Tài Loeeuj Thầy Hait

8/17/2019 Tài Loeeuj Thầy Hait

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Vendor Document No. Rev. Page ARAMIS Development Ltd

TPC-DQR-002-TRM-OPS-013 A 1 of 237

TRAINING MODULE

CONTINUOUS CATALYTIC REFORMER (CCR)

UNIT: 13

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-013-A5016-0000-001-003

Stamp

Document Class: XComment given in this document does not relieve vendor of his/her responsibility for thecorrect engineering design and fabrication. This equipment or product shall be made as perthe codes, requisition, specification, project procedures, and international standards.

A 19-OCT-07 Issue for review Benoit Rabaud Paul Walsh JB Guillemin

RevDate

DD-MMM-YYStatus

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 marginDOCUMENT REVISIONS


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TRAINING MODULE DOC NO: 8474L-013-A5016-0000-001-003

CONTINUOUS CATALYTICREFORMER (CCR)

REV: A DATE: 19/10/07

Page 2 of 237

TRAINING MODULE


UNIT: 13

A 19/10/07 Benoit Rabaud Paul Walsh JB Guillemin

REV DATE PREPARED BY CHECKED BY APPROVED BY

TRAINING DURATION VENUE

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 QUATREFINERY.

THIS MODULE MUST BE RECOGNIZED AS A TOOL AND GUIDE ONLY. IT WOULD BEIMPOSSIBLE 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 REFERENCEMATERIALS UTILIZED, WHILE PERFORMING OPERATIONAL DUTIES, CONFORM AT A

MINIMUM TO THE LATEST ISSUE OF STANDARD OPERATING PROCEDURES, SAFETYCODES, ENGINEERING STANDARDS, AND GOVERNMENT REGULATIONS.

SOME DESIGN FIGURES MIGHT NOT BE IN LINE DURING THE START-UP OF THEREFINERY.


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TABLE OF CONTENT

SECTION 1 : GENERAL description........................................................................................... 11

1.1. Purpose of the Unit ................................................................................................ 14

1.2. Basis of Design ...................................................................................................... 19

1.2.1. Duty of Plant ............................................................................................... 19

1.2.2. Feed Characteristics................................................................................... 19

1.2.3. Product Specifications ................................................................................ 19

1.2.3.1. Reformate......................................................................................19

1.2.3.2. Unstabilized LPG........................................................................... 20

1.2.3.3. Make Up H2 Gas............................................................................ 20

1.2.3.4. Fuel Gas ........................................................................................ 211.2.4. Utility/Power/Chemicals/Catalyst consumption .......................................... 21

1.2.4.1. Utility Consumption ....................................................................... 22

1.2.4.2. Chemicals...................................................................................... 32

1.3. Glossary of terms and Acronyms........................................................................... 35

1.3.1. Acronyms.................................................................................................... 35

1.3.2. Glossary...................................................................................................... 38

SECTION 2 : Process Flow Description...................................................................................... 40

2.1. Platforming Reaction Section................................................................................. 402.1.1. Feed preheater section............................................................................... 40

2.1.2. Charge heater and inter heaters................................................................. 40

2.1.3. Reactors...................................................................................................... 41

2.1.4. Reactor effluent...........................................................................................41

2.1.5. Reactor effluent separator .......................................................................... 42

2.1.6. Recycle compressor ................................................................................... 42

2.1.7. Steam generation........................................................................................ 42

2.1.8. RECOVERY PLUS system......................................................................... 43

2.1.8.1. Refrigeration Circuit....................................................................... 43

2.1.8.2. Net Gas Circuit .............................................................................. 43

2.1.8.3. Liquid Circuit.................................................................................. 44

2.1.9. Net Gas Chloride Treaters.......................................................................... 44

2.1.10. Chemical injection..................................................................................... 44

2.1.10.1. Chloride injection package X-1307.............................................. 44

2.1.10.2. Sulfide injection package X-1396 ................................................ 45


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2.1.10.3. Phosphate dosing drum X-1397.................................................. 45

2.1.11. Debutanizer Section.................................................................................. 45

2.2. Regeneration Section ............................................................................................ 46

2.2.1. Spent Catalyst Transfer.............................................................................. 472.2.2. Burn Zone / Reheat Zone ........................................................................... 48

2.2.3. Chlorination Zone........................................................................................ 49

2.2.4. Drying Zone ................................................................................................ 50

2.2.5. Cooling Zone............................................................................................... 51

2.2.6. Reduction Zone........................................................................................... 52

2.2.7. Regenerated Catalyst Transfer................................................................... 53

2.2.8. Lift gas & Fines removal circuit................................................................... 54

2.2.9. Normal Catalyst Addition ............................................................................ 56

2.2.10. Catalyst Change-out on the fly.................................................................. 57

2.2.11. Vent Gas Wash Tower.............................................................................. 59

2.2.12. Process Pressures and Environments...................................................... 61

SECTION 3 : Process control...................................................................................................... 65

3.1. Control Narrative & Operating parameters............................................................ 65

3.1.1. Charge heater & inter-heaters temperature outlet control.......................... 65

3.1.2. Reactor Section Pressure Control .............................................................. 69

3.1.3. Separator D-1301 Level control.................................................................. 70

3.1.4. Steam Generation Controls ........................................................................ 71

3.1.5. Water Circulation Pumps Logic P-1303 A/B............................................... 73

3.1.6. Debutanizer T-1301 Temperature Control.................................................. 75

3.1.7. Catalyst Circulation Control ........................................................................75

3.1.7.1. Catalyst Flow Pushbutton.............................................................. 78

3.1.7.2. Catalyst circulation rate set point & set point ramping.................. 79

3.1.7.3. Lock Hopper Sequence................................................................. 79

3.1.8. Regeneration System Tower ...................................................................... 90

3.1.9. Regeneration Tower T-1351 Isolation Systems ......................................... 94

3.1.9.1. Regenerator Inventory Switch....................................................... 98

3.1.10. Dust Collector Fines Unloading: ............................................................... 99

3.1.11. Catalyst Addition: .................................................................................... 102

3.1.12. Catalyst Change-out on the fly................................................................ 106

3.1.13. Inter-Unit Controls & Interfaces............................................................... 109

3.1.14. Operating Parameters............................................................................. 109

3.2. Instrument List...................................................................................................... 110


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3.3. Main Equipment ................................................................................................... 111

3.3.1. Heaters H-1301, H-1302, H-1303 & H-1304 ............................................ 111

3.3.2. Reactor R-1301, R-1302, R-1303 & R-1304 ............................................ 114

3.3.3. Recycle Compressor C-1301 & Steam Turbine CT-1301........................ 1173.3.4. Debutanizer T-1301.................................................................................. 119

3.3.5. Regeneration Tower T-1351..................................................................... 121

3.3.6. Nitrogen Seal Drum D-1357 ..................................................................... 126

3.3.7. Lock Hopper D-1358................................................................................. 127

3.3.8. Catalyst L-Valve Assemblies.................................................................... 130

3.3.9. Reduction Zone......................................................................................... 132

3.3.10. Disengaging Hopper D-1353 ..................................................................134

3.3.11. Electric Heaters....................................................................................... 136

3.3.12. Vent Gas Tower T-1352.......................................................................... 138

SECTION 4 : Safeguarding devices .......................................................................................... 141

4.1. Alarms and Trips.................................................................................................. 141

4.2. Safeguarding Description..................................................................................... 141

4.2.1. CCR Platforming Reaction Section .......................................................... 141

4.2.1.1. Loss of Make up compressor (unit 12)........................................ 141

4.2.1.2. Heaters Protection (UX-001):...................................................... 141

4.2.1.3. Recycle Compressor Protection (UX-002).................................. 142

4.2.1.4. Separator pumps P-1301 A/B and Debutanizer pumps P-1302 A/BProtection (UX-003): ................................................................................. 142

