 reset by the temperature controller TIC-754 on the sensitive tray (tray #8) in the top section of the column. This control loop determines the C5 specification in the overhead product.

•

57,044 kg/hr of overhead liquid, the LPG product, flow to the shell side of the LPG water cooler E-1562 (duty = 0.342 MW). Cooled LPG leaving the shell side of E-1562 at 40°C then flow thru TI-768, FIC-723, FV-723 and PG-755 to the bottom of the LPG Amine Absorber T-1556.

The gasoline product leaving the bottom of the debutanizer T-1554 at 171°C then flows thru XV-738, TI-755 to the tube side of the stripper first reboiler E-1556. Downstream of E-1556, the gasoline product flows thru TI-731 to the gasoline air cooler E-1558 (duty = 9.00 MW). Gasoline then flows thru TI-732 to the gasoline water cooler E-1559 (duty = 0.957 MW). Downstream of E-1559, the gasoline stream is split in 2: •

30,000 kg/hr of gasoline are recycled by means of the gasoline recycle pump P-1554A to the inlet of T-1551.

•

133,547 kg/hr of gasoline, the gasoline product, flow thru FIC-715, FV-715, FI-716 and TI-735 to the gasoline treating unit at 8.5 kg/cm2g and 40°C.

LPG amine absorber T-1556 Cooled LPG leaves the shell side of E-1562 at 40°C and flows thru TI-768, FIC723, FV-723 and PG-755 to the bottom of the LPG Amine Absorber T-1556. 23,331 kg/hr of lean amine at 55°C and 22.6 kg/cm2g flow from the ARU thru the shell side of the lean amine water cooler E-1566, TI-772, FIC-724 and FV-724 to the LPG Amine Absorber above the top packing bed. The overhead LPG liquid flows thru PG-757, TI-795, and PDI-761 to the LPG amine coalescer D-1555. The LPG Amine Coalescer is operated at 18.4 kg/cm2g and 40°C. 57,023 kg/hr of LPG overheads from D-1555, the LPG product, is sent to the LPG Treater Unit (LTU, unit 16) at 40°C and 18 kg/cm2g. A total of 23,352 kg/hr of rich amine is returned to the ARU at 7.0 kg/cm2 and 41°C. This stream is composed of: •

Mainly rich amine leaving the bottom of the LPG Amine Absorber thru XV748, LV-746 and TI-771;

•

Rich amine leaving the boot of the LPG amine coalescer D-1555 thru XV751, LV-749 and sent to mixing with the rich amine from T-1556, downstream of TI-771.

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8.1.2. Operating Parameters For guidelines on the operating parameters of the RFCC and how to adjust the operating conditions, refer to the chapters 7.3, 7.4, 7.5, 7.6 and 7.7 of the licensor operating manual, doc. No. 8474L-015-ML-001. 8.2. Start-up Procedure The following will present the main steps of the start-up procedure without detailing the procedure to perform each action. For a detailed description of the start-up procedures, refer to specific procedures into the RFCC Operating Manual doc. No. 8474L-015-ML001.

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DATE: 06/12/07

8.2.1. Pre-commissioning Activities These are the necessary pre-commissioning activities: 1. Vessel and other Major Equipment Inspection 2. Line Cleaning 3. Servicing and Calibration of Instruments 4. Run-in of Rotary machineries 5. Chemical Cleaning 6. Refractory Drying 7. System Drying 8. Loading of Chemicals, Catalysts, and Other Materials 9. Operational Tightness Test 10. Air Freeing 11. Commissioning of Additional Plant Services 8.2.2. Initial Start-up 8.2.2.1. Status of the Unit prior to first start-up The status of the unit prior to its initial start-up is as follows: •

Tightness test and nitrogen purges have been completed (O2 < 0.5% volume) on the feed preparation section.

•

Free water trapped has been drained at low points.

•

All necessary utilities are in service: blinds on the headers have been swing open and valves opened on all users.

•

All instrumentation has been checked and is in service.

•

The emergency shutdown systems have been tested and are ready for operation.

•

On disengager and first regenerator cyclones, set blocks to open the trickle valves on the diplegs (if it not planned to re-enter the vessel use a material that will incinerate or melt at the temperatures expected).

•

Verify that the disengager and the regenerators manways are closed.

•

Verify isolation and blinding of the fuel gas system.

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8.2.2.2. Chronology of first Start-up

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8.2.3. Initial & Normal Start-Up 8.2.3.1. Start-up summary of the Reaction Section See Next Page

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8.2.3.2. Start-up summary of the Fractionation & Gas Recovery Sections See Next Page

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8.3. Shutdown Procedures The following presents the main steps of the shutdown procedure only. For a detailed description of the normal shutdown procedure, refer to specific procedures into the RFCC Operating Manual 8474L-015-ML-001. There are three types of shutdown. The normal shutdown scheduled for a turnaround, the shutdown due to short duration problem in part of the unit, and the emergency shutdown. The normal scheduled shutdown requires the catalyst unloading while, for a short time shutdown, one will try to keep the catalyst circulation by all means in order to restart the unit as quickly as possible.

8.3.1. Normal Shutdown 8.3.1.1. Normal Shutdown Summary of Reactor & Regenerator Normal scheduled shutdown should be made in orderly sequences because there is no issue of emergency. The main points to observe are: •

Keep catalyst circulation during the shutdown as long as possible.

•

Make sure all circuits are flushed to avoid problems during the inspection and the next start-up.

•

Keep products on specification as long as possible.

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8.3.1.2. Normal Shutdown Summary of Fractionation and Gas Recovery Section

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8.4. Emergency Shutdown 8.4.1. General emergency shutdown Emergencies, which occur in the RFCC unit, must be recognized and acted upon immediately. The operators and supervisory personnel should carefully study in advance, and become thoroughly familiar with the proper steps to be taken in such situations. The emergency conditions described here could lead to serious damage to equipment if the situation is not handled properly. It is strongly recommended that the emergency procedures and the automatic shutdown systems be understood by all persons involved in the operation. In general, the objective of the emergency procedures is to avoid damage to equipment, to the unit and to the personnel. The most common causes of emergency shutdowns are described below, together with their effects and the actions to be undertaken. In several cases, a number of actions are carried out by the emergency sequences. But operators must always check the satisfactory completion of the sequence and complement it as described. In addition they must be able to perform the safety sequence in manual mode, if needed. A few actions (through hand-switches) are left to operators judgement. The sequences must be reviewed before start-up In most of failure cases, it is recommended or required to stop the feed to the unit. This can be done by activating the emergency system UX-001. Each time the following operations must be achieved: •

Check that feed has been bypassed back to the feed surge drum

•

Check that all recycles to the riser have been stopped.

•

Check that passivator injection has been stopped.

•

Close the control valves on feed and recycle lines.

•

Check that dispersion steams, stabilization steam and riser bottom steam are effective.

•

If the duration of the failure exceeds a couple of hours, the fuel gas purges on the reaction section should be switched to nitrogen purges.

8.4.2. Power failure A failure of electrical power will result in an emergency shutdown of the unit. Steam pressure will generally be kept for a short time. However, refinery wide power failure results in steam failure, subsequent to power failure, as sea water and BFW will stop with a refinery wide power failure. Instrument indications and controls should not be affected as the UPS system will give back up for quite some time. The consequences and emergency sequences to be followed will depend on whether it is a localized power failure or refinery wide power failure.

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Note that Air Blower and Wet Gas Compressor will also stop with a power failure, since sea water to the turbine’s surface condensers will be stopped during power failure as most of the sea water pumps are driven by motor. Refer to the corresponding equipment failure described hereafter. The object is to get the unit into a safe condition while battery power or alternate power is available to the instruments. The following will occur: •

Feed oil will stop

•

Disengager will depressurize rapidly

•

SV-1502 differential pressure will fall

•

Cooling water supply will stop.

