Fccnht Manual

OPERATING MANUAL FOR FCC NAPHTHA HYDRO TREATER UNIT,

VRCFP, HPCL VISAKH

Doc No. Draft

Rev. A

Page 1 of 187

Template No. 5-0000-0001-T2 Rev A Copyrights EIL- All rights reserved

OPERATING MANUAL

FOR

FCC NAPHTHA HYDROTREATING UNIT

VISAKH REFINERY CLEAN FUEL PROJECT

HINDUSTAN PETROLEUM CORPORATION LIMITED VISAKH

A Issued for comments

Rev No. Date Purpose Prepared by Checked by Approved by

PREFACE

This operating manual for FCC Naphtha HydroTreater Unit (Unit No.-75) of

Visakh Refinery Clean Fuel Project for HPCL Visakh Refinery has been prepared

by M/s Engineers India Limited for M/s Hindustan Petroleum Corporation Limited.

The objective of FCC Naphtha Hydrotreating Unit is to process FCC

Gasoline to obtain product streams (Light gasoline and Heavy Hydrotreated

gasoline) with targeted qualities of octane number, sulphur content, benzene

content and olefins content. This manual contains process description and operating guidelines for the unit and is based on documents supplied by the Process Licensor (Axens). Hence the manual must be reviewed /approved by the licensor before the start-up /operation of the unit. Operating

procedures & conditions given in this manual are indicative. These should be

treated as general guide only for routine start-up and operation of the unit. The

actual operating parameters and procedures may require minor

modifications/changes from those contained in this manual as more experience is

gained in operation of the Plant.

For detailed specifications and operating procedures of specific equipment,

corresponding Vendor's operating manuals/instructions need to be referred in

addition to Process Package and Design Basis.

List Of Abbreviations, Definitions and Legend

TABLE OF CONTENTS

SECTION- 1 INTRODUCTION..................................................................................................................................9

1.1 INTRODUCTION.....................................................................................................................................................10

1.2 UNIT CAPACITY...................................................................................................................................................10

1.3 ON-STREAM FACTOR............................................................................................................................................10

1.4 TURNDOWN RATIO...............................................................................................................................................10

1.5 FEED CHARACTERISTICS......................................................................................................................................10

1.5.1 FCC Gasoline 10

1.5.2 Sulfur Distribution (ppm wt)*....................................................................................................................11

1.5.3 Hydrogen 12

1.5.4 Lean Amine 13

1.5.5 Start-up inert naphtha 13

1.6 PRODUCTS SPECIFICATION...................................................................................................................................14

1.6.1 Light FCC gasoline: 14

1.6.2 Heavy desulfurized FCC gasoline.............................................................................................................15

1.6.3 Benzene Heartcut 15

1.6.4 Splitter purge gas 17

1.6.5 Selective HDS purge 17

1.6.6 Rich Amine 17

1.6.7 Stabilizer purge 18

1.7 PROPOSED TREATMENT SCHEME..............................................................................................................18

1.8 BATTERY LIMIT CONDITIONS OF PROCESS LINES................................................................................................19

1.9 MATERIAL BALANCES..........................................................................................................................................20

1.9.1 SHU section overall balance.....................................................................................................................20

1.9.2 HDS section overall balance.....................................................................................................................20

1.10 SPECIFICATIONS OF CATALYSTS AND CHEMICALS..........................................................................................21

1.10.1 Catalyst 21

1.10.2 Catalyst Bed Protections 22

1.10.3 Inert balls 23

1.10.4 Chemicals 24

1.11 UTILITY CONDITION AT UNIT BATTERY LIMIT.................................................................................25

1.12 UTILITY SPECIFICATION:.........................................................................................................................27

1.13 INTERMITTENT UTILITY CONSUMPTION...........................................................................................................28

1.13.1 Start-up requirement 28

1.13.2 Catalyst in-situ regeneration.....................................................................................................................30

1.14 EFFLUENT SUMMARY:.....................................................................................................................................31

SECTION- 2 PROCESS DESCRIPTION...............................................................................................................33

2.1 UNIT DESCRIPTION...............................................................................................................................................34

2.2 SELECTIVE HYDROGENATION..............................................................................................................................34

2.3 SPLITTER SECTION...............................................................................................................................................35

2.4 HDS SECTION.......................................................................................................................................................36

2.5 RECYCLE COMPRESSOR SECTION.........................................................................................................................37

2.6 STABILIZER SECTION........................................................................................................................................37

2.7 CATALYST IN-SITU REGENERATION OPERATION..................................................................................................38

SECTION- 3 PROCESS PRINCIPLE.....................................................................................................................40

3.1 PURPOSE OF THE PROCESS...................................................................................................................................41

3.2 GENERAL.............................................................................................................................................................41

3.3 SELECTIVE HYDROGENATION REACTOR (75-R-01)..............................................................................................41

3.4 SPLITTER (75-C-01).............................................................................................................................................42

3.5 FIRST HDS REACTOR (75-R-02)..........................................................................................................................43

3.6 CHEMICAL REACTIONS AND CATALYST..............................................................................................................43

3.6.1 Objective 43

3.6.2 Thermodynamics and kinetics....................................................................................................................44

3.6.3 Catalyst activity, selectivity AND stability................................................................................................44

3.6.4 Selective hydrogenation Reactions and Catalyst.......................................................................................45

3.6.5 Chemical reactions 45

3.6.6 Hydrogenation of diolefins 45

3.6.7 Isomerization of olefins 47

3.6.8 Hydrogenation of olefins 47

3.6.9 Thermal and catalytic polymerization of unstable compounds.................................................................47

3.6.10 Thermodynamic and kinetic analysis.........................................................................................................47

3.6.11 Sulfur reaction 48

3.7 PROCESS VARIABLES IN SELECTIVE HYDROGENATION............................................................................49

3.7.1 Reactor Temperature 49

3.7.2 Residence time in the reactor.....................................................................................................................50

3.7.3 Reactor pressure 50

3.7.4 Hydrogen make-up rate 51

3.8 CHEMICAL: HDS REACTOR REACTIONS AND CATALYST....................................................................................51

3.8.1 Chemical reactions 51

3.8.2 Hydrorefining 52

3.8.3 Hydrogenation of olefins 53

3.9 RELATIVE RATES OF REACTION...........................................................................................................................54

3.9.1 Process variables in hds reactor...............................................................................................................54

3.9.2 Temperature 54

3.9.3 Operating pressure and H2/HC ratio........................................................................................................55

3.9.4 Space velocity 56

SECTION- 4 UTILITY DESCRIPTION.................................................................................................................57

4.1 INTRODUCTION...............................................................................................................................................57

4.1.1 INSTRUMENT AIR SYSTEM.....................................................................................................................58

4.1.2 PLANT AIR SYSTEM 58

4.1.3 SEA COOLING WATER SYSTEM.............................................................................................................58

4.1.4 BEARING COOLING WATER SYSTEM..................................................................................................59

4.1.5 SERVIC WATER SYSTEM 59

4.1.6 NITROGEN 60

4.1.7 LP STEAM SYSTEM 60

4.1.8 MP STEAM SYSTEM 60

4.1.9 VHP STEAM SYSTEM 61

4.1.10 FUEL GAS SYSTEM 61

4.2 EFFLUENT SYSTEM........................................................................................................................................61

SECTION- 5 PREPARATION FOR START-UP...................................................................................................63

5.1 GENERAL..........................................................................................................................................................64

5.2 PRE-COMMISSIONING ACTIVITIES.............................................................................................................64

5.2.1 Inspection / Checking 65

5.2.2 Inspection of equipments 65

5.2.3 Piping and Accessories 66

5.2.4 Instruments 66

5.2.5 Relief Valves 66

5.2.6 Rotary Equipment 66

5.2.7 Drainage System 66

5.3 PREPARATION FOR PRE-COMMISSIONING............................................................................................................67

5.4 PRE-COMMISSIONING...........................................................................................................................................67

5.4.1 Commissioning of Utilities 68

5.4.2 Final Inspection of Vessels 70

5.4.3 Pressure Test Equipment 70

5.4.4 Wash Out Lines and Equipment.................................................................................................................72

5.4.5 Functional Test of Rotating Equipment.....................................................................................................73

5.5 INSTRUMENTS CHECKING.....................................................................................................................................76

5.6 SAFETY DEVICES CHECK......................................................................................................................................78

5.7 HEATER REFRACTORY DRY-OUT AND REACTION SECTION DRY-OUT..................................................................78