4.2.1.5. Debutanizer Overhead Pumps P-1302 A/B Protection (UX-004)142

4.2.1.6. Debutanizer Isolation................................................................... 142

4.2.1.7. Air coolers Motor vibration protection.......................................... 143

4.2.2. CCR Regeneration Section ...................................................................... 143

4.2.2.1. Regenerator Automatic Shutdown Summary.............................. 143

4.2.2.2. Regeneration Tower Automatic Stops ........................................ 146

4.2.2.3. Lock Hopper D-1358 Abnormal Unload/Load Alarms................. 149

4.2.2.4. Lock Hopper Level Switch Malfunction Alarm............................. 150

4.2.2.5. Lock hopper Starting & Stopping Sequence............................... 150

4.2.2.6. Catalyst Flow Interrupt Systems ................................................. 151

4.2.2.7. Regenerated Catalyst Lift Line Valve.......................................... 152

4.2.2.8. Regeneration Section Isolation Systems .................................... 152

4.2.2.9. Reduction Zone/Reactor #1 Differential Pressure system.......... 153

4.2.2.10. Vent Gas Wash Wash Tower T-1352 Protection ...................... 155


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4.3. Safeguarding Equipment ..................................................................................... 156

4.3.1. Pressure Safety Devices .......................................................................... 156

SECTION 5 : Fire & Gas Systems............................................................................................. 162

5.1. Fire & Gas detection ............................................................................................ 162

5.2. Fire Protection...................................................................................................... 169

SECTION 6 : Quality control......................................................................................................177

6.1. Sampling connections.......................................................................................... 177

6.2. On-line analyzers ................................................................................................. 181

SECTION 7 : Causes and effect................................................................................................183

7.1. Cause & Effect Matrix: ......................................................................................... 183

7.1.1. Example from Cause and Effect Chart ..................................................... 183

7.1.1.1. Sheet 1: Reactor Heater H-1301/02/03/04 Shutdown (UX-001). 183

SECTION 8 : Operating practices.............................................................................................. 186

8.1. Normal Operation................................................................................................. 186

8.1.1. Operating conditions................................................................................. 186

8.1.2. CCR Platforming Reaction Section ..........................................................186


8.1.4. Guidelines for operation of the reactor section......................................... 193

8.1.4.1. Reaction loop pressure ............................................................... 193

8.1.4.2. Reactors inlet temperatures ........................................................ 194

8.1.4.3. Space velocity ............................................................................. 195

8.1.4.4. Chloride water balance................................................................ 195

8.1.5. Guidelines for the operation of the Debutanizer section .......................... 197

8.1.5.1. Debutanizer Overhead ................................................................197

8.1.5.2. Debutanizer Bottom.....................................................................198

8.1.6. Operation Guidelines for CCR Regeneration Section.............................. 198

8.1.6.1. Reheat Zone and Chlorination Zone temperature ...................... 198

8.1.6.2. Chlorination Zone Gas Flowrate .................................................1988.1.6.3. Lower Air Rates........................................................................... 199

8.1.6.4. Lock Hopper Makeup Valve (Learning Valve) Adjustments ....... 199

8.1.6.5. Dust Collector reverse Jet Cleaning............................................200

8.1.6.6. Dust Collector Fines Unloading................................................... 200

8.1.6.7. Normal Catalyst Addition............................................................. 200

8.1.6.8. Filter Cleaning ............................................................................. 201

8.1.6.9. Catalyst Change-out on the fly.................................................... 202


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8.2. Start-up Procedure............................................................................................... 203

8.2.1. Start-Up Sequence ................................................................................... 204

8.3. Shutdown Procedures..........................................................................................209

8.3.1. CCR Platforming Reaction Section shutdown.......................................... 2108.3.2. CCR Regeneration Section Manual Shutdown ........................................ 211

8.4. Emergency Shutdown.......................................................................................... 213

8.4.1. CCR Platforming Reaction Section ..........................................................213

8.4.1.1. Loss of feed................................................................................. 213

8.4.1.2. Loss of recycle compressor......................................................... 213

8.4.1.3. Instrument air failure.................................................................... 214

8.4.1.4. Cooling water failure....................................................................215

8.4.1.5. HP Steam failure ......................................................................... 216

8.4.1.6. Boiler Feed Water Failure ........................................................... 216

8.4.1.7. Electrical Power Failure............................................................... 216

8.4.1.8. Loss of refrigerant........................................................................ 217

8.4.1.9. Fuel Gas Failure.......................................................................... 217

8.4.1.10. Major Upset................................................................................ 217


8.4.2.1. Power Failure .............................................................................. 218

8.4.2.2. Instrument Air Failure..................................................................219

8.4.2.3. Plant air failure............................................................................. 219

8.4.2.4. Recycle compressor Failure........................................................ 219

8.4.2.5. Booster compressor failure ......................................................... 220

8.4.2.6. Cooling Water Failure.................................................................. 220

8.4.2.7. Explosion, fire, line rupture or serious leak ................................. 220

8.4.2.8. CCR Nitrogen Failure..................................................................220

SECTION 9 : HSE...................................................................................................................... 223

9.1. Hazardous Areas ................................................................................................. 223

9.2. Safety Equipment................................................................................................. 225

9.3. Specific PPE ........................................................................................................225

9.3.1. Hydrogen Sulfide ...................................................................................... 226

9.3.2. Minimizing exposure to armomatics .........................................................226

9.4. Chemical Hazards................................................................................................ 227

9.4.1. Hydrogen Sulfide Poisoning ..................................................................... 228

9.4.1.1. Acute Hydrogen Sulfide Poisoning.............................................. 228

9.4.1.2. Subacute Hydrogen sulfide Poisoning ........................................ 229


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9.4.2. Benzene.................................................................................................... 229

9.4.2.1. Special Instruction:...................................................................... 229

9.4.3. Toluene, Xyllene & Heavier armomatics .................................................. 229

SECTION 10 : Reference documents index.............................................................................. 232

10.1. Operating Manual/ Licensor Documentation .......................................................232

10.2. Arrangement Drawings, Layouts and Plot Plans .................................................232

10.3. Process Flow Diagrams....................................................................................... 232

10.4. Piping and Instrumentation Diagrams.................................................................. 232

10.5. Equipment list....................................................................................................... 235

10.6. Main Equipment Data Sheet................................................................................ 235

10.7. Instrument List...................................................................................................... 236

10.8. Cause & Effect Matrix .......................................................................................... 23610.9. Safety Logic diagram ........................................................................................... 236

10.10. Fire & Gas Cause & Effect Chart .............................................................. 236

10.11. Fire & Gas Detectors Layout..................................................................... 236

10.12. Fire Protection Layout............................................................................... 236

10.13. Hazardous Area Classification.................................................................. 236

10.14. MSDS........................................................................................................236

10.15. Vendors Documentation............................................................................ 237


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TRAINING MODULE


UNIT: 13

Course Content:

Section 1 - General Description

XSection 2 - Process Flow DescriptionSection 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 CCR is divided in 2 sections:

• Reaction Section or Platforming, which processes the hydrotreated straight run heavynaphtha from the naphta splitter of unit 12 to produce a high octane gasoline blendingcomponent. This is achieved by using a catalyst refining process to transform naphtenesinto aromatics while minimizing the conversion of paraffins and aromatics. The main by-product of this process, hydrogen, is then used in unit 12.

• Regeneration section, which continuously regenerate the catalyst in 4 steps:

o Burning of the accumulated coke

o Oxychlorination – To disperse the catalyst metals and adjusting the catalystchloride content

o Catalyst Drying

o Reduction – To change the catalyst metals to the reduced state

The CCR unit is located in the area 2 with the Naphta Hydrotreater Unit (NHT, 012) and theLight Naphta Isomerization Unit (ISOM, 023).