The following actions should be taken immediately: a) Activate UX-001, block in all oil feed to riser. Place SV-1501, SV-1502, and plug valve on manual and close. Shutdown passivator injection. b) Adjust fresh feed dispersion steam and all other oil injectors dispersion steam to minimum. c) Adjust pressures as required to control differential pressures. Reduce combustion air rates to 50% operating conditions if possible. d) Due to lack of sufficient cooling in the main fractionator overhead system, any steam usage in the riser should be minimized. e) Stop heating steam to E-1522 and E-1524. f) Stop stripping steam to T-1503 & T-1504 Specific note for steam demand management between RFCC and PRU. Though, PRU is not part of RFCC, but complex of RFCC group. PRU should be also brought into emergency mode operation, during upset of RFCC. Since PRU compressor C-2101 consumes substantial HPS (30-35 ton/hr), stop C-2101 for proper management of HPS demand, during emergency of RFCC. When electrical supply is re-established check operation of pumps and air coolers. Restart the unit following normal start-up procedures.

8.4.3. Instrument air failure Usually instrument air failure is of short duration and the unit can be started-up immediately after return to normal conditions. However, loss of instrument air will require an emergency shutdown of the unit. Supervision should set a standard for minimum instrument air pressure for continued operation referring the minimum IA pressure where the actuators on CVs have been designed (4.0 kg/cm2g). Although control elements will drift toward their fail-safe positions, operator intervention is required to manage the shutdown. If falling air pressure reaches the minimum pressure, the emergency shutdown sequence should be enacted. Page 291 of 323


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a) Activate UX-001 to recycle feed from the riser to feed surge drum, block in oil to the riser, and continue dispersion and stabilization steam to clear the riser. b) Place the regenerated catalyst slide valve on manual and close. c) When the stripper level begins to fall, place the spent catalyst slide valve on manual and close. d) Set the dispersion steam to about 50% flow rate and reduce the stripping steam to 50% of the operating conditions. e) Close the plug valve but be careful not to overfill first regenerator. f) Adjust the air rates to about 50% flow rate but be careful not to lose air lift flow. g) When feed is cut out of from the riser, the disengager pressure will fall rapidly. Adjust pressures as required to maintain the spent catalyst slide valve differential. h) Start torch oil and on through bypass valve and keep the temperature near 600°C in the regenerators. Due to loss of purge air or instrument supply air, instruments and level indicators may begin to give false signals. Look for correlating variables, especially temperatures to help understand the status of the process. For this reason, extreme care should be taken in making any moves on the levels when there is no instrument air pressure. Continuous operator attention is required where the process is on hand valve control. i) Determine the expected duration of the outage. If less than 24 hours the catalyst can be maintained hot with torch oil. The disengager pressure should be maintained at least 0.1 kg/cm2 higher than the regenerator pressure to keep air out of the disengager. j) When instrument air is re-established return to control on the various hand valves that are being used. Check all instrument purges to ensure they are not plugged and see that instruments are reading correctly. k) Check all nozzle points to see that they are not plugged and place them in service. l) When this has been accomplished the unit may be started using the normal start-up procedure. Note: The major problem will come from the air blower which can surge or choke during transient operations. Snort valves, UV-822/823/824 will fail open and valve controlling air to the air lift will fail in position. This is important to avoid return of catalyst from second regenerator into first regenerator.

8.4.4. Fluidization / Aeration / Purge Air and FG failure Loss of fluidization, aeration, or purge air flow will require the unit to be shutdown. Erroneous instrument readings and or catalyst circulation instability make the unit uncontrollable without operator action. a) Activate UX-001 to cut feed to the riser, to go to bypass and to block in the oil feed and adjust the dispersion steam at the rate of 50% operating conditions. Page 292 of 323


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b) Shutdown passivator injection. c) Put the regenerated catalyst slide valve on manual and close. d) When the stripper level begins to drop out the spent catalyst slide valve on manual and close. Close the plug valve but be careful not to overfill first regenerator. e) When feed is cut out from the riser, the disengager pressure will drop rapidly. f) Adjust pressures as required to maintain a positive spent catalyst slide valve differential. g) Be aware that instruments taps on the regeneration and reaction section may plug up and give false readings. Therefore exercise extreme caution in making any moves on the regenerators. By closely monitoring the regenerators temperature profile the unit may be kept hot with torch oil. All instrument taps should be checked for plugging after aeration is re-established. When assured that all taps are free, the unit may be re-started as for a normal start-up. Note: In disengager side only, fluidization, aeration and purge are supplied with fuel gas in normal operation, but nitrogen take place for start-up and FG failure.

8.4.5. Steam failure Loss of steam will require a complete shutdown of the unit due to loss of the Air blower and wet gas compressor, and loss of dispersion, stabilization and stripping steam. a) Actuate UX-001, to stop feed and bypass the riser, block in all oil feeds to the riser, and shut down the passivator injection system if it is in operation. b) Close the SV-1501 on manual control. Maintain dispersion steam as long as possible to clear the riser of catalyst. c) When the stripper catalyst level begins to drop, close the SV-1502)\ on manual control. Close the plug valve being careful not to allow the first stage regenerator to overfill. d) When oil feed is cut out of the riser, the system pressure will drop rapidly. As necessary, adjust system pressure to maintain the adequate differential on the SV-1502 e) Transfer as much as possible of the catalyst retained in the stripper to the first regenerator by carefully opening the spent catalyst slide valve. Avoid pressure differential to go below 0.1 kg/cm2. f) Since the air blower is steam driven the regenerator catalyst beds will slump. Torch oil cannot be used to maintain regenerator temperatures without proper catalyst fluidization. Ensure that the plug valve does not open as that would cause the catalyst in the second stage regenerator to flow into the first stage Page 293 of 323


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regenerator. Block in steam headers to the process before steam header pressure falls below regenerators pressures. g) The wet gas compressor is also steam turbine driven and will shut down. It will be necessary to depressure the main fractionator to prevent the potential of hydrocarbons backing into the regenerators. The depressurizing control valve PIC-458 at the outlet of D-1514 should be set to open at a pressure of around 0.15 kg/cm2 above the normal operating pressure to prevent the disengager from slumping. h) The slurry circuit should be flushed to prevent any plugging problems as the slurry system cools down. i) Determine the expected duration of the outage. If the expected start-up will be within 48 hours, the unit can remain hot on torch oil control after getting the air blower back in operation. If the outage is expected to extend beyond 48 hours the catalyst should be emptied from the unit. When steam supply is re-established, first ensure that steam headers are dry all the way up to the process and then start stripping, dispersion and stabilization steam. When this is done, the unit may be restarted using the normal start-up procedure. j) If no operator intervention is taken upon loss of steam pressure, the catalyst circulation will stop due to loss of riser lift. When feed is cut off due the temperature increases, the riser will slump. This can lead to extended shutdown and plugged equipment which is difficult and costly to clear. Exceedingly high temperatures in the regenerator can be experienced upon the loss of dispersion, stabilization, and stripping steam if feed is not cut off immediately. k) When steam is available begin circulation of the slurry system and, if necessary, use torch oil as in the normal start-up. Confirm that the steam is dry and then establish both stripping and main fractionator steam. Control pressure on the main fractionator as required to maintain differentials between the disengager regenerators. At this point the unit can be restarted following the normal start-up guidelines.