5.8 PURGING AND GAS BLANKETING........................................................................................................................78

5.9 TIGHTNESS TEST..................................................................................................................................................80

5.10 CATALYST LOADING PROCEDURE....................................................................................................................82

5.11 CATALYST SPECIAL PROCEDURE......................................................................................................................82

SECTION- 6 START-UP PROCEDURE................................................................................................................84

6.1 INTRODUCTION...............................................................................................................................................84

6.2 PRE-START-UP CHECKLIST FOR PRIME G+ UNIT.............................................................................................85

6.3 FIRST START-UP...................................................................................................................................................86

6.3.1 Chronology of start-up operations............................................................................................................87

6.3.2 Purging of air 87

6.4 START-UP PRELIMINARY OPERATION...................................................................................................................90

6.4.1 Unit status 90

6.4.2 Inert naphtha circulation (Reaction sections by-passed)..........................................................................91

6.4.3 Start-up of Hot Naphtha circulation in splitter and stabilizer...................................................................94

6.5 PRESSURIZATION OF THE REACTION SECTIONS AND HYDROGEN LEAK TESTS.....................................................95

6.5.1 Unit status 95

6.5.2 H2 inroduction in SHU section..................................................................................................................96

6.5.3 H2 inroduction in HDS section..................................................................................................................96

6.6 CATALYST SULFIDING – DRY SULPHIDING.........................................................................................................97

6.6.1 Sulfiding of HR-845 Catalyst in the Diolefin Reactor (75-R-01)..............................................................98

6.6.2 Sulfiding of HR-806 Catalyst of first HDS Reactor (75-R-02)..................................................................98

6.6.3 Sulphiding Procedure 98

6.7 UNIT START-UP.................................................................................................................................................100

6.7.1 UNIT Status 100

6.7.2 Lining up of the SHU reaction section.....................................................................................................101

6.7.3 Lining up of the HDS reaction section.....................................................................................................102

6.7.4 Inert naphtha circulation 103

6.7.5 FCC Gasoline Feed 104

SECTION- 7 NORMAL OPERATING PROCEDURE.......................................................................................107

7.1 GUIDELINES FOR NORMAL OPERATION................................................................................................107

7.2 INTRODUCTION.............................................................................................................................................107

7.3 OPERATING PARAMETER...........................................................................................................................108

7.4 ALARMS:.........................................................................................................................................................115

7.5 OPEARATING CONDITIONS OF DIFFERENT CASES OF OPERATION................................................119

7.6 EQUIPMENT LIST..........................................................................................................................................120

7.6.1 Pumps 120

7.6.2 Vessels 120

7.6.3 Columns 121

7.6.4 Reactors 121

7.6.5 Heat Exchangers(Tubular) 122

7.7 LIST OF INSTRUMENTS...............................................................................................................................123

7.7.1 Control Valves: 123

7.7.2 ON-OFF Valves 125

7.7.3 Safety valves 126

7.8 RELIEVE VALVE LOAD SUMMARY..........................................................................................................128

7.9 DETAIL OF INTERLOCK LOGIC AND TRIPS............................................................................................128

7.10 EFFECT OF OPERATING VARIABLES ON THE PROCESS...................................................................................133

7.10.1 Operating parameters 133

7.10.2 Reactor temperature 133

7.10.3 other parameter 135

7.10.4 Make-up H2 and recycle H2 flow-rates....................................................................................................136

7.10.5 Space velocity (feed rate) 138

7.10.6 Feed quality 139

SECTION- 8 SHUTDOWN PROCEDURES........................................................................................................141

8.1 NORMAL SHUTDOWN PROCEDURE.........................................................................................................142

8.1.1 introduction 142

8.1.2 Preparations for a Planned Shutdown.....................................................................................................142

8.1.3 General procedure 143

8.1.4 Short period shutdown 143

8.1.5 Long period shutdown 145

8.1.6 Shutdown followed by maintenance, inspection or catalyst unloading...................................................146

8.2 UNIT RESTART....................................................................................................................................................148

SECTION- 9 EMERGENCY SHUTDOWN PROCEDURE...............................................................................150

9.1 EMERGENCY SHUTDOWN PROCEDURE.................................................................................................151

9.1.1 general 151

9.1.2 Emergency shutdown by operators..........................................................................................................151

9.1.3 Loss of feed 153

9.1.4 Loss of cooling water 155

9.1.5 Lack of hydrogen make-up 155

9.1.6 Loss of Amine 155

9.1.7 Quench pump failure 155

9.1.8 Fuel gas failure 156

9.1.9 Steam failure 156

9.1.10 Instrument air failure 156

9.1.11 Power failure 156

9.1.12 Fire or major leak 157

9.1.13 Automatic emergency shutdown..............................................................................................................158

SECTION- 10 TROUBLE SHOOTING..................................................................................................................160

10.1 TROUBLE SHOOTING..............................................................................................................................161

10.1.1 High differential pressure (DP) in the reactor.........................................................................................161

10.1.2 Chemical H2 consumption increase........................................................................................................161

10.1.3 Octane losses 162

SECTION- 11 SAMPLING PROCEDURE AND LABORATORY ANALYSIS................................................163

11.1 GENERAL....................................................................................................................................................164

11.2 SAMPLING PROCEDURE.........................................................................................................................164

SECTION- 12 SAFETY PROCEDURE..................................................................................................................170

12.1 INTRODUCTION........................................................................................................................................171

12.2 PLANT SAFETY FEATURES.............................................................................................................................171

12.2.1 General 171

12.2.2 Emergency shutdown 171

12.2.3 Overpressure protection 171

12.2.4 Safety shower and eye wash.....................................................................................................................172

12.2.5 Operational safety stations 172

12.2.6 High pressure 172

12.2.7 Reactor protection 172

12.2.8 Personnel protection 172

12.3 SAFETY OF PERSONNEL.........................................................................................................................175

12.4 WORK PERMIT PROCEDURE..................................................................................................................176

12.5 PREPARATION OF EQUIPMENT FOR MAINTENANCE.....................................................................178

12.6 PREPARATION FOR VESSEL ENTRY....................................................................................................180

12.6.1 General procedure 180

12.6.2 Preparation of Vessel Entry Permit.........................................................................................................184

12.6.3 Checkout Prior to New Unit Start-up......................................................................................................184

12.6.4 Inspections during Turnarounds..............................................................................................................185

12.7 FIRE FIGHTING SYSTEM.........................................................................................................................186

12.7.1 Use of life saving device 187

SECTION- 13 GENERAL OPERATING INSTRUCTIONS FOR EQUIPMENT.............................................189

13.1 GENERAL....................................................................................................................................................190

13.2 CENTRIFUGAL PUMPS............................................................................................................................190

13.3 HEAT EXCHANGERS................................................................................................................................193

13.3.1 General 193

13.3.2 Air coolers 193

13.3.3 Exchangers 193

SECTION- 1 INTRODUCTION

1.1 INTRODUCTIONHindustan Petroleum Corporation Limited (HPCL), Visakh is in the process of

augmenting the capacity of the existing refinery by revamping the existing

primary units and installing additional facilities required to meet the product

specifications.

The objective of this Unit is to process FCC gasoline to produce a blend of two

streams (LCN+HCN), Maximise the octane number while meeting pool

specifications in term of sulphur content, benzene content and olefins content.

Three different feeds considered for the design of the FCC Naphtha Hydrotreater

unit: are NITCASE, AM (Arab Mix) CASE, BH (Bombay High) CASE

1.2 UNIT CAPACITYThe unit capacity is 893 330 T/yr for all three cases

1.3 ON-STREAM FACTORThe unit is designed for a stream factor of 8000 hours/annum.

1.4 TURNDOWN RATIOThe unit is capable of a turndown of 50% of hydrocarbon flow.

1.5 FEED CHARACTERISTICSThree operating cases, AM CASE, BH CASE and NIT CASE are selected for the

design of the unit.