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FUTURE

FUTURE

021024

FUTURE

CRUDETANK

055

060

032

058

033

FUTURE

051

051

051

051 038/ 056

051/ 054/ 055

031

039

035

059

036

019

012013

020

022013

023

014 011

040

S L U D G E

F A R M

057

LEGEND

UNITNUMBER

PROCESSUNIT

011

012

013

014

015

016

017

018

019

020

021

022

023

024

CRUDEDISTILLATIONUNIT

NAPHTHAHYDROTREATERUNIT

CONTINUOUSCATALYTICREFORMERUNIT

KEROSENETREATERUNIT

RESIDUEFLUIDCATALYTICCRACKINGUNIT

LPGTREATERUNIT

RFCCNAPTHATREATERUNIT

SOURWATERSTRIPPINGUNIT

AMINEREGENERATIONUNIT

SPENTCAUSTICNEUTRALISATIONUNIT

PROPYLENERECOVERYUNIT

SULPHURRECOVERYUNIT

LIGHTNAPTHAISOMERISATIONUNIT

LCOHYDROTREATERUNIT

UNIT

NUMBERUTILITIESSYSTEMUNIT

031

032

033034

035

036

037

038

039

040

WATERSYSTEM( POTABLE, PLANT, DEMIN)

STEAMGENERATION/ DISTRIBUTIONSYSTEM

COOLINGWATERSYSTEMSEAWATERINTAKESYSTEM

PLANTANDINSTRUMENTAIRSYSTEM

NITROGENSYSTEM

FUELGASSYSTEM

FUELOILSYSTEM

CAUSTICSUPPLYSYSTEM

ELECTRICALPOWERGENERATIONAND

DISTRIBUTIONSYSTEM

UNIT

NUMBEROFFSITEFACILITIES

051

054

055

056

057

058

059060

REFINERYTANKAGE

PRODUCTBLENDING

FLUSHINGOIL

SLOPS

FLARESYSTEM

EFFLUENTTREATMENTSYSTEM

FIREWATERSYSTEMCRUDEOIL

37

060

060

060

Figure 1: 2D Refinery Plot Plan


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Figure 2: 3D Refinery Plot Plan


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1.1. Purpose of the Unit

The function of the Platforming unit is to process the hydrotreated straight run heavynaphtha from NHT unit (012) to produce a high octane gasoline blending component.

The catalytic reforming process is a catalytic refining process employing a bimetalliccatalyst to upgrade low octane number naphthas to higher octane motor fuel blendings.

The basic reaction of Platforming is to transform naphtenes into aromatics (most rapidand efficient reaction). The paraffins conversion is very small, and the aromaticshydrocarbons pass through the Platforming unit essentially unchanged.

LPG is a valuable product so recovery of LPG in the naphtha complex is to be maximizedand sent to the LPG spheres. Hydrogen rich gas is another product of the catalyticreforming reactions, required for the operation of units such as hydrotreatment units(NHT, 012), isomerisation (ISOM, 023).

Figure 3: Process Connections of the CCR


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The Continuous Catalytic Regeneration section allows the reaction section to operate inhigh severity conditions. At such conditions, reforming catalyst deactivates more rapidlybecause coke lays down on the catalyst at a faster rate. So without a regenerationsection, the reaction section would have to be shut down more often for regeneration toburn off this coke and restore the catalyst’s activity and selectivity.

In the regeneration section, the catalyst is continuously regenerated while the Platformingreaction section continues to operate.

The Catalyst Regeneration Section consists of a system of integrated equipment that isseparate from, but still connected to, the reaction section. It performs two principalfunctions – catalyst circulation and catalyst regeneration – in a continuous circuit. Firstspent catalyst from the last Platforming reactor is circulated to the Catalyst RegenerationSection. In the Catalyst Regeneration Section, the spent catalyst is regenerated in foursteps:

• Burning of the accumulated coke

•

Oxychlorination – for dispersing the catalyst metals and adjusting the catalystchloride content

• Catalyst drying

• Reduction – for changing the catalyst metals to the reduced state

Finally, the regenerated catalyst is circulated back to the first Platforming reactor. Thelogic and sequence of this circuit are controlled by the Catalyst Regeneration ControlSystem.

In this manner, freshly-regenerated catalyst is continuously circulated through thePlatforming reactors. This ensures that the Platforming reactor section operateseconomically with optimum catalyst performance at high-severity conditions and for long

on-stream periods of operation.


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Figure 5: Unit 13 3D Drawings


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Figure 6: CCR Process Flow Scheme


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1.2. Basis of Design

1.2.1. Duty of Plant

The plant capacity is 21100 BPSD (corresponding to 103496 kg/h) of heavy

naphtha from NHT unit (012) and sweet naphtha.

The CycleMax CCR regenerator has a capacity of 1000 lb/h of catalyst circulation.

The Turndown of the CCR unit corresponds to 50% of the NHT unit (012) plus thesweet naphtha. Consequently, the capacity of unit is around 60% of the CCRdesign capacity.

1.2.2. Feed Characteristics

(This applies to the reaction section only.)

The Platformer is fed with hydrotreated Heavy Naphtha from Unit 012. The unitcan also be fed with sweet heavy naphtha from TK-5104 during start-up in additionof the straight run hydrotreated heavy naphtha.

The heavy naphtha from the NHT unit (Unit 012) will contain less than 0.5 wt ppmS (Sulfur) and less than 0.5 wt ppm N (Nitrogen).

1.2.3. Product Specifications

1.2.3.1. Reformate

Reformate is sent to the storage TK-5107 for blending. The required

reformate properties are the following:

Property Value

RONC 102 min

MON 91 min

C4 content (%vol) 1 max.

The molar composition of the reformate stream is the following:

Compound Reformate (mole %)

Ethane ppm

Propane 0.02

i Butane 0.32

n Butane 0.92

i Pentane 1.87

n Pentane 1.25

C6+ 95.6


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RONC: Research Octane Number

The most important characteristic of gasoline is its Research OctaneNumber or octane rating, which is a measure of how resistant gasoline isto premature detonation ( knocking). It is measured relative to a mixture of

2,2,4-trimethylpentane (an octane) and n-heptane. So an 87-octanegasoline has the same knock resistance as a mixture of 87% isooctaneand 13% n-heptane.

MON: Motor Octane Number

The Motor Octane Numbe (MON) is a better measure of how the fuelbehaves when under load. Its definition is also based on the mixture ofisooctane and n-heptane that has the same performance. Depending onthe composition of the fuel, the MON of a modern gasoline will be about10 points lower than the RON. Normally fuel specifications require both aminimum RON and a minimum MON.

1.2.3.2. Unstabilized LPG

The debutanizer net overhead liquid is treated in the LPG ChlorideTreaters D-1308 A/B and then sent to storage TK-5212 A/B/C/D/E.

C5+ content in LPG product shall not exceed 1.1%mol max. The molarcomposition of the unstabilized LPG stream is the following:

Compound Unstabilized LPG(mole %)

H2O 0.006

H2 0.08

Ethane 0.21

Propane 36.61

i Butane 23.64

n Butane 33.87

i Pentane 0.88

n Pentane 0.05

C6+ 0.06

1.2.3.3. Make Up H2 Gas

Net hydrogen produced in the Platforming Unit is recontacted in theRecovery Plus package (X-1301) and sent to chloride removal D-1302 A/B. After chloride removal, some of the net hydrogen is sent to themake-up gas multi-stage compressors (C-1202 A/B/C) in the NHT Unit(012), where it is pressurized up to the consumers (NHT, LCO HDT,


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Isomerization, NHT H2 storage drums) required pressure levels. Most ofthe net gas product is sent to Fuel Gas system (Unit 037) .

The composition of hydrogen shall be the following in normal operation:

Compound Make up H2 (mole %)

H2 93.3

Ethane 2.5

Propane 1.4

i Butane 0.1

n Butane 0.1

i Pentane 0.04

n Pentane 0.02

C6+ 0.04

1.2.3.4. Fuel Gas

Fuel Gas from the Debutanizer reflux drum can be sent to Fuel GasNetwork (Unit 037).

But normally, no flow is exported to FG network via the debutanizer refluxdrum. Off gas from the debutanizer receiver is sent to the recovery plussystem X-1301.

1.2.4. Utility/Power/Chemicals/Catalyst consumption


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Figure 7: Utilities Connections of the CCR

1.2.4.1. Utility Consumption

The following describes the utility consumption of the ETP based on thefollowing Estimated Utility Consumption Documents:


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8474L-013-CN-0003-001 Design Case - 100% Bach-Ho or MixedCrude Max Gasoline or Distillate

8474L-013-CN-0003-002 Normal Case - 100% Bach-Ho MaxGasoline or Distillate

8474L-013-CN-0003-003 Normal Case - Mixed Crude MaxGasoline or Distillate

In the following, only the normal case – 100% Bach Ho Max Gasoline orDistillate is described.