8.4.6. Boiler feed water failure Loss of boiler feed water (BFW) will require a shutdown of the RFCC unit. Actuate UX-001. Additionally, the loss of steam production may lead to a steam failure. If this happens, the procedure for steam failure should be followed. A BFW failure will require bypassing the flue gas equipments (CO Boiler and waste heat boiler), maintain water circulation through the tubes as long as possible to maintain cooling on the tubes. The wet gas compressor and all steam generation equipment should be shut down. As liquid levels require, other pumps should be shut down. When BFW is available establish levels in the steam generators and restart the unit following normal start-up procedures. Page 294 of 323


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8.4.7. Cooling water failure Loss of cooling to the fractionation and Gas Recovery section will require the shutdown of the RFCC unit. Loss of lube oil cooler of the air blower and wet gas compressor also require to trip Air Blower and wet gas compressor. Actuate UX-001, to stop feed to the riser, block in all oil injectors feeds, and adjust the fresh feed dispersion steam rate for 50% operating condition. Place the SV1501, SV-1502, and plug valve on manual and close. Since the lube oil system for the air blower and wet gas compressor require cooling water for continued operation, shut down the wet gas compressor and air blower. Due to reduced cooling capacity in the main fractionator system, any steam usage in the reaction and regeneration sections should be minimized. Since the air blower is shut down, it will be necessary to depressurize the main fractionator to minimize disengager regenerator differential pressure and prevent to potential flow of hydrocarbons from the disengager into the regenerators. Disengager pressure should be held around 0.15 kg/cm2 above the first stage regenerator pressure. When cooling water is re-established the unit may be restarted following normal start-up procedures. The effect of cooling water loss should be studied by refinery personnel to develop a detailed plan of action. 8.4.8. Sea water failure Sea water is used for coolant of the surface condenser of the air blower and wet gas compressor. Therefore, failure of sea water will automatically trip of air blower and wet gas compressor, as turbine is not work properly. Follow operation procedure of Air Blower failure and Wet Gas Compressor failure. 8.4.9. Air blower failure In case of air blower failure, the unit will be shut down by UX-005, which will actuate UX-002 and UX-001 systems. The pressure in the regenerators will fall rapidly resulting in possible flow reversal at SV-1501 if the operator does not act immediately. Reduce the main fractionator pressure to flare to minimize the disengager / regenerator differential pressure. Bypass the fresh oil feed to the feed surge drum, block in all oil feeds to the riser, while reducing all other injector steam and stripping steam to about 50% of operating conditions. Shut down passivator injection if it is in operation. Place the SV-1501 and SV-1502 on manual and close. Place the plug valve on manual and close. Disengager pressure should be held at about 0.15 kg/cm2 above regenerator pressure. Catalyst may have backed into air lines so extreme care should be taken when reestablishing air flow. Normally the following actions are required to re-established air flow to the unit when restarting the blower: a) Close the control valves on the line to the first stage regenerator air rings. Page 295 of 323


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b) Open the plant air into the catalyst lift line between the first regenerator and second regenerator. The uppermost blast point should be started first, and then open the lower blast points stepwise down the lift line. c) Before starting the blower it must be checked that all air lines are free of catalyst upstream the assisted check valves. Ensure that the check valves are in closed position. d) Plant air connections have been provided upstream the regenerators air rings. These connections must be put in operation to clear the air rings from the accumulated catalyst. e) The amount of catalyst back flow into the air heaters must be checked by visual inspection. In case of significant catalyst amount in the heaters, the blast connections provided on the air lines must be put in operation to clear the lines. The connections must be put in operation one by one, starting with the connection located close to the regenerator. f) With all blast points open, slowly begin lift air from the air blower and then reduce plant air to minimum purge rates. g) After clearing of the air lines, the air blower can be restarted h) Open the control valves on the line to the R-1 rings. This should be done slowly so as not to lose lift air flow. i) When all air flows are re-established, the unit may be started as in the normal start-up procedure. Notes: The unit can be restarted if the catalyst temperatures are not too low (above 400°C). Loss of the blower by serious mechanical failure due to long duration problem will necessitate the normal shutdown of the RFCC unit with catalyst unloading. The loss of the blower causes the fluidized bed to slump. As a result, not all catalyst is regenerated and fully cooled. The critical items regarding the catalyst unloading without blower are: •

To be able to maintain enough pressure in the regenerators to transfer the catalyst to the hopper (a delta pressure about 0.7 kg/cm2 – by plant air injections – should be sufficient).

•

To cool down the catalyst in the regenerators to a temperature below 300°C. This is essential to avoid any coke combustion either in the catalyst transfer lines or in the spent catalyst hopper.

During catalyst unloading, a careful survey of the temperatures in the regenerators disengager stripper, and at the top of the spent catalyst hopper should be performed. Before catalyst unloading following plant safety rules, install blinds to allow the final vacuum truck removal of the remaining catalyst as necessary.

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8.4.10. Feed pump failure Loss of feed will activate emergency shutdown system, activate UX-001 to stop feed and recycles to the riser and bypass the riser. If the spare feed pump can be quickly started, the unit may be brought back on line in a short period of time. If unable to start a fresh feed pump, maintain the unit in a hot condition. a) Adjust the dispersion steam at the maximum rate of operating conditions. b) Take the regenerated catalyst slide valve on manual control to monitor the catalyst circulation. Place the feed control on manual and close. c) When the feed is taken out of the unit the disengager pressure will fall. Adjust the pressure balance to maintain a positive pressure differential between the disengager and the regenerators (higher than 0.15kg/cm2). d) Start torch oil injection immediately in the regenerators to keep the catalyst about 600°C. e) When feed is available, re-establish the operating conditions as required before the normal oil-in (riser outlet temperature around 530°C, pressure balance,...) and restart the unit following normal start-up procedures.

8.4.11. Other pump failure Loss of any other pump will not require a shut down of the RFCC unless the spare pump cannot be started. In cases where the spare pump is unavailable, it may be possible to continue operation by adjusting unit operations. Each system should be studied to determine how to continue operation is case of pump failure.

8.4.12. Fuel gas failure Typically, fuel gas failure will not require a shutdown of the RFCC. Fuel gas is used in the CO Boiler. Switch main fuel source from fuel gas to fuel oil so that COB operation can be continue as far as possible. Loss of the CO Incinerator may require a shutdown of the RFCC since the carbon monoxide rich flue gas from first regenerator is released to the atmosphere. Violations of the environmental permits may force reduction of the RFCC feed. Provision is made that fuel oil can be also used for COB combustion burner. Use fuel oil firing, maximum extent at failure of fuel gas, and maintain COB operation as far as possible. If feed is cut off from the unit, the reaction / regeneration sections can be maintained in a hot condition using torch oil for 24 hours. If the outage is expected to extend beyond 24 hours, the catalyst should be emptied as for a normal shutdown. As the CO Incinerator is off-line, the heat load to the Waste Heat Boiler will be reduced and therefore steam production will diminish. A shut-down of the COB will have a serious impact on the overall steam balance of the refinery, including Air Page 297 of 323


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Blower and WGC in RFCC. Steam from the utility boilers will be used for back-up of steam demand. Reduce RFCC throughput, and reduce Air Blower and WGC load to reduce steam demand, if insufficient steam can be supplied from utility boilers. If steam availability is critical, then cut-off heating steam of HPS and MPS to E-1522 and E-1524. When fuel gas is available, re-establish the unit following the normal start-up procedures.

8.4.13. Wet gas compressor failure Loss of the WGC will require a reduction in fresh feed rate or possibly a shut down of the RFCC. Follow any emergency procedures from the WGC vendor to safeguard the WGC. If this shutdown is for a short period of time, reduce feed flow rate to about 60% of the operating condition and flare the gas at the overhead receiver. If it not possible to flare the gas or if pressure is uncontrollable: a) Activate UX-001 to stop feed and recycles to the riser. b) Place slide valves and plug valve on manual control. c) Control the disengager pressure higher than the regenerators pressures. Inject fuel gas in the overhead receiver as necessary. The catalyst circulation can be maintained as long as the pressure differential through the spent catalyst slide valve is kept above 0.15 kg/cm2 and as long as the steam flow in riser is sufficient to lift the catalyst (minimum velocity: 5 m/s). d) If catalyst circulation is maintained, check the flue gas treatment equipments (steam drum levels), check the main fractionator level and check the temperatures in the regenerators; use torch oil to maintain the catalyst about 600°C. 1. If catalyst circulation is difficult to maintain at adequate conditions (eg unsteady pressure balance, high or low temperatures in regenerators), actuate UX-002 to shut-down the unit. 2. In addition, instrument purge systems on the disengager side use treated gas from the Gas Recovery as the primary media. Automatic back-up by nitrogen will be made when supply of treated off gas is stopped as consequence of the failure of the wet gas compressor. Operations should carefully monitor the back-up nitrogen system is working (eg PV-367B is opened). When the WGC is ready for restarting follow vendor’s procedures and restart the unit following normal start-up procedure. Notes: Loss of the WGC by serious mechanical failure due to long duration problem will require the normal shutdown of the RFCC unit with catalyst unloading.