1.5.1 FCC GASOLINE:

CharacteristicsAMCASE

BHCASE

NITCASE

Max Available Rate, t/hr 111 666 111 666 111 666

CharacteristicsAMCASE

BHCASE

NITCASE

St m3/hr 152.3 156.0 152.8

Density at 15°C, g/cc 0.7334 0.716 0.731

Total Sulfur, wppm / RSH 2400/720 180/90 1133/229

RON 93 93 91.4

MON 80.6 81.6 81.2

PONA (vol %)

Paraffins, vol % 29.5 29.2 24.35

Olefins, vol %

(Diolefins wt %)

35.5

(2.0)

38.5

(2.0)

54.47

(2.0)

Naphthenes, vol % 10.7 10.3 7.01

Aromatics, vol %

(Benzene, vol%)

24.3

(1.8)

22.0

(1.9)

14.17

(0.38)

Distillation (ASTM-D86), °C

IBP 46.1 46.1 40

10 % vol 56.1 56.1 57.6

30 % vol 75.5 75.5 70.6

50 % vol 95.5 95.5 92

70 % vol 124.4 124.4 123.2

90 % vol 155 155 156.4

95 % vol 167.7 167.7 168.2

FBP 180 180 187

1.5.2 SULFUR DISTRIBUTION (PPM WT)*

Sulphur componentsAM case (ppm wt)

BH case (ppm wt)

NIT case (ppm wt)

Methyl mercaptan 0.5 0.5 0.5

Ethyl mercaptan 200 25 118

C3 mercaptan 138 17 81



C6+ mercaptan 97 12 5

Carbonyle disulfide 0.5 0.1 0.5

Dimethyl sulfide 2 0.2 1

Sulphur componentsAM case (ppm wt)

BH case (ppm wt)

NIT case (ppm wt)

Methyl ethyl sulfide 2.0 0.2 1.0

Methyl-t-butyl sulfide 5 0.5 3

Thiophene 236 12 100

C1 thiophene 360 24 200

Tetra hydro thiophene 51 5 20.0

C2 thiophene 262 12 128

C3+ thiophene and

benzothiophenes

773 37 451

Total 2400 180 1133

(*) Assumed from Axens data bank

1.5.3 HYDROGEN

Components / Origin Hydrogen from CCR Start-up H2

H2, mol%

C1, mol%

C2, mol%

C3, mol%

iC4, mol%

nC4

C5+, mol%

Total

93.0 99.9

2.3

2.2

1.7 balance

0.3.

0.3

0.2

100 100

Origin: Normal Start-up

Impurities: H2S 5ppm vol max Nil

HCl 0.5 ppm vol max 1 ppm vol max

CO 6-10 ppm vol max 1 ppm vol max

COS 1 ppm vol max

Others: CO+CO2 25 ppm vol max 20 ppm vol max

Water: 30-35 ppm vol 50 ppm vol max

Olefins: 10 ppm wt

Nitrogen: 1 ppm wt

1.5.4 LEAN AMINE

Properties / Case All cases

Type

Rate, kg/h

Amine Content, % wt

Loading, mol H2S/mol amine

Di-EthanolAmine (DEA)

10 000

25

Lean Amine : 0.03

Rich Amine: 0.33 max.

1.5.5 START-UP INERT NAPHTHAFor start-up, inert naphtha is required to perform naphtha circulation in the unit and to put

the unit at SOR temperatures. This naphtha should have the following properties.

Start-up Inert Naphtha Specification

Sulfur components Estimated Required

Volume, m3

Bromine Number, gBr/100g

Diene Value

Specific Gravity

D86 5%vol, °C

D86 95%vol, °C

2 x unit volume

< 5

< 0.5

between 0.725 and 0.850

between 5 and 70

between 145 and 225

ASTM as close as possible to the cracked feed.

Typically, straight run naphtha coming from the crude distillation unit is used.

1.6 PRODUCTS SPECIFICATION

1.6.1 LIGHT FCC GASOLINE:

CharacteristicsNITCASE

AMCASE

BHCASE

Max Available Rate, t/hr 49027 32000 32000

ST m3/hr 73.8 49.0 49.5

Density at 15°C, g/cc 664 654 647

MW, kg/kmol 74.3 74.1 73.9

Sulfur, wppm 240 270 15

RON (estimated) 94.6 94 94

MON (estimated) 81.8 81.1 82

RVP (kpa) 100 120 122

PONA (vol %)

Paraffins, vol % 34.4 52.2 50.7

Olefins, vol %

(Diene Value)

61.2

(0.0)

43.2

(0.0)

45.5

(0.0)


Aromatics, vol %

(Benzene, vol%)

0.8

(0.76)

2.13

(2.13)

2.1

(2.1)

Distillation(ASTM D86),°C

ssCCCCCCxxCCC868686)86),°C

simulated simulated simulated

IBP 24.5 19.0 18.8

5 % vol 39.1 33.4 33.2

10 % vol 41.2 34.6 34.4

30 % vol 45.9 37.0 36.8

50 % vol 55.3 40.4 40.1

70 % vol 61.7 46.7 44.8

90 % vol 73.3 64.4 63.8

95 % vol 77.8 69.4 68.4

FBP 84.1 77.1 75.5

1.6.2 HEAVY DESULFURIZED FCC GASOLINE


AMCASE

BHCASE

Max Available Rate, t/hr 62468 63188 64350


AMCASE

BHCASE

St m3/hr 78./8 79.6 83.8

Density at 15°C, g/cc 793.2 793.5 767.9

MW, kg/kmol 115 114.5 116.4

Sulfur, wppm 10 200 290

RON (estimated) 75.3 88.1 92.8

MON (estimated) 74.3 78.4 81.7

RVP (kpa) 6 6 6

PONA (vol %)

Paraffins, vol % 62.6 25.0 16.5

Olefins, vol %

(Diene Value)

1.0

(0.0)

15.3

(0.0)

28.7

(0.0)


Aromatics, vol %

(Benzene, vol%)

26.5 43.4

(0.43)

38.2

(0.47)

Distillation(ASTM D86),°C simulated simulated simulated

IBP 106.0 75.2 104.7

5 % vol 112.0 111.8 110.8

10 % vol 114.9 115.0 113.6

30 % vol 125.6 125.7 124.2

50 % vol 137.2 137.3 136.2

70 % vol 149.8 149.5 148.8

90 % vol 170.7 167.2 166.9

95 % vol 178.6 173.6 173.4

FBP 182.9 178.2 178.0

1.6.3 BENZENE HEARTCUTIn order to meet the 0.9% vol benzene content in the gasoline pool in case of any

benzene upset in the feed (up to 1.9 vol %). This heart-cut is not used during normal

operation. The heart-cut properties are presented in the table hereafter.


AMCASE

BHCASE

Max Available Rate, t/hr N A 16000 15000

St m3/hr N A 23.1 22.4

Density at 15°C, g/cc N A 691.6 671.0


AMCASE

BHCASE

MW, kg/kmol N A 85.4 85.4

Sulfur, wppm N A 1116 64

PONA (vol %)

Paraffins, vol % N A 36.5 33.0

Olefins, vol %

(Diene Value)

N A 46.5

(0.0)

51.7

(0.0)

Naphthenes, vol % N A 10.9 8.4

Aromatics, vol %

(Benzene, vol%)

N A 6.2

(5.8)

6.93

(6.85)

Distillation(ASTM D86),°C simulated simulated

IBP N A 45.7 45.2

5 % vol N A 51.8 51.6

10 % vol N A 54.3 54.3

30 % vol N A 72.3 71.6

50 % vol N A 77.3 76.2

70 % vol N A 81.5 80.0

90 % vol N A 88.2 85.4

95 % vol N A 91.9 88.7

FBP 99.1 94.6

1.6.4 SPLITTER PURGE GASThe splitter purge has the following estimated properties. Refer to stream 16 in material

balances for detailed composition, and other physical properties

Case NIT CASE AM CASE BH CASE

Splitter Purge SOR EOR SOR EOR SOR EOR


Rate, kg/h

H2, %mol

C1 to C4, %mol

C5+, %mol

648

46.3

35.3

18.4

1039

53.5

27.1

19.4

537

47.4

36.9

15.7

866

54.4

28.7

16.9

562

46.4

38.4

15.2

905

53.5

30.3

16.2

1.6.5 SELECTIVE HDS PURGEThe selective HDS purge has the following estimated properties. Refer to stream 37 in

material balances for detailed composition, and other physical properties. In normal

operation, this purge is closed.

Case NIT CASE AMCASE BH CASE

HP Purge SOR EOR SOR EOR SOR EOR

Rate, kg/h

H2, %mol

H2S, ppm mol

C1 to C4, %mol

C5+, %mol

216

88.4

6510

10.6

0.35

216

88.4

6510

10.6

0.35

56

91.1

32

7.7

1.2

56

91.1

32

7.7

1.2

NA

NA

NA

NA

NA

NA

NA

NA

NA

NA

1.6.6 RICH AMINEThe rich amine has the following estimated properties. Refer to stream 44 in material

balances for detailed composition, and other physical properties.