Note: In the following

( ): Intermittent Producer/Consumer

+: Indicates Quantity Produced

-: Indicates Quantity Consumed


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1.2.4.1.1. Electrical Power

Electrical Power (kW)

Item Tag Description MotorLoadRating

Mech.RunningLoad

Elec.Oper.Load

PLATFORMING SECTION

P-1301A Seperator Pump -53.5

P-1301B Seperator Pump (-53.5)

P-1302A Debutanizer overhead pump -12.2

P-1302B Debutanizer overhead pump (-12.2)

P-1303A Circulating water pump (-45.5)

P-1304AChemical Injection Pump

(Part of X-1307)-0.4

P-1304BChemical Injection Pump

(Part of X-1307)(-0.4)

P-1305Start-Up chemical injection pump

(Part of X-1307)(-0.33)

P-1306ASulfide injection pump

(Part of X-1396)-0.3

P-1306BSulfide injection pump

(Part of X-1396)(-0.3)

P-1307A Surface condensor condensate pump (-13.6)

P-1308 Net gas chloride pump (-2.3)

P-1309AChloride transfer pump

(Part of X-1307)(-0.8)

P-1309BChloride transfer pump

(Part of X-1307)(-0.8)

P-1397APhosphate dosing pump

(Part of X-1397)-0.3

P-1397BPhosphate dosing pump

(Part of X-1397)(-0.3)

M-1397Phosphate storage drum agitator

(Part of X-1397)-0.4

C-1301 Spare lube oil pump (-19)


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Mech.RunningLoad

Elec.Oper.Load

Lube oil exhauster -1.3

Oil conditioner -1.4

Turning gear (-2.4)

REGENERATION SECTION

E-1303 Products condenser -192

E-1304 Debutanizer bottoms cooler [1] -22

E-1308 Debutanizer condenser -24

E-1309 Net gas cooler -24

X-1301 Recovery plus system -1760

M-1398A Sulfite storage drum agitator -1.5

M-1398B Sulfite storage drum agitator -1.5

P-1351A Caustic circulation pump -14.6

P-1361B Caustic circulation pump (-14.6)

P-1352AChloride circulation pump

(Part of X-1307)-0.3

P-1352BChloride circulation pump

(Part of X-1307)(-0.3)

P-1353ACaustic Injection pump

(Part of X-1359)-0.3

P-1353BCaustic Injection pump

(Part of X-1359)-0.3

P-1354AWater injection pump

(Part of X-1360)-1.8

P-1354BWater injection pump

(Part of X-1360)(-1.8)

P-1398Sulfite dosing pump

(Part of X-1398)-0.3

P-1399 Caustic dosing pump -0.3


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Mech.RunningLoad

Elec.Oper.Load

(Part of X-1398)

B-1361 Fines removal blower -3

C-1361 Lift gas blower -13

Aux. lube oil pump (-0.1)

B-1352 Regeneration blower -100

Lube oil pump -0.5

B-1353 Regeneration cooler blower -27

H-1351 Reduction gas heater No.1 -203

H-1352 Reduction gas heater No.2 -79

H-1353 Regeneration heater (-324)

H-1354 Air heater -84

Note:

[1]: Items combined with same fans: E-1209+E-1304. Indicatedelectrical power corresponds to 50% of the total fans power for

these 2 items.


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1.2.4.1.2. Steam

Steam (T/h) Condensate (T/h)

Item No. Description HPSTM

MPSTM

LPSTM

HPcond

MPcond

LPcond

Vac.cond

Losses(T/h)

PLATFORMING SECTION

P-1303BCooling waterpump [2]

-2.9 2.9

P-1307BSurface condensorcondensate pump[3]

-1.40 1.40

C-1301Recyclecompressor [1]

-22.2 22.2

Main lube oil pump -1.7 1.7

Lube oil heater -0.1 0.1

Sealing mainturbine (start-up)

(-0.1) (0.1)

E-1307Debutanizerreboiler

-5.8 5.8

SG-1301/D-1304

Convection section[6]

21.9 0.2 0.8

J-1301 Steam jet ejector (-1.2) (1.2)

J-1302/3Condensateejectors [7]

-0.1 0.1

J-1304 Hogging ejector (-0.2) (0.2)

J-1305Gland condenserejector

-0.1 0.1

H-1301/2/3/4

CCR heaters [5] (-20) (20)

Tracing steam -0.3 -0.1 0.3 0.1


E-1352 Booster gas heater -0.1 0.1

Water injection -0.8 0.8

TOTAL -28.0 -6.6 6.0 5.8 0.4 0.2 21.5 -23.0


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Notes:

[1]. Condensation turbine. Vacuum condensates. Indicatedflowrate is for lean case with normal HP steam (shaft power =4200 kW)

[2]. Shaft power = 45.5 kW



[5]. Purge steam total flowrate injected in all 4 heaters

[6]. For summer fuel gas case

[7]. Main steam condensate ejectors max normal consumption:130kg/hr


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1.2.4.1.3. Cooling Water & Fresh Water

Cooling WaterItem No. Description

ΔT (°C) m3 /h

Fresh Water(T/h)

PLATFORMING SECTION

E-1306Debutanizer bottoms traincooler

6.9 -59.3

E-1310 Debutanizer trim cooler 3.2 -136.3

E-1311 Steam surface condenser 8.0 -1132.0

E-1399 Sewer blowdown cooler 10.4 -4.8

P-1303A Circulating water pump 0 -1.5

P-1303B Circulating water pump 13 -1.5

P-1307ASurface condensercondensate pump 0 -0.5

P-1307BSurface condensercondensate pump

13 -0.5

C1301 Main lube oil pump 13 -0.5

Spare lube oil pump 0 -0.5

Cooling mineral oil coolers 4 -35.2

P-1301A Separator pumps 13 -1.5

P-1301B Separator pumps 13 -1.5

X-1301 Recovery plus system 5.6 -698.0

P-1302ADebutanizer overheadpump

13 -1.5

P-1302BDebutanizer overheadpump

0 -1.5


E-1354 Caustic cooler 13 -24.8

C-1351 Lift gas blower 13 -2.7

Aux lube oil pump 0 -0.5

B-1352 Regeneration blower 13 -2.5

Lube oil pump 13 -05

B-1353Regeneration coolerblower

13 -1.1

TOTAL -2108.7


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1.2.4.1.4. Instrument & Plant Air

Plant Air (Nm3 /h)Item No. Description Inst. Air Nm3 /h

Contin. Intermit.

PLATFORMING SECTION

Control valves and on/offvalves [1]

-30

Analysers &chromatographs [2]

-1

X-1301 Recovery plus system -40

C-1301 Recycle compressor -12


A-1353 Air drier package [3] -731

Control valves & on/offvalves [4]

-92.3

TOTAL 906.3

Notes:

[1]. Estimated consumption is based on 18 control valves (1.5Nm3/h/control valve) and 3 on-off valves (0.45 Nm3/h/on-off

valve)

[2]. Estimated consumption based on 4 analysers /chromatographs (0.2 Nm3/h analysers & chromatographs)

[3]. Air drier product air flowrate (585 Nm3/h) + 20% purgerequirement for reactivation included

[4]. Estimated consumption based on 25 control valves (1.5Nm

3/h/control valve) and 30 on/off valves (2 Nm

3/h/on-off valve)


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1.2.4.1.5. Nitrogen - Bach Ho Max Distillates Case

Nitrogen (Nm3 /h)ItemNo.

DescriptionContin. Intermit.

PLATFORMING SECTION

Reactor section dryout [1] (-1481)

Reactor section start-up [2] (-1281)

Net gas section start-up [3] (-235)

Reactor section shutdown[4]

(1281)

Net gas section shutdown[5]

(-235)

Net gas chloride treateralumina replacement [6]

(-89)

LPG chloride treateralumina replacement [7]

(-17)

Debutanizer section start-up [8]

(-1016)

X-1301 Recovery plus system [9]

C-1301Secondary and tertiaryseals

-82

Primary seal (start-up) (-91)


Process nitrogen [10] [11] -96.0 (-800)

TOTAL -177.0 -1481

Notes:

[1]: Total volume consumed as per UOP requirement = 2325 Nm3








[9]: Start-up only. Consumption to be defined by vendor


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[10]: A peak of total requirement of 800 Nm3/hr required approx.2 days per month and occurs in place of constant nitrogenconsumption rate during that 2 day period.