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Loss of the WGC will reduce production of RFCC off gas to the refinery fuel gas system. Since RFCC off gas is the prime source of fuel gas, proper management of fuel gas and fuel oil is required to avoid loss of fuel gas in the refinery. Maximize fuel oil firing in the major users of fuel gas (Utility Boilers, CDU and COB) and vaporize LPG, if required.

8.4.14. Catalyst slide valve / plug valve failure For a failure of catalyst slide / plug valves, the unit may remain in operation depending upon the type of failure and which valve fails. It may be possible to continue operation with manual local control of the valve position. If this is attempted, it is very important to have continuous monitoring of the control variable and good communications between the control room and the operator at the valve. If the plug valve fails, the unit may continue to operate by controlling the first regenerator catalyst level with the first/ second regenerator differential pressure. Is stable control cannot be obtained quickly, the unit should be shutdown. a) If stable control cannot be achieved activate UX-001 to stop feed and recycles to the riser, block in all oil feeds, and shutdown passivator injection if it is in operation. b) Close the SV-1501 on manual or with the handwheel. If the SV-1502 cannot be closed, reduce the dispersion, stabilization steam and riser bottom ring injection to about 20-30% let the riser slump. c) Adjust pressures to hold a positive SCSV differential. The RCSV differential may go to zero if the riser is slumped. d) Hold the disengager pressure 0.15 kg/cm2 above the regenerator pressure. Notes: If catalyst slide valve is blocked in closed position, check that UX-001 and UX-002 have been activated. If either catalyst slide valve is blocked in open position activate UX-001 and try to take the other catalyst valves on manual control and adjust the valves opening to obtain a stable and constant catalyst circulation through the unit. The circulation rate will be dictated by the opening of the failed valve. Loss of catalyst slide valve by serious mechanical failure due to long duration problem will necessitate the normal shutdown of the RFCC unit with catalyst unloading.

8.4.15. Loss of regenerators pressure control (flue gas slide valve failure) For a failure of flue gas slide valves, the unit may remain in operation depending upon the type of failure and which valve fails. It may be possible to continue operation with manual local control of the valve position. If this is attempted, it is

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very important to have continuous monitoring of the control variable and good communications between the control room and the operator at the valve. If stable control cannot be achieved, activate UX-001 to stop feed and recycles to the riser, block in all oil feeds, and shutdown passivator injection if it is in operation. Hold the disengager pressure 0.15 kg/cm2 above the regenerator pressure. Note: Loss of flue gas slide valve by serious mechanical failure due to long duration problem, will necessitate the normal shut down of the RFCC unit with catalyst unloading.

8.4.16. Control system failure For a failure of control system, the unit may remain in operation for a short time typically 10 to 15 min. Otherwise the unit is shut down by activating UX-001 and UX-002. 8.4.17. Oil reversal This situation can occur when oil injected in the riser flows back into the second regenerator instead of being lifted up in the riser. This is the consequence of a sudden increase of disengager pressure or sudden decrease of second regenerator pressure. It is detected by a sudden rise of the second regenerator temperatures which can exceed the limit of the design and can be very dangerous. a) Immediately actuate UX-002 and UX-001 and check that catalyst slide valves are all closed. Check that oil is effectively bypassed from riser, block all oil feeds. b) Decrease air rates if the temperatures continue to rise. c) Establish a pressure higher in the disengager than in the regenerators. Inject fuel gas in the fractionator overhead receiver. d) Restart the unit as soon as the reason for the oil reversal is explained and corrected. Note: Catalyst is withdrawn into an external withdrawal stand pipe. This proven system ensures an efficient seal against oil reversal.

8.4.18. Low riser outlet temperature (ROT) In case of too low Riser Outlet temperature (< 480°C), the feed is not cracked and the catalyst will be socked with hydrocarbons. These hydrocarbons will be carried into the first regenerator where they will burn, causing unacceptable temperature run away. Loss of ROT will require a reduction in fresh feed rate or possibly a shut down of the RFCC by activating UX-001. The catalyst circulation can continue on automatic control, however, the operator may have to temporarily intervene to Page 300 of 323


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manually reduce the catalyst circulation rates. Feed-in can be achieved when an acceptable Riser Outlet Temperature for start-up (510-530°C) is obtained. 8.4.19. Plugged catalyst circulation It can happen that the catalyst is plugged in the lift or standpipes, especially during the start-up periods. In that case feed and recycles must be stopped to the riser (actuate UX-001) before attempting to unplugging the catalyst. a) In case of plugging in the air lift, blast connections are provided along the air lift to help to re-fluidize the catalyst. Put the blast connections in operation one by one, starting with the upper connection. Lift air flow rate and pressure can be increased to help to de-plug the air lift. b) In case of catalyst plugging in a standpipe, the circulation can be restored by increasing the differential pressure through the line: decrease the first regenerator pressure in case of spent catalyst line plugging and increase the second regenerator pressure in case of regenerated catalyst line plugging (if increasing the aeration and fluidization rates is not sufficient). During the deplugging operation, do not maintain the catalyst slide valve continuously fully open; proceed with quick close/open valve operations.

8.4.20. Downstream unit failure Depending upon the nature of the downstream equipment failure, the RFCC may operate at reduced throughput. If unable to operate in a stable, controlled manner the unit should be shutdown following the normal shutdown procedure. Follow as close as possible the normal shutdown procedure. If the outage is expected to be less than about 48 hours, the unit can be kept hot with torch oil. If the outage is expected to extend beyond 48 hours, plan for unloading catalyst as per the normal shutdown procedure. In the case of continued stand-by operation, reduce the disengager pressure to 0.15 kg/cm2 above the first stage regenerator pressure and reduce stripper catalyst level to minimum. Once the downstream failure is repaired, the unit may be restarted following the normal start-up procedure. 8.4.21. Fire emergency In case of a fire emergency, it should be determined what effect the emergency will have on the RFCC. If shut down of the unit is required, the normal shutdown procedure should be followed as closely as possible (activate UX-001). If the emergency requires immediate action, it may not be possible to completely utilize the normal shutdown procedure. In those cases, oil hydrocarbon feeds should be isolated from the reactor section and the unit should be maintained in a hot condition using torch oil. As required the catalyst circulation may be shut down (activate UX-002) until the emergency situation is under control.

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8.4.22. Emergency shutdown of Fractionator and Gas Recovery Section - General In an emergency, steps must be taken to bring the unit to a safe shutdown condition. An emergency may be caused due to failure of a utility or failure of equipment. Emergency shutdown of the reaction section will also necessitate shutdown of the fractionation and gas recovery sections. Initially, the unit should be shutdown and maintained in a hot condition by switching the slurry steam generators to heating. Admit fuel gas to the main fractionator overheads to maintain the pressure balance in the reactor. It may be necessary to shut down the wet gas compressor because of steam balance requirements or because of compressor surging. If the emergency is anticipated to be for long duration, shutdown should proceed as for a normal shutdown, as far as equipment is available to do so.

8.4.23. Steam failure for the Fractionation/Gas Recovery Section On loss of steam, the air blower in the reaction section and the wet gas compressor will be lost. This will require a shutdown of the unit. The slurry pumparound pumps are all steam turbine driven and these also will be lost. Depressurize the main fractionator to prevent the possibility of flow of hydrocarbon back to the regenerators. Flush the slurry circuit to prevent plugging problems as the slurry circuits cool down. Shut off stripping steam to the HCO and LCO strippers. When steam becomes available, start the slurry pumps and start slurry circulation. Confirm the liquid level of T-1501 with LI-411A and B prior start slurry pumparound pumps. If necessary, heat the slurry circuits as for normal start-up. Admit fuel gas to the main fractionator overhead and start the wet gas compressor. Continue start-up of the unit following the procedure for normal start-up.