Rich amine SOR EOR SOR EOR SOR EOR

Rate, kg/h

DEA, % mol

Loading,

mol H2S / mol

DEA

NA

NA

NA

NA

NA

NA

10124

5.38

0.25

10124

5.38

0.25

NA

NA

NA

NA

NA

NA

1.6.7 STABILIZER PURGEThe Stabilizer purge has the following estimated properties. Refer to stream 51 in

material balances for detailed composition, and other physical properties.


Stabilizer Purge SOR EOR SOR EOR SOR EOR

Rate, kg/h

H2, % mol

H2S, % mol

C1 to C4, % mol

C5+, % mol

855

23.3

11.2

60.4

5.1

854

23.2

11.2

60.4

5.2

428

30.4

12.4

51.3

5.9

428

30.4

12.4

51.3

5.9

NA

NA

NA

NA

NA

NA

NA

NA

NA

NA

1.7 PROPOSED TREATMENT SCHEMEThe processing block comprise following system:

The Selective Hydrogenation facilities on the FCC gasoline consist:

A FCC gasoline splitter to produce a partially de-sulfurized Light FCC gasoline

and a Heavy FCC gasoline.

The PRIME G+ Selective Hydrodesulphurization of Heavy FCC gasoline.

The desired product streams from the block are a light partially desulfurized

FCC cut and a heavy desulfurized gasoline stream, which should be of the

required quality to meet the pool specifications.

The basic design utilizes Axens’ Prime G+ technology. Prime G+ is a process for

hydrodesulfurization of cracked gasoline, which includes the following major unit

sections:

Selective Hydrogenation and Splitter Section

Selective HDS and Stabilizer Section

The unit 75 produces:

A partially desulfurized and sweet light FCC cut, routed to the MS pool

A desulfurized heavy FCC cut, routed to the MS pool

1.8 BATTERY LIMIT CONDITIONS OF PROCESS LINES

Streams Pressure kg/cm²g

Temperature °C

Feeds: FCC gasoline

FCC gasoline from storage

6.0

6.0

70

40

Lean amine 20.4 40

H2 Make-up Normal operation

From CCR

Start-up

39.0 (*)

22.0 (**)

20.0

40

40

45

Product(s): Light FCC gasoline

FCC heart cut

Desulfurized heavy FCC gasoline

7.0

7.0

7.0

40

40

40

Rich amine 2.4 47

Gas purges

Splitter purge 4.5 40

Selective HDS HP purge

NIT Case

AM Case

5.5

4.5

40

40

Stabiliser purge 5.0 40

(*) At Isomerization H2 make-up compressor discharge on unit 73.

(**) When isomerization compressor is shut down

1.9 MATERIAL BALANCES

1.9.1 SHU SECTION OVERALL BALANCE

Case AM CASE BH CASE MIX CASE

SOR EOR SOR EOR SOR EOR

Feeds kg/hr

FCC gasoline 111 666 111 666 111 666 111 666 111 666 111 666

H2 make-up 277 323 244 284 245 286

TOTAL 111 943 111 989 111 910 111 950 111 911 111 952



Products kg/hr

Splitter purge 648 1039 537 866 562 905

Light gasoline 49 027 49 027 32 000 32 000 32 000 32 000

Heart cut gasoline NA NA 16 000 16 000 15 000 15 000

Heavy gasoline 62 268 61 923 63 373 63 084 64 350 64 047

TOTAL 111 943 111 989 111 910 111 950 111 912 111 952

1.9.2 HDS SECTION OVERALL BALANCE



Feeds kg/hr

Heavy gasoline 62 268 61 923 63 373 63 084 NA NA

H2 make-up 1271 1270 470 469 NA NA

Lean Amine - - 10 000 10 000 NA NA

TOTAL 63 539 63 193 73 843 73 553 NA NA

Products kg/hr

Separator purge 216 216 56 56 NA NA

Stabilizer off-gas 855 854 428 428 NA NA

Heavy hydroteated

gasoline

62 468 62 123 63 189 62 899 NA NA

Separator drum sour

water

- - 35 35 NA NA

Stabilizer reflux drum

sour water

- - 11 11 NA NA

Rich amine - - 10 124 10 124 NA NA

TOTAL 63 539 63 193 73 843 73 553 NA NA

1.10 SPECIFICATIONS OF CATALYSTS AND CHEMICALS1.10.1 CATALYST

HR 845

Relevant to

Trade mark

Presentation

Estimated cycle length

Estimated life time

Loaded catalyst volume

Selective Hydrogenation Reactor, 75-R-01

HR 845, manufactured by :

Axens Procatalyse Catalysts & AdsorbentsSpheres, diameter 3mm (2 to 4mm)

Refer (1)

Refer (1)

38.2 m3, Refer (2), (3)

(1) Catalyst cycle length and estimated life time is different for each case:

NIT CASE : Estimated cycle life = 3 years, Estimated life time = 5 years

AM CASE : Estimated cycle life = 1.5 years, Estimated life time = 2.5 years

BH CASE : Estimated cycle life = 3 years, Estimated life time = 5 years

These cycle length and life duration are defined at iso-capacity (111 666 kg/hr)

(2) The 75-R-01 is designed to have some provision in the reactor for a future

loading. Additional catalyst amount will 49.7 m3 allow to increase catalyst cycle life

and life time for AM CASE feed.

AM CASE : Estimated cycle life = 3 years, Estimated life time = 5 years

(3) Sock catalyst loading method

HR 806

Relevant to

Trade mark

Presentation

Estimated cycle length

Estimated life time


First HDS reactor, 75-R-02

HR 806, manufactured by :

Axens Procatalyse Catalysts & AdsorbentsSpheres, diameter 3mm (2 to 4mm)

Refer (1)

Refer (1)

23.9 m3 refer (2), (3)

(1) Catalyst cycle length and estimated life time is different for each case:

NIT CASE : Estimated cycle life = 3 years, Estimated life time = 5 years

AM CASE : Estimated cycle life = 1.5 years, Estimated life time = 2.5 years

These cycle length and life duration were defined at iso-capacity (111 666 kg/hr)

(2) The 75-R-02 was designed to have some provision in the reactor for a future

loading. Additional catalyst amount will be 38.2 m3 allowing to increase catalyst

cycle life and life time for AM CASE feed.

AM CASE : Estimated cycle life = 3 years, Estimated life time = 5 years

(3) Sock loading catalyst method

1.10.2 CATALYST BED PROTECTIONS

Details Total Requirements for Reactors (75-R-01 & 75-R-02)

Material ACT-068 (Inert Alumina)

Supplier Axens Procatalyse Catalysts & Adsorbents.

Shape Penta rings extrudates

Outside Diameter 25 mm

Loading density 880 kg/m3 (1)

Loaded Volume 0.25 m3



Shape Fluted ring




Material ACT-108 (Inert Ceramic)


Shape Hollow cylinder


Loading density 900 kg/m3




Shape Sphere




1.10.3 INERT BALLS¾ inch inert balls

Relevant to

Presentation

Loading density

Loaded catalyst volume (1)


HDS Reactor ,75-R-02

Sphere, diameter 19mm (17 to 23mm)

1350 kg/m3

4.72 m3

(1) The volume specified for inert balls ¾” does not include inert balls volume

occupied by unloading catalyst nozzles.

¼ inch inert balls

Relevant to

Presentation

Loading density



HDS Reactor, 75-R-02

Sphere, diameter 6.3mm (6.0 to 8.2mm)

1400 kg/m3

29.7 m3 (1)

(1) This amount of inert balls is defined for catalyst future loading provision.

1.10.4 CHEMICALS

1.10.4.1 Chemical during normal operation - Corrosion inhibitor agentThe corrosion inhibitor agent is injected and diluted at 10% Wt in desulfurized

heavy naphtha. Once injected in process unit, the corrosion inhibitor is at 10 ppm

wt of process stream.

Type : CHIMEC 1044

Estimated consumption : 832 kg/year

See also enclosed CHIMEC 1044 technical datasheet.

1.10.4.2 Chemical during transient operation – sulfiding agentThe sulfiding agent is injected at reactor inlets during start-up (first start-up and

after in-situ catalyst regeneration) in order to sulfurize the catalyst. It shall be

injected pure.

Type : DI-METHYL DI-SULFIDE, DMDS

DMDS shall be injected during two 12-hours (max 18-hours) period. Reactor

sulfiding is done one by one.