[11]: Dedicated CCR regeneration nitrogen supply from liquid

nitrogen supply

1.2.4.1.6. Boiler Feed Water

BFW (T/h)Item No. Description

HP BFW MP BFW LP BFW

PLATFORMING SECTION

SG-1301/D-1304

Convection section -23.0

TOTAL -23.0 0.0 0.0

1.2.4.1.7. Furnace and Boilers

Furnaces & Boilers

Item No. Description DutyMW

Efficiency%

Fuel FiredMW

PLATFORMING SECTION

H-1301 Charge heater 8.1 -13.3

H-1302 No.1 Interheater 12.7 -20.9



H-1301/2/3/4

Convection section 18.00.0

TOTAL 52.8 -57.4

1.2.4.2. Chemicals

The following table describes the chemical consumption of the CCR:


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I t e m

D e s

c r i p t i o n

C h

e m i c a l

C o n c

e n t r a t i o n

A v e r

a g e F l o w

k g / h

P i c k F

l o w

( k g / h r )

R e m a r k s

D-1302ANet gas chloride

treater No.1

UOPMOLSIV

adsorbent9139A

D-1302BNet gas chloride

treater No.2

UOPMOLSIV

adsorbent9139A

Volume = 17.5 m3,

13088 kg,

Density = 750 kg/m3

90 days life per volume

D-1308ALPG chloridetreater No.2

UOPMOLSIV

adsorbent9139A

D-1308BLPG chloridetreater No.2

UOPMOLSIV

adsorbent9139A

Volume = 2.5 m3,

1683 kg,

Density=750 kg/m3

180 days life per volume

X-1397Boiler Chemical

DosingTrisodiumphosphate

10 wt% 1.62

XXXChlorideinjection

Perchloro-ethylene

Un-diluted

0.1 110%263 kg required for 30days of operation

XXX Caustic injection Caustic14.4wt%

32.7 110%71000 kg required for 90days of operaton

XXX Catalystsulfiding

Diethyl-sulfide

Un-diluted


XXX Chlorideinjection

Perchloro-ethylene

Un-diluted


R-1301/2/3/4

CCR Catalyst R-234

81 m3 installed volume,

45360 kg,

Density = 560 kg/m3

Losses = 0.55m3 / 90days

X-1301Recovery plus

initial fillingPropylene

3680kg

total

XXX NaClO treatingSodiumsulfite

23 wt% 5.5 120%9600 kg of solid saltsrequired


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Notes:

1. Common chloride storage for CCR platformer and CCR regenerationsections

2. Di-ethyl sulphide storage in NHT unit (X-1252)

3. Catalysed sodium sulphite acts as an oxygen scavenger

4. DMDS can be used alternatively to di-ethylsulfide. In this case anamount of 83 kg is required for 90 days of operaton.

CCR Catalyst:

The Type of catalyst used in the CCR reactors is UOP catalyst R234.Catalysts from R-230

TM series are used to produce high octane reformate

and hydrogen. R-234 catalyst is a low platinum version.

Physical properties of R-230 series catalysts are the following:

Circulating ABD (kg/m3): 537

Static ABD (kg/m3): 561

Nominal diameter (mm): 1.6

Shape: Sphere

R-234 platinum, wt%: 0.290

R-230 series catalyst can be supplied in oxidized or reduced form.

The following quantities of catalyst are required:

Item No. Service Volume (m3)

R-1301 Reactor No.1 11.6




CCR Regeneration Section 25.1

Total 81.0

Catalyst life is around 6 years. Addition of catalyst in continuous (0.55m3) is required to compensate fines losses.


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1.3. Glossary of terms and Acronyms

1.3.1. Acronyms

COMPANIES/ORGANISATIONS

DQR Dung Quat Refinery

DQIZMBDung Quat Industrial ZoneManagement Board

EVN Electricity Authority of VietnamFW Foster Wheeler Energy LimitedMOC Ministry of Construction

MOSTEMinistry of Science, Technologyand Environment

MPIMinistry of Planning andInvestment

SRV Socialist Republic of VietnamTPC Technip Consortium

OTHERS

ACE Application Control Environment MC Marshalling Cabinet

ADAS Analyser Data AcquisitionSystem

MCB Main Control Building

ADP Alarm Display Panel MCC Motor Control Center AER Application Engineers Room MCR Main Control Room

AI Analyser Indicator

MCSMOVControlSystem

MOV Control System

AIT Auto Ignition Temperature MDF Main Distribution Frame

AMS Asset Management System MISManagement InformationSystem

ANSI American National Standardsinstitute

MMS Machine Monitoring System

APC Advanced Process Control MMTMinimum MaintainedTemperature

API American Petroleum Institute MOC Madrid Operating Center

ARUCONTINUOUS CATALYTIC

REFORMER (CCR)

MOM Minutes of Meeting

ASC Analyser Speciality Contractor MOV Motor Operated Valve

ASME American Society ofMechanical Engineers

MP Medium Pressure

ASP Analyser Systems Package MPTMinimum PressurizationTemperature

ASTM American Society of Testingand Materials

MR Material Requisition

ATM Asynchronous Transfer Mode MRR Marshalling Rack RoomBCS Blending Control System MSD Material Selection DiagramBEDD Basic Engineering Design Data MSDS Material Safety Data SheetBFD Block Flow Diagram MTBF Mean Time Between Failures


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BFW Boiler Feed Water MTTR Mean Time To RepairBL Battery Unit MTO Material Take-OffBOM Bill of Materials MTPA Metric Tonnes per Annum

BPC Blending Properties Control MVIPMulti Vendor InterfaceProgram (Honeywell)

BPCD Barrels per Calendar Day NACENational Association ofCorrosion Engineers

BPSD Barrels per Stream Day NCR Non Conformance ReportBRC Blending Ratio Control NDE Non Destructive Examination

CAD Computer Aid Design NFPANational Fire Protection Association

CALM Catenary Anchor Leg Mooring NHT Naphtha Hydrotreater (Unit)CBT Commercial Bid Tabulation NIR Near Infrared Spectroscopy

CCARControl Complex AuxiliaryRoom

NPSH Net Positive Suction Head

CCC Central Control Complex NPV Net Present Value

CCR Continuous Catalytic Reformer NTU Naphtha Treater UnitCCTV Closed Circuit Television OAS Oil Accounting SystemCD Chart Datum OJT On Job Training

CDUCONTINUOUS CATALYTICREFORMER (CCR)

OM&SOil Movement and StorageControl System

CENELECEuropean Committee forElectrotechnical Standardization

OMSAOil Movement and Storageautomation

CFC Chlorofluorocarbons OOS Operation Override Switch

CFRCooperative Fuel Research(Engine)

OPSSOperations Planning andScheduling System

C&I Control and Instrumentation OSBL Outside Battery Limit

CMMSComputerized Maintenance

Management SystemOTS Operator Training Simulator

CNU(Spent) Caustic NeutralizationUnit

PABXPrivate Automatic BranchExchange

CPI Corrugated Plate Interceptor PAGAPublic Address / General Alarm

CSI Control Systems Integrator PCB Printed Circuit BoardDAF Dissolved Air Flotation PFD Process Flow DiagramDAU Data Acquisition Unit PFM Path Find ModuleDCS Distributed Control System PDB Project Documents Base

DEA Diethanolamine PGCProcess Gas Chromatograph(Analysers)

DEIA

Detailed Environmental Impact

Assessment PHD Plant History DatabaseDMDS Dimethyldisulfide PI Plant AirDMS Document Management System PIB Process Interface Building

DNV Det Nork Veritas PIDPiping and InstrumentDiagram

DPTDDesign, Pressure, TemperatureDiagram

PIMProject ImplementationManual

DQMISDung Quat ManagementInformation System

PKSProcess Knowledge System(Honeywell DCS)

DQRP Dung Quat Refinery Project PLEM Pipeline End ManifoldDVM Digital Video Manager PLG Planning


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DWT Dead Weight Tonnes PMCProject ManagementConsultant

EL Equipment List PMI Positive Material IdentificationEOR End of Run PMT Project Management Team

EDMSElectronic DocumentManagement System PO Purchase Order

EMC Electromagnetic Compatibility POC Paris Operating Center

EPCEngineering Procurement,Construction andCommissioning

PP Project Procedure

ERP Enterprise Resource Planning PPB Parts per BillionES Ethernet Switch PPM Parts per MillionESD Emergency Shut Down PRU Propylene Recovery UnitETP Effluent Treatment Plant PWHT Post Weld Heat TreatmentETS Effluent Treatment System QA Quality AssuranceEWS Engineering Work Station QC Quality Control