8.4.24. Instrument air failure for the Fractionation/Gas Recovery Section Instrument air failure will require shutdown of the unit. The control valves will go to the failure position. The operators should be familiar with these positions. If the wet gas compressor has not shut down on instrument failure, it should be shut down following the normal shutdown procedure. Maintain slurry circulation. It will be necessary to manually control boiler feed water to the slurry pumparound steam generators, using the control valve by-passes. Other pumps should be shut down as liquid levels decrease. Stop stripping steam to the strippers. As steam flow may continue to the reactor, the main fractionator reflux drum water level will require manual control. If necessary, heat the slurry circuit in the steam generators to maintain the main fractionator hot. When instrument air is available, check all control valves for proper operation. Any control valves being by-passed should be placed back in Page 302 of 323


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service and by-pass valves closed. Restart the unit following the normal start-up procedure.

8.4.25. Boiler feed water failure for the Fractionation/Gas Recovery Section Loss of boiler feed water will require shutdown of the unit. Loss of boiler feed water can lead to loss of steam, depending on the duration. In this case, follow the procedure for steam failure. When boiler feed water is available, establish levels in the steam generators and restart the unit following the normal start-up procedure.

8.4.26. Fuel gas failure for the Fractionation/Gas Recovery Section Fuel gas failure will not normally require a shutdown of the fractionator section. Fuel gas is used for pressure control on the feed surge drum. Loss of pressure control should not result in any operating difficulty as any loss of pressure will be gradual. Fuel gas is also used as pressure control on the surge drums associated with the slurry separator. Loss of this control should not result in any operating difficulty. 8.4.27. Electrical power failure for the Fractionation/Gas Recovery Section Electrical power failure will require a shutdown of the unit. There is a possibility that steam failure will also occur, soon after refinery wide power failure as no sea water and cooling water. Wet gas compressor will be shut-down, automatically, as sea water is not available in the event of refinery wide power failure. Try to maintain operation of the following pumps at power failure, and subsequent steam failure: •

Main fractionator bottom pump P-1519ABC

•

HCO flushing pump P-1521A for supplying flushing oil to P-1519ABC. In case HCO is not available from the main fractionator, try to introduce LCO from the tankage, if available.

In case shut-down duration is to be longer, maintain the main fractionator hot by switching the slurry steam generators to heating. For prolong steam available to the essential part of RFCC, i.e. steam to riser and reactor stripping, cut off the steam to the following users, manually: •

MP steam to E-1522

•

HP steam to E-1524

•

HPS to COB FD fan CT-1502B, subject to availability of HPBFW and fuel oil and or fuel gas.

•

LP steam to T-1503

•

LP steam to T-1504

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As the fractionator overhead air condenser and overhead sour water pumps will be lost, the use of steam to the reactor should be minimized. When power is available restart the unit following the normal start-up procedure.

8.4.28. Cooling water failure for the Fractionation/Gas Recovery Section Cooling water failure will require a shutdown of the unit. Cooling water is used for main fractionator trim condenser, and trim condensers of the wet gas compressor. Cooling water is also used for pump auxiliary coolers, and lube oil cooler of the Wet Gas Compressor. Shut down the wet gas compressor and maintain the main fractionator hot by switching the slurry steam generators to heating. 8.4.29. Sea water failure for the Fractionation/Gas Recovery Section Sea water is used for coolant of the surface condenser of the wet gas compressor. Therefore, failure of sea water will automatically trip of WGC, as turbine is not work properly. Follow operation procedure of wet gas compressor failure.

8.4.30. Wet gas compressor failure for the Fractionation/Gas Recovery Section On loss of the wet gas compressor, divert the fractionator overhead gas to flare and start to reduce feed to the unit. If the wet gas compressor cannot be re-started quickly, this will require shutdown of the unit. Follow any emergency procedures from the vendor to safeguard the compressor. Maintain the main fractionator hot by switching the slurry steam generators to heating. When the wet gas compressor is ready to start, follow the normal start-up procedure to re-start the unit.

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TRAINING MODULE


Course Content: Section 1 - General Description Section 2 - Process Flow Description Section 3 - Process Control Section 4 - Safeguarding Devices Section 5 - Fire & Gas Systems Section 6 - Quality Control Section 7 - Cause & Effects Section 8 - Operating Procedures Section 9 - HSE

X

Section 10 - Reference Document Index

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SECTION 9 : HSE 9.1. Hazardous Areas Refer to the following attached documents: •

8474L-015-DW-0051-001 Plot Plan – RFCC/LTU/NTU units

•

8474L-015-DW-1920-001 Hazardous Area Classification diagram – RFCC/LTU/NTU units

9.2. Safety Equipment Refer to the following attached document: •

8474L-015-DW-1933-011 Safety Equipment Layout RFCC/LTU/NTU units

9.3. Specific PPE For the description of the PPE required for the chemicals used in the RFCC, refer to the specific MSDS which must be supplied by the material vendor. All personnel involved in chemical handling related work in the RFCC unit must wear the specific PPE required. The substances used in the RFCC include: •

Catalyst and additives,

•

Flue gases,

•

Cracked Hydrocarbons,

•

Hydrogen Sulfide

The following advice is valid for any chemical handling: •

Use good work and personal hygiene practices to avoid exposure.

•

Keep an eye wash fountain available.

•

Keep a safety shower available.

•

If clothing is contaminated, remove clothing and thoroughly wash the affected area.

•

Do not eat or drink while handling chemicals

9.3.1. Catalyst RFCC catalyst is able to cause eyes and lungs irritations. When working with catalyst (taking samples, catalyst containers loading and unloading…) face shields or goggles and a dust mask must be worn. Hot catalyst will burn skin. During catalyst sampling the whole body must be protected by adequate clothing. One should be careful with pile of hot catalyst spillage which can be cold externally but very hot inside.

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9.3.2. Flue gas In the RFCC process there are two different flue gases. The flue gas coming from the first regenerator contains CO and is a very dangerous gas. 9.3.2.1. Carbon Monoxide The following details the Personal Protection Equipment required when entering a zone susceptible to contain CO: Eye/Face Protection:

Safety Goggles or Glasses

Skin Protection:

Any material protective gloves

Respiratory Protection: Positive pressure air line with full-face mask and escape bottle or self-contained breathing apparatus should be available for emergency use. Always wear a self contained air mask when entering in an area or vessel suspected to contain CO. Safety Shoes

Other:

9.3.3. H2S The best method for prevention of H2S poisoning is to stay out of areas known or suspected to contain it. The sense of smell is not an infallible guide as to the presence of H2S, for although the compound has a distinct and unpleasant odor (rotten eggs), it will frequently paralyze the olfactory nerves to the extent that the victim does not realize that he is breathing it. This is particularly true of higher concentrations of the gas. Fresh air masks or gas masks suitable for use with hydrogen sulfide must be used in all work where exposure is likely to occur. Such masks must be checked frequently to make sure that they are not exhausted. People who must work on or in equipment containing appreciable concentrations of H2S, must wear fresh air masks and should work in pairs so that one may effect a rescue or call for help should the other be overcome. As mentioned above, the atmosphere in which people work should be checked from time to time for appreciable concentrations of H2S. REMEMBER - JUST BECAUSE YOUR NOSE SAYS IT'S NOT THERE, DOESN'T MEAN THAT IT IS NOT. PPE recommendation for protection against H2S: Ventilation Respiratory Protection

Use adequate ventilation to control exposure below recommended levels For concentrations exceeding the recommended exposure level, use NIOSH/MSHA approved air purifying respirator. If conditions immediately dangerous to life or health (IDLH) exist, use NIOSH/MSHA approved self-contained breathing apparatus (SCBA) Page 307 of 323


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equipment. Eye Protection

For splash protection use chemical goggles and face shield

Skin Protection

Gloves and coveralls of rubber or neoprene construction if liquid contact could occur. Avoid unnecessary skin contamination with material

9.3.4. Nickel passivator – NALCO NICKEL PASSIVATION PLUS EC9192 The following table details the PPE required when handling this chemical: The use and choice of personal protection equipment is related to the hazard of the product, the workplace and the way the product is handled. In general, we recommend as a minimum precaution that safety glasses with side-shields and workclothes protecting arms, legs and body be used.