Estimated consumption for initial catalyst loading:

o 75-R-01 : 4620 kg

o 75-R-02 : 1290 kg

Estimated consumption for future catalyst loading:

o 75-R-01 : 6012 kg

o 75-R-02 : 2061 kg

1.11 UTILITY CONDITION AT UNIT BATTERY LIMIT

Stream Steam and condensatePressure(kg/cm2g)

Temperature(deg.C)

Very High Pressure

(From CCR unit)

Minimum (for thermal

design):

33 340

Normal 35 360

Maximum 38 380

Mechanical design: 40 400

Medium pressure Minimum (for thermal

design):

9 Saturated.

Normal: 10 250

Maximum: 11 280

Mechanical design: 12.5 300

Low pressure Minimum (for thermal

design):

2.5 saturated

Normal: 3.0 150

Maximum: 4.0 170


Normal: 5.5 100


Temperature(deg.C)

Steam condensate (HP

and HP steam)


Cooling water Supply Minimum: - -

Normal 5.3 33

Maximum: - -


Cooling water Return Minimum pressure required

for return:

3.5 44

Maximum temperature for

return:

- -

Mechanical Design 7.6 65

Boiler feed water

(VHP/HP)

Minimum: 47/17.5 120/120

Normal: 50/20.5 120/120

Maximum: - -

Mechanical Design: 71/29 155/155

Demineralised water Minimum: - -

Normal: 3.0 Ambient

Maximum: - -

Mechanical Design: 9.0 65

Plant air (oil-free and

water for catalyst

regeneration)

Minimum: 3.0

Normal: 4.0 Ambient

Maximum: 5.0


Instrument air Minimum: 4.0

Normal: 5.0 Ambient

Maximum: 6.0


Nitrogen Minimum: 5.0

Normal: 6.0 Ambient

Maximum: 7.0


Fuel gas Minimum: 2.5 30

Normal: 3.0 40-50

Maximum: 3.5 60


Temperature(deg.C)


Fuel oil Minimum: 7.0 100

Normal: 8.0 130

Maximum: 11 170


1.12 UTILITY SPECIFICATION:1. NITROGEN QUALITY:

Nitrogen 99.99 % vol. min

Dew point at atm. pressure -100 deg C

CO traces

CO2 <3 vol ppm max

Oil content <3 vol ppm max

Oxygen <3 vol ppm max

2. FLARE HEADER PRESSURE:

Built up Back-Pressure (kg/cm2g)

Superimposed Back-pressure at BL (kg/cm2g)

Total Back-pressure at PSV outlet (kg/cm2g)

Normal Flare 0.1 1.5 1.7

Acid Gas Flare 0.1 1.5 1.7

3. BOILER FEED WATER

pH – 8.5-9.5

Cation conductivity @ 25 0C (micromho/cm) - <5

Hardness (CaCo3) (mg/l) – Nil

Dissolved Oxygen (mg/l) – 0.007

Copper (mg/l) – Nil

Total Fe (mg/l) – 0.03

Total SiO2 (mg/l) - <0.05

KMnO4 Value @ 100 0C mg/l) - <5

4. DM WATERpH – 6.7-7.3

Cation conductivity @ 25 0C (micromho/cm) – 1-2

Hardness (CaCo3) (mg/l) – Nil

Turbidity (NTU) – Nil

Copper (mg/l) – Nil

Total Fe (mg/l) – <0.03

Total SiO2 (mg/l) - <0.05

KMnO4 Value @ 100 0C mg/l) - <5

5. BEARING COOLING WATER

pH – 7.5-8.0

Hardness (CaCo3) (mg/l) – 140-210

Turbidity (NTU) – 20-30 (max 50)

Total dissolved solids (mg/l) – 875-1300

M. Alkalinity (mg/l) – 100-120

Chlorides as Cl (mg/l) – 225-335

Sulphates as SO4 (mg/l) – 205-466

Organophospahtes as PO4 (mg/l) – 8-10

Total Fe (mg/l) – 1 (max)

KMnO4 Value @ 100 0C mg/l) – 30-40 (Max 50)

Oil content (mg/l) – 10 (max)

Zinc Sulphate as Zn (mg/l) – 1-2

1.12 INTERMITTENT UTILITY CONSUMPTION1.12.1 START-UP REQUIREMENT

The estimated consumption is based on a normal start-up sequence. Intermittent

operation can be assumed to occur once every 3 years.

V1=100 m3 is the estimated volume of the SHU reaction section

V2=260 m3 is the estimated volume of the HDS reaction section

The overall volume V is considered for utility consumption is 360 m3.

a) Start-up instrument airThe instrument air is used for tightness test after catalyst loading:

Estimated consumption: 6 V (2160 Nm3)

b) Start-up nitrogenNitrogen gas is required for start-up and shutdown periods in order to free the

unit of any oxygen or hydrocarbons.

Unit pressurization: 8 V

Catalyst drying: 15 V (max)

Unit purge: 3 V

Total: 26 V (= 8280 Nm3)

Note: Minimum required nitrogen quality (content by volume)

O2 : 5 ppm max

H2O : 5 ppm max

Carbon compounds : 5ppm max

H2 : 20 ppm max

CO : 20 ppm max

CO2 : 20 ppm max

Chlorine : 1 ppm max

N2 : 99.7 % vol min.

c) Start-up hydrogen

Unit pressurization: 20 V

Unit purge: 10 V

Total: 30 V

Total in Nm3: 10 800 Nm3

Note: Minimum required quality (content by volume) :H2 : 95 % min.

C1 : 5% max.

C2+ : 0.5% max.

CO : 20 ppm max.

CO2 : 100 ppm max.

O2 : 100 ppm max.

H2S : 1 ppm max

d) Start-up steamLP Steam: LP Steam will also be used during start-up to inertise other equipments by

steam out.

e) Start-up inert naphthaEstimated required volume 360 m3

1.12.2 CATALYST IN-SITU REGENERATIONa) Plant airOil free plant air is used during catalyst regeneration to provide oxygen for coke

combustion:

Reactor No. Burning phase Polish burning phase

OverallconsumptionkgKg/hr Duration

(days)Kg/hr Duration

(hr)

75-R-01 358 7 2450 9 82 190

75-R-02 960 1 5908 1.5 31 900

b) MP steamMP steam is used for catalyst in-situ regeneration:

Reactor No.Stripping phase Burning phase Polish burning

Kg/hr Duration (hr)

Kg/hr Duration (days)

Kg/hr Duration (hr)

75-R-01 7650 8 4473 7 2485 9

75-R-02 14730 8 11 983 1 5992 1.5

1.13 EFFLUENT SUMMARY:a) Sour water from 75-V-03 separator drumAbout 5100 kg/hr during water injection in 75-A-03 for salts removal.

75-V-03 NIT CASE AM CASE BH CASE

Flowrates, kg/hr 5100 5100 NA

HC content, wt ppm 300 300 NA

Dissolved H2S, wt ppm 600 320 NA

Temperature, C 40 40 NA

b) Sour Water from HDS Stripper Reflux Drum 75-V-05This stream is less than 20 kg/h during normal operation.


Flowrates, kg/hr 10 11 NA

HC content, wt ppm 200 200 NA

Dissolved H2S, wt ppm 2260 2100 NA


c) Gas purge from Splitter Reflux Drum 75-V-02Continuous service for light ends removal: 537 to 905 kg/hr, 40°C at operating

temperature

d) Gas purge from HDS reaction sectionIn NIT Case the Amine absorber is bypassed and the purge gas (216 kg/hr) is

routed to sour purge gas.

In AM Case the Amine absorber is in service and the purge gas (56 kg/hr) is

routed to sweet purge gas.

e) Gas purge from HDS Stripper Reflux Drum 75-V-05

This stream exists during normal operation; it is sent to the sour purge for

treatment. This stream is sour (about 11.2 to12.4 % mol).

Continuous service for light ends and H2S removal: about 428 to 855 kg/hr, 40°C

as operating temperature.

f) Regeneration gas purge to atmosphereDuring PRIMEG+ reactors catalyst in situ regeneration operation, waste vapour

stream is routed to heater (75-F-01) stack at safe location under pressure control.

This waste vapour stream contains, during burning and polish burning phases:

Reactor No.CO2kg/hr

SO2kg/hr

SO3 kg/hr

H2Okg/hr

Estimated duration

75-R-01 83 599 15 4495 16 days

75-R-02 241 1206 31 12048 2.5 days

SECTION- 2 PROCESS DESCRIPTION

2.1 UNIT DESCRIPTIONThe completed unit is in accordance with the registered Prime G+

processing scheme. The purpose of this scheme is to meet an optimized

management of the gasoline pools regarding the sulfur content, olefins content

and octane number. The purpose is to achieve an olefin control in the gasoline

pools by an adjusted blending of the segregated olefin-rich (sulfur-lean) lighter

fraction of gasoline and the olefin-lean (sulfur-rich) gasoline.