FDC Feed Development Contract RA Risk AnalysisFAP Fire Alarm Panel R&D Research and Development

FAT Factory Acceptance Test RDBMSReal Time DatabaseManagement System

FEL Front End Loading RFCCResidue Fluid CatalyticCracking

F&G Fire and Gas System RFSU Ready for Start-UpFIU Field Interface Unit RLU Remote Line UnitFIC Flow Indicating Controller ROW Right of Way

FM Factory Mutual (Approval body) RPMSRefinery PerformanceManagement System

FOTC Fibre Optic Termination Cabinet RTDResistance Temperature

Detector

FSCFail Safe Controller (HoneywellESD)

RTDBReal Time Data Base(System)

FTE Fault Tolerant Ethernet RTU Remote Terminal UnitGC Gas Chromatograph SAT Site Acceptance TestGFT Ground Fault SBT Segregated Ballast Tanks

HAZAN Hazard Analysis Study SBMSSoftware Bypass ManagementSystem

HAZOP Hazard and Operability Study SCADASupervisory Control and Data Acquisition

HDT Hydrotreater SCC Satellite Control Complex

HEI Heat Exchange Institution SCE

Simulation Control

EnvironmentHHP High High Pressure (Steam) SCR Satellite Control RoomHGO Heavy Gas Oil SDH Synchronous Digital HierarchyHIC Hydrogen Induced Cracking SE Safety EarthHP High Pressure S&E Safety & EnvironmentalHSE Health, Safety and Environment SGS Safeguarding System

HVACHeating Ventilation AirConditioning

SOE Sequence of Events

IA Instrument Air SOR Start of Run

ICAOInternational Civil AviationOrganisation

SOW Scope of Work


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ICE Instrument Clean Earth SP Specification

ICS Integrated Control System SPIRSpare Parts andinterchangeability Record

IIP Initial Interface Plan SPM Single Point MooringI/O Input/Output SR Scope of SupplyIP Institute of Petroleum SRU Sulphur Recovery Unit

IPSInstrumented ProtectiveSystem

STC Construction Standard

IRP Interposing Relay Panel STD Design StandardIRR Internal Rate of Return STEL Short Term Exposure Limit

IS Intrinsically Safe SVACShelter Ventilation and AirConditioning

ISA Instrument Society of America System (Analyser houses)ISE Intrinsically Safe Earth SWS Sour Water Stripping (Unit)ISBL Inside Battery Limit TAS Terminal Automation SystemISOM Isomerisation Unit TBT Technical Bid Tabulation

ITB Invitation to Bid TCF Temporary ConstructionFacilitiesITP Inspection and Test Plan TCM Task Control Module

JB Junction Box TEMATubular ExchangerManufacturers' Association

JCC Jetty Control Complex TGIFTemperature Gauge IndicationFacilities (Tankage)

JCR Jetty Control Room TLCR Truck Loading Control RoomJSD Job Specification for Design TLCS Truck Loading Control SystemJSS Job Specification for Supply TN Transmittal Note

JVD Joint Venture Directorate TPSTotal Plant Solution(Honeywell)

KLOC Kuala Lumpur Operating Center TQM Total Quality ManagementKTU Kerosene Treatment Unit TS Terminal ServerLAN Local Area Network TWA Time Weighted AverageLCO Light Cycle Oil UFD Utility Flow diagramLCOHDT LCO Hydrotreater U/G Underground

LDE Lead Discipline Engineer ULUnderwriter Laboratories(Approval body)

LELLower Exposition Limit (F&G, Analysers)

UPS Uninterruptible Power Supply

LGO Light Gas Oil VDU Visual Display Unit

LIMSLaboratory InformationManagement System

VPU Vendor Package Unit

LIS Laboratory Information System WABT Weight Average BedTemperature

LLU Local Line Unit WBS Wash Breakdown StructureLP Low Pressure WHB Waste Heat BoilerLPG Liquefied Petroleum Gas YOC Yokohama Operating CenterLTU LPG Treater Unit

1.3.2. Glossary

Refer to separate glossary.


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TRAINING MODULE


UNIT: 13

Course Content:

Section 1 - General Description

Section 2 - Process Flow Description XSection 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 2 : PROCESS FLOW DESCRIPTION

DRAWING TO BE INSERTED (DRAWING IN PROGRESS)

Figure 8: CCR Block Flow Diagram

A detailed description of each section of the CCR is shown bellow, sorted by main steps.

2.1. Platforming Reaction Section

2.1.1. Feed preheater section


Figure 9: Simplified PFD of the Reactors Section

The platformer feed, hydrotreated heavy naphtha, coming from the NaphthaSplitter (Unit 12), enters the unit under flow control and is filtered to remove anyparticles which may plug the welded plate-type exchanger E-1301 where the feedis then routed.

In normal operation, the feed is directly supplied from the Naphtha Splitter (T-1202) via the Stripper Feed Naphtha Splitter Bottoms cooler (E-1206) in the unit012.

Before the feed is supplied to the combined feed exchanger E-1301, sulfide is

injected by means of the sulfide injection pumps P-1306 A/B. Chloride is alsoinjected periodically in the feed upstream E-1301 by means of thechloride/condensate injection pumps P-1304 A/B in the chloride injection packageX-1307.

A recycle hydrogen rich gas from the recycle compressor C-1301 is also suppliedto the Combined Feed Exchanger E-1301 where it is mixed with the feed stream.The combined feed (liquid feed + recycle gas) is heated up by heat exchange withthe reactor effluent from the last reactor R-1304 in E-1301.

The combined feed is then sent to the Charge Heater H-1301 to be heated up tothe desired temperature before entering the first reactor R-1301 in the reactorstack.

2.1.2. Charge heater and inter heaters

The heat and reheat section consists of the Charge Heater and 3 Inter-heatersbetween the reactors. In the reactors, the chemical reactions that occur are mostlyendothermic, and so the outlet temperature of each reactor is less than the inlettemperature. The function of the interheaters is to raise the temperature of eachreactor’s effluent back up to reaction temperature for the next reactor:

Rection effluent leaving the bottom of reactor No.1 R-1301 is heated up ininterheater No.1 H-1302 and sent to the top of the reactor R-1302.


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Effluent from reactor 2 R-1302 is heated in interheater No.2 H-1303 and sent toreactor R-1303.

Effluent from reactor 3 R-1303 is heated in interheater No.3 H-1304 and sent toreactor R-1304.

The Charge Heater and the Interheaters in UOP Continuous Platforming Units arecontained in a single, partitioned, multi-cell heater box. The heater box has aconvection section to recover heat from the flue gas to generate HP steam.

Fuel Gas used in the heaters firing systems is supplied from the Fuel Gas Headerfrom unit 037.

2.1.3. Reactors

In the reactors, the heated heavy naphta reacts on the catalyst to produce the highoctane gasoline blend desired via 2 major types of reactions: hydrogen consumingreactions and hydrogen producing reactions.

The reactor stack is composed of 4 reactors constructed together to form onelarge vessel. The bottom heads of the individual reactors are used to divide thisvessel into separate reactors.

In order to have a low pressure drop, the reactors design is radial flow:

Hydrocarbon enters at the top of the reactor and flows across the catalyst bedfrom the outside to the inside of the reactor. Process vapors then flow through thecenter pipe and out the reactor.

Catalyst enters at the top of the reactor, flows down through the reactor, and exitsat the bottom. The reactor stack is equipped with reactor internals that permitcatalyst transfer series flow through the stack; i.e. from one reactor to the next.

Fresh regenerated catalyst is introduced at the top of the 1st

reactor. The catalystexiting the last reactor R-1304 is sent to the regeneration section.

The temperature of the process vapor drops rapidly in going through the catalystbed, since the reactions are very endothermic. Therefore, they must be reheatedbefore they enter the next reactor to support further reactions. After reheating, thevapors go to the next reactor where the process is repeated.

Recycle H2 gas from the recycle compressor is also injected at the bottom of thelast reactor to sustain the hydrogen consuming reactions.

2.1.4. Reactor effluent

Leaving the Reactor No.4 R-1304, the effluent is split into two streams:• 1 stream is used to heat up the recycle gas injected at the bottom of R-

1304 in the reactor purge exchanger E-1302

• The other stream is cooled by exchange with the combined feed stream inthe Combined Feed Exchanger E-1301.