General Advice

In addition any person visiting an area where this product is handled should at least wear safety glasses with side-shields. Where concentrations in air may exceed the limits given in this section, the use of a half face filter mask or air supplied breathing apparatus is recommended. A suitable filter material depends on the amount and type of chemicals being handled.

Respiratory Protection

Consider the use of filter type: A-B-E-K-P In event of emergency or planned entry into unknown concentrations a positive pressure, full-facepiece SCBA should be used. If respiratory protection is required, institute a complete respiratory protection program including selection, fit testing, training, maintenance and inspection. When handling this product, the use of chemical gauntlets is recommended. PVC gloves are recommended.

Hand Protection

Gloves should be replaced immediately if signs of degradation are observed.

Skin Protection

When handling this product, the use of overalls is recommended. A full slicker suit is recommended if gross exposure is possible.

Eye Protection

Wear chemical splash goggles

9.3.5. Corrosion Inhibitor - CHIMEC 1430 The following table details the PPE required when handling this chemical: Respiratory protection

A localized aspiration is necessary if the warmed product forms vapours

Skin protection

protective gloves in neoprene or latex, approved for protection against chemical substances Page 308 of 323


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Eye protection

goggles or face shield with safety glasses

Others

appropriated protective clothing

DATE: 06/12/07

9.3.6. Antifoam CHIMEC 8045 The following table details the PPE required when handling this chemical: A localized aspiration is necessary if the warmed product forms vapours. Ensure good ventilation.

Respiratory protection

In closed areas or in case of insufficient ventilation, use protective mask with filter for organic vapours.

Skin Protection

Protective gloves made of nitrile or PVA, approved for protection against chemical substances

Eye Protection

Goggles or face shield with safety glasses

9.3.7. Phosphate NALCO 7208 The following table details the PPE required when handling this chemical: Where concentrations in air may exceed the limits given in this section, the use of a half face filter mask or air supplied breathing apparatus is recommended. Respiratory protection

A suitable filter material depends on the amount and type of chemicals being handled. Consider the use of filter type: Particulate filter - HEPA (Purple) If respiratory protection is required, institute a complete respiratory protection program including selection, fit testing, training, maintenance and inspection.

Hand Protection

Neoprene gloves, Nitrile gloves, Butyl gloves, PVC gloves

Skin Protection Neoprene gloves, Nitrile gloves, Butyl gloves, PVC gloves Eye Protection

Wear chemical splash goggles

9.4. Chemical Hazards The material safety datasheet for chemicals used in the RFCC will be provided by vendor and serves as reference. These datasheets clearly explains what are the health hazards specific to each chemical. It is of the utmost importance that all employees involved in this unit read and understand the MSDS of the chemical they will handle before proceeding to work. No work or

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operation should be allowed to commence before all employees involved in chemical handling related work have demonstrated knowledge of the health hazards they my face. The substances used in the RFCC include: •

Catalyst and additives,

•

Flue gases,

•

Cracked Hydrocarbons,

•

Hydrogen Sulfide

9.4.1. Hazardous Properties of Catalyst RFCC catalyst is able to cause eyes and lungs irritations. Hot catalyst will burn skin. One should be careful with pile of hot catalyst spillage which can be cold externally but very hot inside. 9.4.2. Flue gas In the RFCC process there are two different flue gases. The flue gas coming from the first regenerator contains CO and is a very dangerous gas. Exposure to a concentration as low as 0.4 % vol. can be fatal in a short period of time. The flue gas contains no or very little oxygen and is a dense gas which can accumulate in low parts of equipments. Therefore it can cause asphyxiation or poisoning if not sufficiently purged off. First aid consists of taking the victim out of the dangerous area and then to use artificial respiration. 9.4.2.1. Hazardous properties of carbon monoxide (CO) Carbon monoxide has the ability to replace oxygen in the blood; too high concentration in the body may cause death in a short period of time. CO also acts to keep the oxygen in the blood from reaching the tissues causing a type of suffocation. Maximum allowable concentration in the air is 100 ppm. CO burns readily and is dangerous when exposed to heat or flames. Its explosive limits range from 12.5% to 74% volume. Auto ignition temperature: 650°C. Mixtures of CO and air in certain proportions are flammable. The following table summarizes the health hazards of CO: Eye Effects:

None reported

Skin Effects:

None Reported

Ingestion Effects:

None Reported

Inhalation Effects:

Inhaled carbon monoxide binds with blood hemoglobin to form Page 310 of 323


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carboxyhemoglobin. Carboxyhemoglobin can not take part in normal oxygen transport, greatly reducing the blood’s ability to transport oxygen. Too high concentration in the body may cause death in a short period of time. Depending on levels and duration of exposure, symptoms may include headache, dizziness, heart palpitations, weakness, confusion, nausea, and even convulsions, eventual unconsciousness and death.

9.4.3. Hazardous Properties of Cracked hydrocarbons Cracked hydrocarbons are skin irritants. Precautions should be taken during maintenance operations or products sampling to avoid contact with skin and eyes. It also contains aromatics which are poisons. In case of exposure, skin should be washed with soap and eyes thoroughly cleaned with water. Contaminated clothes should be removed.

9.4.4. Hazardous Properties of Hydrogen Sulfide Toxicity Classification:

Hydrogen sulfide is both an irritant and an extremely poisonous gas. it is extremely toxic (almost as toxic as hydrogen cyanide) and highly corrosive to certain metals. Breathing even low concentrations of hydrogen sulfide (H2S) gas can cause poisoning. Hydrogen sulphide at concentrations greater than 500 ppm is highly toxic and can cause immediate death. The unit must be completely gas tight and leaks repaired immediately when occur. It can be lethal to under-estimate an H2S leak. It is highly soluble in both water and oil. H2S is colorless, and heavier than air. It will therefore accumulate in low places, in dangerous concentrations. It is however, readily dispersed 'by the wind' movement, so areas where there is a risk of H2S emission should be well ventilated. H2S is explosive in air in the range of 4.3% to 45% by volume, and has an automatic ignition temperature of 292OC. It burns with a blue flame producing Sulphur Dioxide (SO2), which is also a toxic gas. Human tolerance of exposure varies greatly between individuals at lower concentrations. As concentrations increase, tolerance variations decrease rapidly.

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A feature of H2S poisoning is that the H2S immobilizes or paralyses that part of the central nervous system, which controls the body's automatic breathing system. H2S acts by deadening nerve endings including those associated with smell. H2S can usually be detected by its 'bad egg' smell, but the sense of smell is quickly lost in concentrations over 1000 ppm, even at 50 ppm the sense of smell is unreliable. WARNING: YOU CANNOT RELY ON YOUR NOSE TO TELL YOU HOW MUCH H2S IS PRESENT. At concentration greater than 20 ppm it is no longer possible to smell the gas, thus greatly increasing its hazard. No work should be undertaken on the unit where there is danger of breathing H2S, and one should never enter or remain in an area containing it without wearing a suitable fresh air mask. 9.4.4.1. Acute Hydrogen Sulfide Poisoning Breathing air or gas containing more than 500 mol-ppm H2S can cause acute poisoning and possibly be fatal. Symptoms of Acute Poisoning The symptoms of acute H2S poisoning are muscular spasms, irregular breathing, lowered pulse, odor to the breath and nausea. Loss of consciousness and suspension of respiration quickly follow. Even after the victim recovers, there is still the risk of edema (excess accumulation of fluid) of the lungs which may cause severe illness or death in 8 to 48 hours. First Aid Treatment of Acute Poisoning Move the victim at once to fresh air. If breathing has not stopped, keep the victim in fresh air and keep him quiet. If possible, put him to bed. Secure a physician and keep the patient quiet and under close observation for about 48 hours for possible edema of the lungs. In cases where the victim has become unconscious and breathing has stopped, artificial respiration must be started at once. If a Pulmotor or other mechanical equipment is available, it may be used by a trained person; if not, artificial respiration by mouth-to-mouth resuscitation must be started as soon as possible. Speed in beginning the artificial respiration is essential. Do not give up. Men have been revived after more than four hours of artificial respiration. If other persons are present send one of them for a physician. Others should rub the patient's arms and legs and apply hot water bottles, blankets or other sources of warmth to keep him warm. After the patient is revived, he should be kept quiet and warm, and remain under observation for 48 hours for the appearance of edema of the lungs.