2.2 SELECTIVE HYDROGENATION Refer PFD No.: 04-2529-75-5FD-2 sheet1/4 Rev 0

The feed is directly taken to the SHU Surge Drum 75-V-01. The pressure in

the surge drum is maintained by split range control of hydrogen and venting to

fuel gas header. The feed is pumped by SHU Feed Pumps (75-P-01A/B) under

flow control in cascade with the surge drum level control.

The hydrogen make-up from Isomerisation unit, unit 73 is sent to the unit

under ratio flow control to the hydrocarbon feed flow and mixed with the fresh

feed before entering tube side of SHU feed/HDS Effluent exchanger

(75-E-01A/B).

The feed and hydrogen mixture is heated by exchanging heat with the SHU

Feed / HDS Effluent Exchanger, 75-E-01. In addition, the feed is further heated

by the SHU Feed / Effluent Exchanger 75-E-02. The final heat-up of the feed to

reach the proper reactor inlet temperature is achieved in the SHU Preheater (75-

E-03). To allow a good control of the SHU reactor inlet temperature, a minimum

temperature increase of 50C must be done in the steam preheater. For that

purpose, a bypass of the 75-E-01 and 75-E-02 exchanger is installed and

controlled by temperature difference on 75-E-03.

The heated feed / hydrocarbon mixture flows to the top of the SHU reactor.

The reactor contains two beds of HR-845 catalyst. Operating conditions and

catalyst are optimized to provide selective hydrogenation of diolefins in the feed

and convert light mercaptans into heavier boiling temperature sulfur compounds.

A bypass line of the first bed was provided in case of any pressure drop

build-up in the 75-R-01 SHU reactor. The effluent from the SHU reactor flows

through the SHU Feed / Effluent Exchanger 75-E-02 and into the Splitter 75-C-

01, under pressure control.

2.3 SPLITTER SECTIONRefer PFD No.: 04-2529-75-5FD-2 sheet 2/4 Rev 0

The Splitter has 52 trays and the feed enters the column at tray 19

(numbering from bottom). The purpose of the Splitter is to fractionate the feed

and produce a Light Cracked Naphtha (LCN) and a Heavy Cracked Naphtha

(HCN). The LCN / Heart cut gasoline cut-point is adjusted to produce a low-sulfur

LCN while simultaneously recovering a large portion of olefins. This is possible

since the heavier boiling components contain a high disproportionate amount of

sulfur relative to low olefins content.

The Splitter overhead is almost totally condensed by air-cooling in the

Splitter Overhead Air Condenser 75-A-01. Vapour (excess hydrogen and light

ends) is separated from the reflux liquid in the Splitter Reflux Drum (75-V-02).

The Splitter Post Condenser (75-E-04) cools the vapour purge to battery limit

conditions in order to recover light ends from the purge. The splitter pressure is

controlled by the split range control of pressurizing hydrogen (normally no flow)

and venting to fuel gas header. The liquid is pumped by the Splitter Reflux

Pumps (75-P-03 A/B) and returned to the top of 75-C-01 as reflux, under flow

control in cascade with the reflux drum level control.

The LCN product is drawn from the accumulator tray number 48 of the

Splitter (numbering from bottom). It is cooled with the light gasoline Air cooler

(75-A-06) under flow control in cascade with the splitter tray 44 temperature

control of lighter sulfur compounds concentrated in the LCN.

The Splitter bottom is reboiled with 75-E-07 HP steam reboiler. The

reboiling steam rate is under flow control in cascade with the Splitter reflux flow.

Heavy naphtha from the splitter bottom (75-C-01) is sent to HDS section under

flow control in cascade with the splitter bottoms level control.

One benzene heart-cut is foreseen in order to reduce benzene content in the

gasoline pool in case of high concentration benzene in the PRIME G + feed. The

heart-cut benzene is drawn from the accumulator tray number 36. The heart-cut

stream is cooled by light gasoline air cooler 75-A-02 and pumped by 75-P-05 A/B

to storage after final cooling in 75-E-06 A/B under flow control reset by 31 st tray

temperature control.

As the selective hydrogenation reactor is operated mainly in liquid phase, a

sufficient liquid velocity shall be maintained at its inlet. Therefore, the

hydrocarbon flow rate to the reactor shall be at least of 75% of the normal flow

rate. In case of turndown (50% of feed), part of the splitter bottom shall be

recycled to the SHU feed surge drum under flow control.

2.4 HDS SECTIONRefer PFD No.: 04-2529-75-5FD-2 sheet 3/4 Rev 0

The heavy naphtha from 75-C-01 Splitter is pumped by HDS Feed Pumps

(75-P-02 A/B) under flow control in cascade with the splitter level control. The

main part of HCN feed is mixed with the recycle hydrogen before entering the

First HDS Feed / Effluent Exchanger (75-E-08 A/B/C).

The HDS reactor is divided in 3 beds of HR806 catalyst. The overall temperature

rise in the reactor is controlled by two injection of recycle liquid quench from the

separator drum 75-V-03 between the three beds.

The HDS effluent is further heated in HDS heater, 75-F-01. The heater operates

in vapor phase and the feed HDS reactor inlet temperature is controlled via fuel

gas control. The effluent from the heater is then cooled by the HDS feed / effluent

exchangers 75-E-08 A/B/C and by exchanger with the SHU reactor feed/HDS

effluent exchanger 75-E-01. Final cooling is achieved in the HDS effluent air

cooler 75-A-03 and the reactor effluent trim coolers 75-E-09 A/B.

An intermittent washing water injection point upstream the HDS effluent air

condenser 75-E-03 enables to flush these equipment from salt deposit that may

have been formed at low temperature.

The hydrocarbon liquid is partially pumped back to the HDS section through 75-P-

06 A/B quench pumps. The remaining part of the liquid is routed to the stabilizer

section under flow control reset by 75-V-03 level control.

2.5 RECYCLE COMPRESSOR SECTION

Refer PFD No.: 04-2529-75-5FD-2 sheet 3/4 Rev 0

The vapour enters the amine KO drum (75-V-06) where it is freed from

condensed liquid hydrocarbon particles due to a wire mesh.

In the amine absorber (75-C-02) the recycle gas is contacted with a 25 % wt

lean DEA solution coming from battery limits. The lean DEA is pre-heated in the

lean amine pre-heater (75-E-10), thus maintaining a 10°C temperature difference

between the gas and the amine.

The H2S enriched DEA, collected in the absorber bottoms, is then routed to

the DEA regeneration unit under amine absorber bottoms level control.

The sweetened gas is mixed with the H2 make up, then flows to the recycle

compressor K.O. drum (75-V-04) where it is freed from any liquid amine

entrainment that may have occurred.

Part of the gas is then purged to the fuel gas network under flow control to

prevent any light end concentration in the recycle loop. The remaining part of the

gas is compressed back to the 75-E-08 A/B/C inlet by the recycle compressor 75-

K-01 A/B.

2.6 STABILIZER SECTIONRefer PFD No.: 04-2529-75-5FD-2 sheet 4/4 Rev 0

The liquid from the separator is heated through the stabiliser feed/bottoms

heat exchangers (75-E-11 A/B) and enters the Stabiliser column (75-C-03). The

overhead of the stabilizer is condensed through the stabilizer overhead air

condenser (75-A-05) and additionally cooled in stabilizer overhead trim coolers

75-E-14A/B. The liquid phase, the water phase (if any) and the vapour phase

separate in the stabilizer reflux drum (75-V-05), the pressure of which is

controlled by the purge gas flow. The water collected in the boot is sent to the

sour water treatment under boot level control.

The liquid is routed back to the column as reflux by the stabilizer reflux

pumps (75-P-09 A/B) under flow control reset by reflux drum level control.

The stabilizer overhead is protected from corrosion by corrosion inhibitor injection

from the corrosion inhibitor package (drum + metering pump) into the stabilizer

overhead line.

The stabilizer bottom is reboiled by HP steam reboiler (75-E-13), the duty of

which is adjusted by HP steam flow rate reset by stabilizer sensitive tray control.

The bottoms of the stabilizer (treated heavy gasoline) is sent to storage under

flow control reset by stabilizer bottoms level control. The cooling down of the

stabilizer is ensured first by the stabilizer feed/bottoms heat exchanger (75-E-11

A/B) and by the heavy gasoline air cooler (75-A-07) heavy gasoline trim cooler

(75-E-12 A/B).