These 2 streams are recombined downstream exchanger E-1301 and then furthercooled in the Products Condenser E-1303.

After cooling, the reactor effluent is sent to the Separator D-1301 where H2 richvapour is separated from the liquid hydrocarbon, by using a wire mesh inside D-1301 to catch any liquid entrainment.


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2.1.5. Reactor effluent separator

The hydrogen rich stream is then compressed by the recycle compressor C-1301and split into 2 streams:

• The majority of the gas stream is recycled back into the reaction section:Most of it is sent to the combined feed exchanger E-1301 for mixing withthe platformer feed and a slip stream is sent back to the bottom of thereactor R-1304 after being heated up against R-1304 effluent in E-1302.

• The remaining stream, so called Net Gas is cooled in the net gas cooler E-1304 and then sent to the Recovery Plus system X-1301 to allow therecovery of LPG / Reformate which remain in the net gas stream. This NetGas is mixed with off gas from the debutanizer receiver upstream theRecovery Plus Package X-1301.

Part of the Separator liquid is pumped by the separator pump P-1301 A/B to therecovery plus system where it is recontacted with the liquid effluents, while the

other part is sent to the debutanizer feed/bottoms exchanger before being fed tothe debutanizer T-1301.

2.1.6. Recycle compressor

The recycle compressor C-1301 is driven by a steam turbine CT-1301 using HPsteam from HP steam header.

LP steam from the turbine exhaust is condensed against cooling water in thesurface condenser E-1311. Condensate is then pumped by the surface condensercondensate pumps P-1307 A/B to the vacuum condensate system.

2.1.7. Steam generation


Figure 10: Simplified PFD of the Steam Generation Section

HP Steam is available from interconnecting header. But HP steam is alsoproduced using HP Boiler Feed Water (BFW) from Header:

BFW is preheated in the convection section SG-1301 of the heater H-1301/02/03/04 before entering the disengaging drum D-1306. Steam from thisdrum is then re-heated through the convection section of heaters, resulting in HPsteam sent to the De-superheater DS-1301.

In case of water flow drop, water from the steam disengaging drum D-1306 isrecirculated to the steam convection section SG-1301 via the circulating waterpumps P-1303 A/B (1 electric + 1 steam driven).

From the disengaging drum, there is also a continuous blowdown of vapour/liquidto the continuous blowdown drum D-1304 and an intermittent blowdown of liquidto the intermittent blowdown drum D-1305.

LP steam exits D-1304 where water is separated and directed to D-1305. In D-1305, the collected water is sent to the sewer after being cooled in E-1399 againstcooling water.


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2.1.8. RECOVERY PLUS system


Figure 11: Simplified PFD of Recovery Plus System

The RECOVERY PLUS™ system contains (principally) the following circuits:

2.1.8.1. Refrigeration Circuit

The refrigeration circuit in the RECOVERY PLUS™ system is apressurized closed loop.

The propylene refrigerant flows to the Combined Chiller X-1301-E-03through a valve in which the pressure drop vaporizes a portion of theliquid refrigerant, and the resultant phase change chills it to the requiredoperating temperature.

The frothing of the refrigerant in the Chiller covers the rest of the tubes.Rich Net Gas and Lean Oil pass through their respective tube bundles,cooled by refrigerant evaporation. The vaporized refrigerant that leavesthe Combined Chiller enters the suction of the Refrigerant Compressor X-1301-C-01. Within the compressor, refrigerant vapor comes in contactwith circulating synthetic lube oil, which aids compression whilelubricating and cooling the Compressor. Mechanical energy and warm oilheat the refrigerant to a temperature well above the condensing point.The compressed gas/oil mixture discharges from the Compressor to the

Oil Separator X-1301-V-02.

In the Oil Separator, the refrigerant disengages from the oil and passesoverhead through coalescing elements where entrained oil is removed.

Oil buildup from the downstream side of these elements is sent back intothe compressor suction by the lube oil pumps X-1301-P-01 A/B throughthe oil cooler X-1301-E-04 and the lube oil filters X-1301-F-02 A/B.

The refrigerant leaves the top of the Oil Separator and enters the shellside of the Refrigerant Condenser X-1301-E-06, where it condensesagainst cooling water. The lower section of the Condenser acts as arefrigerant surge capacity.

Condensed refrigerant drains from the Condenser and is cooled further inthe Subcooler X-1301-E-05, before entering the Combined Chiller. Aportion of the condensed refrigerant bypasses the Subcooler and is usedin the thermosyphon Lube Oil Cooler, which cools the lube oil for return tothe Compressor. The refrigerant from the Lube Oil Cooler is returned tothe inlet of the Refrigerant Condenser.

2.1.8.2. Net Gas Circuit

The NET GAS IN from the recycle compressor C-1301 passes throughthe Vapor Exchanger X-1301-E-02, where it is cooled by exchanging heatwith the RICH NET GAS. The RICH NET GAS then enters the vapor side


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of the Combined Chiller where it is further cooled. Some condensation ofheavier hydrocarbons occurs as the gas is cooled.

Leaving the Chiller, the RICH NET GAS enters the Absorber below tray10. Passing upward through the Absorber, the gas is contacted with the

chilled Lean Oil which absorbs hydrocarbons from the gas.The H2 rich gas (LEAN NET GAS) leaves the top of the Absorber, is thenheated in the shell side of the vapor exchanger and sent to the Net GasChloride Treaters D-132 A/B outside X-1301.

2.1.8.3. Liquid Circuit

The Lean Oil (liquid hydrocarbon from the separator D-1301) flows to theLiquid Exchangers X-1301-E-01 A/B, where it is cooled by exchangingheat with the absorber rich liquid. The lean oil then enters the liquid tubeside of the Combined Chiller where it is further cooled. Before enteringthe Absorber above tray 1.

The liquid flows counter-current, absorbing hydrocarbon from the risinggas. Leaving tray 10, the liquid accumulates in the bottom of the Absorberand is sent to the liquid exchangers X-1301-E-01A/B by the rich oil pumpsPX-1301-P-01 A/B where it is heated before being further warmed in theSubcooler.

The LPG and reformate rich stream then flows to the Debutanizer FeedBottoms Exchanger, outside X-1301.

2.1.9. Net Gas Chloride Treaters


Figure 12: Simplified PFD of the Net Gas Section

Net gas from X-1301 is fed to the net gas chloride treaters D-1302 A/B after beingmixed with reduction gas from CCR regeneration section. In D-1302 A/B the netgas flows through the absorbers in series and chloride components are removedon the beds of activated Alumina.

The Net Gas Chloride Treaters outlet gas is then separated into two streams:

•

1 stream is sent to the first stage of the NHT make up compressor suctiondrum in unit 012

• 1 stream is sent on pressure control, via 013-PV-004B to the fuel gassystem (unit 037)

2.1.10. Chemical injection

2.1.10.1. Chloride injection package X-1307

Chloride and water (condensate collected in the water break tank) areinjected into the feed stream to obtain optimum activity and selectivity ofthe catalyst.


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Chloride from storage D-1399 is injected into the feed upstream of thecombined feed exchanger E-1301 by means of the Injection Pump P-1305 (for startup) or the Chloride/Condensate Injection Pumps P-1304 A/B.

2.1.10.2. Sulfide injection package X-1396

Sulfide from sulfide storage drum D-1396 is injected via the sulfideinjection pumps P- 1306 A/B in the Feed from NHT stripper at the inlet ofthe combined exchanger E-1301.

2.1.10.3. Phosphate dosing drum X-1397

Phosphate is injected from phosphate feed drum D-1397 via thephosphate injection pump P-1397 A/B to the Steam disengaging drum D-1306.

2.1.11. Debutanizer Section


Figure 13: Simplified PFD of the Debutanizer Section

The Debutanizer is used to control the vapor pressure of the gasoline byfractionating all but a predetermined amount of C4’s (butanes) overhead. Theamount of butane left in the gasoline will help determine the vapor pressure of thegasoline.

The liquid hydrocarbon from the following streams is mixed at the inlet of theDebutanizer Feed-Bottoms Exchanger E-1306 A/B/C/D :

• Liquid from RECOVERY PLUS system (X-1301)

• Liquid from the separator (D-1301) via pumps P-1301 A/B

• Liquid from Net gas chloride treaters (D-1302 A/B) via pump P-1308(Normally no flow)

The mixed liquid is heated up against Debutanizer bottoms liquid in E-1306 A/B/C/D, and enters the Debutanizer T-1301 column above tray No. 21.