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9.4.4.2. Subacute Hydrogen sulfide Poisoning Breathing air or gas containing H2S anywhere between 10 to 500 molppm for an hour or more may cause subacute or chronic hydrogen sulfide poisoning. Symptoms of Subacute Poisoning The symptoms of subacute H2S poisoning are headache, inflammation of the eyes and throat, dizziness, indigestion, excessive saliva, and weakness. These can be the result of continued exposure to H2S in low concentrations. Edema of the lungs may also occur. First Aid Treatment of Subacute Poisoning Keep the patient in the dark to reduce eyestrain and have a physician treat the inflamed eyes and throat. Watch for possible edema. Where subacute poisoning has been suspected, the atmosphere should be checked repeatedly for the presence of H2S by such methods as testing by odor, with moist lead acetate paper, and by Tutweiler H2S determination to make sure that the condition does not continue.

9.4.5. Hazardous Properties of NALCO NICKEL PASSIVATION PLUS EC9192 Hazard Classification:

The following table summarizes the health hazards of this chemical: Inhalation

Repeated or prolonged exposure may irritate the respiratory tract. Product mist or vapors may cause headache, nausea, vomiting, drowsiness, stupor or unconsciousness. Methyl alcohol may cause central nervous system effects which may result in permanent visual changes including blindness.

Skin Contact

Can cause moderate irritation. Harmful if absorbed through skin. Methanol may be absorbed through the skin and cause central nervous system effects which may result in permanent visual changes including blindness.

Eye Contact

Can cause moderate irritation

Ingestion

Not a likely route of exposure. There may be irritation to the gastrointestinal tract. Harmful if swallowed. Can cause blindness. Page 313 of 323


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Note: Keep out of waterways: Toxic to aquatic organisms.

9.4.6. Hazardous Properties of Corrosion Inhibitor - CHIMEC 1430 Hazard Classification:


Vapours or fog inhalation at high temperature may produce irritation of respiratory tract.

Skin Contact

Corrosive, may produce dermatitis and burns

Eye Contact

Corrosive

Ingestion

burning effects in mouth, throat and stomach with abdominal cramps

9.4.7. Hazardous Properties of Antifoam CHIMEC 8045 Hazard Classification:

The following table summarizes the health hazards of this chemical: Page 314 of 323


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Slight exposure: irritation of eyes and primary respiratory tract, with temporary reduction of smelling capacity.

Inhalation

Exposure to high vapour concentration: depressant effect on the central nervous system with headaches, drowsiness, derangement, serious damage to visual faculties, nausea, vomiting, drunkenness. May cause anesthetic and/or narcotic effects. Skin Contact

Prolonged and repeated contact may produce dermatitis and irritation

Eye Contact

Vapours may cause irritation

Ingestion

Ingestion causes severe irritation of the mouth, throat and stomach, with nausea, vomiting, dizziness, faintness, drowsiness and lack of coordination. Ingestion creates a high risk of aspiration and subsequent chemical pneumonia.

9.4.8. Hazardous Properties of Phosphate NALCO 7208 Hazard Classification:


Not a likely route of exposure. No adverse effects expected

Skin Contact

Can cause moderate to severe irritation

Eye Contact


Ingestion


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TRAINING MODULE


Course Content: Section 1 - General Description Section 2 - Process Flow Description Section 3 - Process Control Section 4 - Safeguarding Devices Section 5 - Fire & Gas Systems Section 6 - Quality Control Section 7 - Cause & Effects Section 8 - Operating Procedures Section 9 - HSE Section 10 - Reference Document Index

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SECTION 10 : REFERENCE DOCUMENTS INDEX 10.1. Operating Manual/ Licensor Documentation 8474L-015-ML-001

RFCC Operating Manual

10.2. Arrangement Drawings, Layouts and Plot Plans 8474L-015-DW-0051-001

Plot Plan – RFCC / LTU / NTU

8474L-015-DW-1960-001

Escape Route Layout for RFCC / LTU / NTU

10.3. Process Flow Diagrams 8474L-015-PFD-0010-101


8474L-015-PFD-0010-102


8474L-015-PFD-0010-103


8474L-015-PFD-0010-104


8474L-015-PFD-0010-105


8474L-015-PFD-0010-106


8474L-015-PFD-0010-107


8474L-015-PFD-0010-111


8474L-015-PFD-0010-112


8474L-015-PFD-0010-113


8474L-015-PFD-0010-114


8474L-015-PFD-0010-115


8474L-015-PFD-0010-116


8474L-015-PFD-0010-117


10.4. Piping and Instrumentation Diagrams Interconnections: 8474L-015-PID-0021-101

Interconnecting Process Lines to RFCC

8474L-015-PID-0021-102

Interconnecting Process Lines from RFCC

8474L-015-PID-0021-103

Interconnecting Process Lines to/from LTU

8474L-015-PID-0021-104

Interconnecting Process Lines to/from NTU

8474L-015-PID-0021-105

Interconnecting Process Lines to/from PRU

8474L-015-PID-0021-106

Interconnecting Utilities

8474L-015-PID-0021-107

Interconnecting Utilities

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Specific Details: 8474L-015-PID-0021-111

Specific Details (1/4)

8474L-015-PID-0021-112


8474L-015-PID-0021-113


8474L-015-PID-0021-114


Reactor/Regenerator Section: 8474L-015-PID-0021-121

Riser: Feed injectors

8474L-015-PID-0021-122

Riser: MTC & Backflush oil injectors

8474L-015-PID-0021-123

Disengager/Stripper: Stripping

8474L-015-PID-0021-124

Disengager/Stripper: Purging

8474L-015-PID-0021-125

Spent Catalyst Line

8474L-015-PID-0021-126

1st Regenerator Dense Phase-Upper

8474L-015-PID-0021-127

1st Regenerator Dense Phase-Lower

8474L-015-PID-0021-128

1st Regenerator Dilute Phase

8474L-015-PID-0021-129

2nd Regenerator Upper

8474L-015-PID-0021-130

2nd Regenerator Lower

8474L-015-PID-0021-131

Withdrawal Well

8474L-015-PID-0021-132

Air Blower

8474L-015-PID-0021-133

1st Regenerator Air Heater

8474L-015-PID-0021-134

2nd Regenerator Air Heater

8474L-015-PID-0021-135

Spent Catalyst Hopper

8474L-015-PID-0021-136

Auxiliary Catalyst Hopper

8474L-015-PID-0021-137

Fresh Catalyst Hopper

8474L-015-PID-0021-138

Steam Injection & Fuel Gas Inst. Purging

Flue Gas Treatment Section: 8474L-015-PID-0021-201

1st Regenerator Flue Gas

8474L-015-PID-0021-202

2nd Regenerator Flue Gas

8474L-015-PID-0021-203

CO Boiler Package

8474L-015-PID-0021-204


8474L-015-PID-0021-205

Economizer

8474L-015-PID-0021-206

Flue Gas KO Drum

Fractionation Section: 8474L-015-PID-0021-301

Feed Surge Drum and Pumps Page 318 of 323


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8474L-015-PID-0021-302

LCO PA/MPS/HPS Feed Heaters

8474L-015-PID-0021-303

1st Slurry preheat exchangers

8474L-015-PID-0021-304

2nd Slurry preheat exchangers

8474L-015-PID-0021-305

MTC Recycle and Heavy Naphta PA

8474L-015-PID-0021-306

HCO recycle

8474L-015-PID-0021-307

LCO PA Pumps

8474L-015-PID-0021-308

HCO PA Pumps & HCO PA MPS Generator

8474L-015-PID-0021-309

Main Fractionator Upper Section

8474L-015-PID-0021-310

Main Fractionator Lower Section

8474L-015-PID-0021-311

Slurry PA Pumps

8474L-015-PID-0021-312

Slurry PA HP steam generators A&B

8474L-015-PID-0021-313

Slurry PA HP steam generators C

8474L-015-PID-0021-314

Slurry PA HP/MP steam generators A

8474L-015-PID-0021-315

Slurry PA HP/MP steam generators B

8474L-015-PID-0021-316

HCO Stripper

8474L-015-PID-0021-317

Heavy Naphta Stripper

8474L-015-PID-0021-318

LCO Stripper

8474L-015-PID-0021-319

Fractionator Overhead

8474L-015-PID-0021-320

Fractionator Reflux Drum

8474L-015-PID-0021-321

Slurry Draw Off Drum

8474L-015-PID-0021-322

Slurry LP Steam Generators

8474L-015-PID-0021-323

Clarified Oil Cooler and Slurry Separator

8474L-015-PID-0021-324

Slurry Separator Backflushing (1/2)