2.7 CATALYST IN-SITU REGENERATION OPERATION

The PrimeG+ unit is equipped with catalyst in-situ facilities that involve:

An air injection line to Reactor heater 75-F-01 for burning operation

A steam injection to Reactor heater 75-F-01 for stripping and burning

operations,

A nitrogen injection to Rector heater 75-F-01 for heating operation

The regeneration steps described below are equivalent for each reactor 75-R-

01 and 75-R-02 except the duration which may vary depending on the amount of

catalyst and steam and air flow rate.

The reaction section is hydrocarbon free and put under nitrogen atmosphere.

Then feed surge drum, feed pumps, splitter and stripper sections are isolated

from the reaction section.

The regeneration procedure includes:

1. A heating phase by nitrogen with 200°C catalytic bed reactor temperature.

2. A stripping phase by steam with 400°C catalytic bed reactor temperature for 8

hours.

3. A coke burning phase by steam and air with 0.3 up to 3.0 vol % oxygen in the

reactor inlet gas with 460°C catalytic bed reactor temperature

4. A catalyst polish burning phase by steam and air with 3.0 up to 8.0 vol %

oxygen and 480°C reactor inlet temperature. (These conditions are kept

during 4 hours).

5. A first cooling down of the reactor temperature to 200°C by steam.

6. A second cooling down of the reactor temperature to 65°C. Steam is replaced

by nitrogen.

SECTION- 3 PROCESS PRINCIPLE

3.1 PURPOSE OF THE PROCESS 3.2 GENERALThe purpose of the Prime G+ unit is a deep hydrodesulfurization of a FCC

gasoline. The majority of sulfur in the typical refinery gasoline pool is coming from

the FCC gasoline. This product is also characterized by a high olefins content.

Deep hydrodesulfurization of high sulfur content gasoline means the

process producing gasoline meeting the toughest sulfur standards. The

conventional gasoline desulfurization technology makes difficult to preserve

octane number due to olefin contents while meeting gasoline specifications, for

low sulfur content. At high level desulfurization, olefins are converted to low

octane alkanes, causing the road octane, (RON + MON)/2, to drop by a 5 to 10

points which is unacceptable. This is the aim of Prime-G+ process to remove

sulfur while avoiding substantial octane losses.

The treatment process operates in three reactors, having the specific catalyst

and operating conditions.

In the SHU reactor (75-R-01), diolefins are hydrogenated and light sulfur

compounds are converted into heavier sulfur species. The reactors effluent is

sent to a splitter column where it is split into three fractions: Light FCC

gasoline, FCC Heart cut gasoline and heavy FCC gasoline. FCC gasoline

heart cut is foreseen for high benzene content in the feed.

In the HDS reactor (75-R-02), most of the desulphurisation of the gasoline

takes place, so that the final gasoline pool meets the sulfur specifications.

Despite the high degree of desulfurization, olefin saturation is very limited and

no aromatic hydrogenation occurs. It is followed by a stabilization column to

remove the light ends, H2S and water resulting from the reaction and from

dissolved components in hydrogen make-up and recycle gases.

3.3 SELECTIVE HYDROGENATION REACTOR (75-R-01) The purpose of the SHU reactor is hydrogenation of diolefins in order to avoid

gum formation in HDS reactor. Moreover, it allows to convert light mercaptans

and light sulfides to heavier sulfur compounds.

The reaction is carried out in one down flow reactor operating mainly in liquid

phase with dissolved hydrogen at low temperature.

The reactor effluent is separated into three fractions in the splitter: light gasoline,

heart cut (intermittent mode for high benzene content in the feed) and heavy

gasoline. The light stream has a very low sulfur content and does not require an

extractive sweetening to further lower the sulfur content.

The light gasoline is a final product and is blended with the stabilizer bottom

before being routed to storage tanks, while heavy gasoline is fed to the HDS

reactor for further hydrodesulfurization.

3.4 SPLITTER (75-C-01)Before being sent to atmospheric storage, light gasoline must be blended with the

stabilizer bottoms or with an other low RVP stream due to the high RVP of the

light gasoline stream.

The FCC gasoline contains mercaptans, thiophene, alkyl thiophenes and

benzothiophene boiling in the same order, with the benzothiophenes being the

higher boiling sulfur components. As mercaptans and light sulfides are converted

into heavier sulfur species in the first reactor, thiophene becomes the first

significant sulfur component to be entrained in the light FCC gasoline product.

The TBP cut point temperature range for the thiophene boil up is about 55°C to

80°C. In general, olefins tend to concentrate in the lighter portion of the FCC

gasoline. Splitter operation is important to achieve a good balance between the

sulfur and olefin concentration present in the heavy FCC gasoline that is sent to

the HDS Reaction Section. The optimum amount of light gasoline depends on the

FCC feed sulfur content, feed thiophene content and on the product sulfur

specification. The exact amount of light FCC gasoline drawn should be precisely

controlled by monitoring the on-line light FCC gasoline sulfur analyzer.

The light FCC gasoline draw rate and the sulfur content is controlled indirectly by

a temperature controller located on the Splitter column a few trays below the light

FCC gasoline draw tray.

A lower light FCC gasoline withdrawal rate from the Splitter will produce an heavy

FCC gasoline with higher olefin concentrations and hence potentially higher

octane losses in the HDS Reaction Section. Alternatively, a higher light FCC

gasoline withdrawal rate from the Splitter will produce an heavy FCC gasoline

with lower olefin concentrations which is initially favorable for octane losses in the

HDS Reaction Section but with increased sulfur levels in the light FCC gasoline.

As the light FCC gasoline rate in the Splitter is increased, the severity of the HDS

Reaction Section has to be increased to offset the amount of sulfur that has left

with the light FCC gasoline.

3.5 FIRST HDS REACTOR (75-R-02)The purpose of the HDS reactor is to achieve the bulk of the hydrodesulfurization

of the heavy FCC gasoline, while limiting olefins saturation.

The reaction is carried out between the vaporized gasoline and an hydrogen rich

gas over a desulfurization catalyst bed.

Sulfur in cracked gasoline is distributed as follows:

Aromatic sulfur (benzothiophene).

Acidic sulfur (mercaptan type).

Disulfide type.

Sulfide type.

Thiophene and alkyl thiophenes.

3.6 CHEMICAL REACTIONS AND CATALYST3.6.1 OBJECTIVE

The objective is to help the operators to better understand the reasons of the

operating instructions and enable them to make wise decisions, should the

circumstances deviate from those covered in the Operating Instructions.

The different chapters of this section describe:

1. The various chemical reactions involved in the process as well as the effect of

the operating conditions.

2. The catalyst characteristics.

3. The catalysis mechanism.

4. The catalyst contaminants.

5. The process variables.

3.6.2 THERMODYNAMICS AND KINETICSFor any chemical reaction, the thermodynamics dictates the conditions of its

occurrence and the amount of products and unconverted reactants. In fact, some

reactions are 100% completed i.e., all the reactants are converted into products.

Others are in equilibrium i. e., part of the reactants only are converted. The

amount of products and reactants at equilibrium depends upon the operating

conditions and is dictated by the thermodynamics. Note that the thermodynamics

does not involve the time required to reach equilibrium or the completion of a

reaction.

Kinetics dictates the rate of a chemical reaction (i. e., the amount of feed that is

converted to products during defined time). Kinetics (rate of reaction) is

dependent upon the operating conditions but can also be widely modified through

the use of properly selected catalysts. One reaction (or a family of reactions) is

generally enhanced by a specific catalyst.

In other words thermodynamics dictates the ultimate equilibrium composition

assuming the time is infinite while kinetics enables the prediction of the

composition after a finite time. Since time is always limited, when reactions are

concurrent, kinetics is generally predominant.

A catalyst generally consists of a support (earth oxide, alumina, silica,

magnesia...) on which (a) finely dispersed metal(s) is (are) deposited.

The metal is responsible for the catalytic action, but very often the support has

also a catalytic action related to its chemical nature.

A catalyst is not consumed, but can be deactivated either by impurities in the

feed or by some of the products of the chemical reactions involved, resulting in

polymers or coke deposits on the catalyst.

3.6.3 CATALYST ACTIVITY, SELECTIVITY AND STABILITYThe main characteristics of a catalyst other than its physical and mechanical

properties are:

The activity which is the catalyst ability to increase the rate of the reactions

involved. It is measured by the temperature at which the catalyst must be

operated to produce a product on-specification, for a given feed, all other

operating conditions being equal.