The overhead from the Debutanizer is partially condensed in the aero-condenser

E-1309 and the trim cooler E-1310 against cooling water, before reaching thedebutanizer receiver D-1303 where vapour and liquid phases are separated.

The hydrocarbon liquid is pumped from the Receiver by the DebutanizerOverhead Pumps P-1302 A/B, and split into two streams:

• One stream is returned as reflux to the Debutanizer,

• The other stream, LPG product, is sent to the LPG Chloride Treaters D-1308 A/B where it flows through the absorbers in series to remove chloridecomponents on activated Alumina beds. Treated LPG is then sent to theLPG recovery unit (LRU, 016).


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The vapor phase (C4 and lighter) leaves the receiver and is routed to the recoveryplus system.

The sour water is removed from the Receiver boot and sent to the Sour WaterStripper Unit.

The stripping vapors in the lower portion of T-1301 are provided by the steamreboiler E-1307, which uses HP steam as heating medium.

The stabilized material, so called reformate, is removed from the bottom of thedebutanizer and partially cooled in the Feed-Bottoms Exchanger E-1306 A/B/C/D.Further cooling is performed in the Debutanizer Bottoms Cooler E-1308 and TrimCooler E-1305 A/B before reformate is being sent to storage.

2.2. Regeneration Section

DRAWING TO BE INSERTED (DRAWING IN PROGRESS)Figure 14: Simplified PFD CCR Regeneration Section

Catalyst regeneration consists of 4 steps. The first three steps – coke burning,oxychlorination, and drying – occur in the Regeneration Tower T-1351. The fourth step,reduction, occurs in the Reduction Zone atop the reactor stack. A 5th step, catalystcooling, is not part of the regeneration but is required for proper catalyst transfer. Thisstep occurs in the regeneration Tower.


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Figure 15: Regeneration Section Flow Scheme

2.2.1. Spent Catalyst Transfer

DRAWING TO BE INSERTED (DRAWING IN PROGRESS)Figure 16: Simplified PFD CCR Regeneration Section (Dust Removal)

Spent catalyst flows by gravity from the bottom of the last reactor to the CatalystCollector. Catalyst flows downward into the Spent Catalyst L-Valve Assemblyagainst an upward flow of nitrogen.

At the L-Valve Asssembly, circulating nitrogen from the Lift Gas Blower C-1351engages the catalyst and lifts it through the catalyst lift line to the DisengagingHopper D-1353.


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In the Disengaging Hopper D-1353, additional circulating nitrogen from the FinesRemoval Blower B-1351 separates catalyst chips and fines from the wholecatalyst and carries them out to the top with the gas. The chips and fines areremoved in the Dust Collector A-1352 and the nitrogen circulates back to thesuction of the Fines Removal Blower B-1351 and the Lift Gas Blower C-1351.

The Whole catalyst drops to the bottom of the Disengaging Hopper D-1353, andflows by gravity into the Regeneration Tower T-1351.

The catalyst flows through and out of the Regeneration Tower by gravity.

2.2.2. Burn Zone / Reheat Zone

The burning of coke from the catalyst occurs in the Burn Zone at the top of theRegeneration tower.

Catalyst enters the regeneration towers where it flows downward between avertical, cylindrical outer-screen and an inwardly tapered inner-screen. Hotregeneration gas, containing a low concentration of oxygen, flows radially from theoutside to the inside of the catalyst bed.

Coke burning occurs as the catalyst moves down in the bed. The coke burningshould be complete when the catalyst exits the Burn Zone.

The purpose of the tapered center-screen is:

(1) To minimize the volume of catalyst behind the turn front where the catalyst isexposed to oxygen-deficient gas which is high in temperature and moisture.These are the conditions which promote catalyst surface area loss.

(2) To concentrate the flow of regeneration gas at the top of the bed where cokeburning is oxygen diffusion limited, a slower flow of gas is acceptable andresidence time is of greater importance.

The hot combustion gas mixes with the gas flowing up from the Chlorination Zone.This oxygen-rich chlorination gas supplies the oxygen for burning coke. Thecombined gases flow back to the Regeneration Blower B-1352.

The Blower B-1352 recycles the gases through the Burn Zone piping loop to thesides of the Burn zone. Part of the gases are cooled in the regeneration Cooler E-1355, which removes the heat generated by the coke burning by means of cooledair blown by the regeneration cooler blower B-1353.

Downstream of E-1355 the Regeneration Heater H-1353 operates, if heat loss inthe piping is greater than the heat of combustion, to heat the gas to the properzone inlet temperature. The products of combustion are vented at the

Regeneration Tower T-1351 inlet so as to provide a constant controlledtemperature vent gas to the downstream chloride scrubbing equipment. Part of thevent gas are also removed from the recirculation circuit and are routed to the ventgas wash tower T-1352 in which the gas are neutralized by contacting them withcaustic.

After catalyst exits the Burn Zone it enters the Reheat Zone. In this zone thecatalyst is contacted radially with hot combustion gas from the RegenerationBlower discharge B-1352. The purpose of this zone is to raise the temperature ofthe catalyst to that required in the chlorination zone.

The flow rate of the reheat gas is typically 10% of the total regeneration gas flow.


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The Reheat Zone also provides additional residence time for oxygen diffusionlimited coke combustion in case of coke breakthrough.

Figure 17: Regeneration Tower – Burn Zone

2.2.3. Chlorination Zone

Oxidizing and dispersing the metals on the catalyst, and adjusting the chloridecontent on the catalyst base occur in the Chlorination Zone.

The Chlorination Zone is located below the Burn Zone / Reheat Zone.

Catalyst enters and flows downward in a cylindrical bed defined by an annularbaffle. Hot air from the Drying Zone below flows upward into the region behind theannular baffle. At this point, vaporized organic chloride pumped by organicchloride injection pumps P-1352 A/B in the chloride injection package X-1307 isintroduced to the gas through a distributor. The resulting chlorination gas thenflows through the catalyst bed and exits into the Burn Zone.


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Figure 18: Regeneration Tower – Chlorination Zone

2.2.4. Drying Zone

Catalyst drying occurs in the Drying Zone, below the chlorination zone.

Catalyst enters and flows downward in a cylindrical bed. Hot drying gas flowsupward through the catalyst bed. The drying gas is air from the Cooling Zone

below and the instrument air Header. Both gases are dried to a very low moisturecontent in the Air Dryer A-1353 before entering the Regeneration Tower T-1351.These gases are mixed upstream the Air heater H-1354 which heats the gas tothe proper inlet temperature. The gas from the cooling zone is hot, as it has beenpreheated by exchange with hot catalyst in that zone. This preheat reduces thenet duty on the Air Heater.

From the Drying Zone the drying air splits into two streams:

• 1 entering the Chlorination Zone behind the annular baffle

• 1 exiting the Regeneration Tower and mixed to the vent gas from theelectric heater H-1353 to the vent gas wash tower.

The split depends on the amount of air needed for coke burning. The flow rate ofair that is needed for coke burning enters the chlorination Zone. Any excess airvents directly from the Regeneration Tower T-1351 on oxygen control. The air inexcess of the coke burning requirement is needed in the Drying Zone for morecomplete moisture removal in that zone.


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2.2.5. Cooling Zone

The Cooling Zone serves 2 functions, cooling the catalyst for downstreamhandling, and preheating a portion of the air to the Drying Zone.

Cooling facilitates catalyst transfer by permitting isothermal catalyst lifting.

The cooling gas is air from the Air Dryer A-1353. The Gas exits the zone andmixes with instrument air from the Air Dryer then enters the Air Heater beforegoing to the Drying Zone.

The split between air going to the Cooling Zone and air going directly to the DryingZone determines the temperature of the catalyst exiting the Regeneration TowerT-1351.



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2.2.6. Reduction Zone

Reducing the metals on the catalyst occurs in the reduction zone. The reductionzone is at the top of the Reactor Stack.

Oxidized catalyst enters the top of the zone via the regenerated catalyst lift line.The catalyst flows downward through two cylindrical beds with a gas disengagingarea between them. The catalyst exits the zone and enters the first Platformingreactor R-1301.

The reduction gas is hydrog