8474L-015-PID-0021-325

Slurry Separator Backflushing (2/2)

8474L-015-PID-0021-326

HCO Flushing Oil

8474L-015-PID-0021-327

HCO Flushing Oil

8474L-015-PID-0021-328

LCO Product Cooling

8474L-015-PID-0021-329

Light Slops Drum

8474L-015-PID-0021-330

Heavy Slops Drum

8474L-015-PID-0021-331

Tempered Water System

8474L-015-PID-0021-332

Phosphate Injection Package

Gas Recovery Section: 8474L-015-PID-0021-401

Wet gas compressor 1st stage KO Drum

8474L-015-PID-0021-402

Wet gas compressor

8474L-015-PID-0021-403

Wet gas compressor Inter/Trim Cooler Page 319 of 323


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8474L-015-PID-0021-404

HP Separator

8474L-015-PID-0021-405

Primary Absorber and Stripper

8474L-015-PID-0021-406

Gasoline Cooldown

8474L-015-PID-0021-407

Secondary Absorber

8474L-015-PID-0021-408

Fuel Gas Absorber

8474L-015-PID-0021-409

Debutanizer

8474L-015-PID-0021-410

Debutanizer Condenser and Reflux Drum

8474L-015-PID-0021-411

LPG Amine Absorber

8474L-015-PID-0021-451

Closed Drain Recovery

8474L-015-PID-0021-452

Blowdown System

8474L-015-PID-0021-453

Amine Closed Drain Recovery

8474L-015-PID-0021-454

Oily Water Lift Station

10.5. Equipment list Refer to the attached equipment list of unit 015: Unit 015 Extracted Equipment List 10.6. Main Equipment Data Sheet 8474L-015-PDS-AE-401

Process Data Sheet of RFCC Analysers

8474L-015-PDS-BV-1501-719

Process Data Sheet of BV-1501

8474L-015-PDS-BV-1502-720

Process Data Sheet of BV-1502

8474L-015-PDS-D-1501-101

Process Data Sheet of D-1501

8474L-015-PDS-D-1501-210

Process Data Sheet of D-1501 (Packing)

8474L-015-PDS-D-1502-102


8474L-015-PDS-D-1503-103


8474L-015-PDS-H-1501-501

Process Data Sheet of H-1501

8474L-015-PDS-H-1502-502


8474L-015-PDS-H-1503-503


8474L-015-PDS-PV-1501-721

Process Data Sheet of PV-1501

8474L-015-PDS-SV-1501-711

Process Data Sheet of SV-1501

8474L-015-PDS-SV-1502-712


8474L-015-PDS-SV-1503-713


8474L-015-PDS-SV-1503-714


8474L-015-PDS-T-1501-211

Process Data Sheet of T-1501 Page 320 of 323


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8474L-015-PDS-T-1501-212

Process Data Sheet of T-1501 (Trays)

8474L-015-PDS-T-1501-213

Process Data Sheet of T-1501 (Packing)

8474L-015-PDS-T-1551-221

Process Data Sheet of T-1551

8474L-015-PDS-T-1551-222

Process Data Sheet of T-1551 (Tray)

8474L-015-PDS-T-1552-223


8474L-015-PDS-T-1552-224


8474L-015-PDS-T-1553-225


8474L-015-PDS-T-1553-226


8474L-015-PDS-T-1554-227


8474L-015-PDS-T-1554-228


8474L-015-PDS-T-1555-229


8474L-015-PDS-T-1555-230


8474L-015-PDS-T-1556-231


8474L-015-PDS-T-1556-232

Process Data Sheet of T-1556 (Packing)

8474L-015-PDS-X-1504-604

Process Data Sheet of X-1504

8474L-015-PDS-X-1507-607

Process Data Sheet of X-1507

10.7. Instrument List Refer to attached extracted instrument list of unit 012: Unit 012 Extracted Instrument List.xls 10.8. Cause & Effect Matrix 8474L-015-DW-1514-602 10.9. Safety Logic diagram 8474L-XX-XXXX-XXX 10.10. Fire & Gas Cause & Effect Chart 8474L-015-DW-1514-610 10.11. Fire & Gas Detectors Layout 8474L-015-DW-1950-001

Fire & Gas Detector Layout RFCC/LTU/NTU

10.12. Fire Protection Layout 8474L-015-DW-1933-001

Fire Protection Layout RFCC/LTU/NTU

8474L-015-DW-1933-011

Safety Equipment Layout RFCC/LTU/NTU Page 321 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

10.13. Hazardous Area Classification 8474L-015-DW-1920-001 Hazardous Area Classification Plan – RFCC/LTU/NTU 10.14. MSDS For the MSDS of the following chemicals, refer to the attachments of the licensor operating manual: •

Nickel Passivator EC9192

•

Corrosion Inhibitor CHIMEC 1430

•

Anti foam Chemical CHIMEC 8045

•

Phosphate NALCO 7208

10.15. Vendors Documentation COB/WHB Package: 8474L-015-A0103-0160-001-029 P&ID Combustion air system 8474L-015-A0103-0160-001-030 P&ID CO Combustor 8474L-015-A0103-0160-001-031 P&ID CO Combustor 8474L-015-A0103-0160-001-032 P&ID Fuel Skid 8474L-015-A0103-0160-001-033 P&ID Waste Heat Recovery Section 8474L-015-A0103-0160-001-034 P&ID Steam Drum 8474L-015-A0103-0160-001-035 P&ID Blowdown System 8474L-015-A0103-0160-001-142 P&ID Economizer 8474L-015-A0103-0160-001-143 P&ID Ancillaries 8474L-015-A0103-0160-001-144 P&ID Economizer Sootblower 8474L-015-A1001-0160-001-098 H-1503 Package Datasheet Electrostatic Precipitator: 8474L-015-A0103-4240-002-005 P&ID ESP 8474L-015-A0103-4240-002-009 P&ID ESP 8474L-015-A0103-4240-002-128 P&ID ESP 8474L-015-A0103-4240-002-129 P&ID ESP 8474L-015-A0103-4240-002-130 P&ID ESP 8474L-015-A0103-4240-002-131 P&ID ESP 8474L-015-A0103-4240-002-133 P&ID ESP 8474L-015-A1001-4240-001-011 Data Sheet X-1507 8474L-015-A3501-4240-002-122 X-1507 Operational Procedure 8474L-015-A3501-4240-002-135 Ash Handling Control Flowchart Page 322 of 323


DOC NO: 8474L-015-A5016-0000-001-005 REV: A

DATE: 06/12/07

8474L-015-A3505-4240-001-023 Logic Sequence Diagram Wet Gas Compressor: 8474L-015-A1001-1010-001-007 Data Sheet of C-1551 8474L-015-A3501-1010-001-108 Control System Description 8474L-015-A3505-1010-001-041 Cause & Effect Diagram Air Blower: 8474L-015-A1001-1040-001-226 Blower Data Sheet 8474L-015-A3505-1040-001-063 Blower Cause & Effect Diagram

Page 323 of 323

RFCC

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