The selectivity expresses the catalyst ability to favour desirable reactions

rather than others. It is measured by the quantity of desired product.

The stability characterizes the change with time of the catalyst performance

(i. e., activity, selectivity) when operating conditions and feed are stable. It

is chiefly polymers or coke deposits that affect stability since they decrease

the metal contact area. Traces of some metals in the feed also adversely

affect stability.

3.6.4 SELECTIVE HYDROGENATION REACTIONS AND CATALYSTIn SHU reactor, the hydrogenation of diolefins takes place in order to avoid gum

production and in the HDS reactor, hydrodesulfurization takes place. They also

convert the light mercaptans and some other light sulfur compounds to heavier

sulfur compounds, to enable producing a light naphtha fraction almost free of

mercaptans and light sulfides.

3.6.5 CHEMICAL REACTIONSThe FCC gasoline contains the following unsaturated components:

Diolefins (aliphatics or cyclics).

Olefins.

Aromatics.

Several chemical reactions can take place during the diolefin hydrogenation. The

most important ones are:

The hydrogenation of diolefins.

The conversion of light sulfur compounds into heavier sulfur species.

The isomerization of olefins.

The hydrogenation of olefins.

The last reaction must be avoided as much as possible.

3.6.6 HYDROGENATION OF DIOLEFINSDiolefins are hydrogenated into corresponding olefins and some of the olefins are

hydrogenated into corresponding paraffins.

A) Cyclodiolefins

A typical example is cyclohexadiene which is hydrogenated into cyclohexene

with no further hydrogenation with the catalyst and at the operating conditions

of the first stage.

B) Normal or isodiolefins

Normal diolefins:Their hydrogenation produce several isomers, for example:

CH3 - CH2 - CH2 - CH2 - CH2 - CH = CH2

CH3 – CH = CH – CH2 – CH2 – CH = CH2 + H2 1 Heptene

1 – 5 Heptadiene CH3 - CH = CH - CH2 - CH2 - CH2 - CH3

2 Heptene (cis and trans)

Iso-diolefinsIsodiolefins hydrogenation produces also various isomers. Moreover double bond

migration can also occur within the newly generated isomer.

Diolefins are very unstable compounds, which polymerize easily into gums.

Therefore conversion of diolefins into olefins improves the product quality: these

reactions are highly exothermic. The difference between the diene value (DV) or

the maleic anhydride value (MAV) of the feed and the DV or MAV of product

measures the yield of these reactions and could be related to the hydrogen

consumption. Refer to chapter "Operation of the unit".

3.6.7 ISOMERIZATION OF OLEFINSCH2 = CH - CH2 - CH2 - CH2 - CH3 ® CH3 - CH = CH - CH2 - CH2 - CH3

1 - Hexene 2 - Hexene

This reaction, thermodynamically enhanced by low temperatures (T < 200°C),

takes place when diolefins are almost completely eliminated. It offers the

advantage of leading to internal olefins that are more stable towards

hydrogenation than external olefins. Thus the selectivity is improved. In addition,

internal olefins often have a higher octane number.

3.6.8 HYDROGENATION OF OLEFINSThese reactions are undesirable because they reduce the octane number.

The hydrogenation of diolefins is faster than the hydrogenation of olefins.

Nevertheless it is difficult to avoid totally hydrogenation of olefins, particularly if

the feed contains 1-olefins which are more reactive than 2,3-olefins.

This reaction is also exothermic.

The difference between the feed bromine number (BrN) and the product bromine

number measures the conversion rate of this reaction and could be related to the

hydrogen consumption. Refer to chapter "Operation of the unit".

3.6.9 THERMAL AND CATALYTIC POLYMERIZATION OF UNSTABLE COMPOUNDSThese reactions are undesirable because polymer deposits reduce both catalyst

activity and cycle duration.

The catalytic polymerization of olefins and even diolefins remains negligible, in

the range of the selected operating conditions, when the appropriate catalyst is

used.

3.6.10 THERMODYNAMIC AND KINETIC ANALYSISThe hydrogenation of unsaturated hydrocarbons is characterized by an important

heat release (exothermic reaction) and a reduction of volume. Consequently

from a thermodynamic point of view, these reactions are favored by low

temperature and high pressure. The typical heats of reaction (per mole of

reactant) are respectively:

Diolefins to olefins : 26 Kcal/mole

Olefins to paraffins: 30 Kcal/mole

From a kinetic viewpoint, with a proper catalyst, at temperature in the range of

160°C, the rate of the diolefins hydrogenation is high enough for almost complete

hydrogenation.

3.6.11 SULFUR REACTIONIn cracked naphthas (FCC gasoline and pyrolysis gasoline), the principal sulfur

compounds include mercaptans (RSH), aliphatic sulfides (RSR), aliphatic

disulfide and thiophenes. Over selective hydrogenation catalysts, light

mercaptans and light sulfides are converted to heavier sulfur species. In addition,

H2S is also converted to heavier sulfur compounds. The combination of selective

hydrogenation and FCC naphtha fractionation allows the production of a light

naphtha stream with a very low sulfur content, provided that thiophene carry-over

in this stream is controlled. The sulfur shift reactions are faster reactions than the

diolefin hydrogenation reactions.

The heavy sulfur compounds produced over the selective hydrogenation

catalysts are essentially heavy sulfides and, to a lesser extent, heavy

mercaptans. The following mechanisms are believed to take place:

Conversion of light mercaptans to heavy sulfides

1. Conversion of light mercaptans to heavy mercaptans

2. Conversion of sulfides to heavier mercaptans

3. Conversion of H2S to mercaptans

Although some of these mechanisms involve the production of some H2S, the

H2S addition reaction is a very fast reaction. Therefore, no H2S exits the reactor.

Approximately 95-98% of the light mercaptans are converted in the Selective

Hydrogenation reactor. Carbonyl sulfide (COS) and carbon disulfide (CS2) will

also be converted to near extinction. Di-methyl sulfide (DMS) and ethyl-methyl

sulfide (EMS) conversion is limited at approximately 50-70%.

Following are examples of the reactions that occur:

Conversion of Light Mercaptans to Heavier SulfidesRSH + R' (C5 to C7 olefin) RS R'

Conversion of Light Mercaptans to Heavier MercaptansStep 1

RSH + H2 RH + H2S

Step 2

H2S + R' (C5 to C7 olefin) R'SH

Conversion of Sulfides to Heavier MercaptansCH3 – S – CH3 or + H2 ® CH4 and C2H6 + H2S

C2H5 – S – CH3

H2S + R' (C5 to C7 olefin) R'SH

Conversion of H2S to Heavier MercaptansH2S + R' (C5 to C7 olefin) R'SH

3.7 PROCESS VARIABLES IN SELECTIVE HYDROGENATIONThere are four main process variables:

Reactor temperature,

Residence time in the reactor,

Reactor pressure,

Hydrogen gas rate.

3.7.1 REACTOR TEMPERATUREThermodynamics for conversion of light mercaptans and selective hydrogenation

of diolefins are very favorable. The reaction will go to completion over a wide

range of operating temperature. Diolefin hydrogenation to olefins is completed

even at relatively high temperature and low H2 content.

From a kinetic perspective, the mercaptan conversion and hydrogenation rate

is increased at higher temperature.

Hydrogenation selectivity (diolefin/olefin), however, is favored by lower

temperature.

For catalyst stability, the operation must take place at lower temperature to

prevent polymerization of gum precursor compounds. Thermal polymerization

deactivates the catalyst by coating of the active area and is accelerated at

temperatures above 200°C.

Low operating temperature minimizes vaporization of the feedstock, keeping

the reactants in the liquid phase at moderate pressures.

However, as catalyst ages, polymer deposits progressively coat the selective

sites and catalyst activity decreases (i.e. at the same temperature, conversion

drops). A slight progressive increase in reactor temperature is used to

compensate for this loss of activity. The limit correspond to the end of run

temperature.

The normal inlet temperature for a feed composition as specified in the design

basis, ranges from the start of run (SOR) figure to the end of run (EOR) figure.

Refer to chapter “operation of the unit/summary of operating condition”.

3.7.2 RESIDENCE TIME IN THE REACTORIn chemical catalysis, the residence time is expressed through the liquid hourly

space velocity (LHSV) which is defined as the ratio of the hourly liquid feed flow

rate (expressed in volume at 15°C) to the catalyst volume.

LHSV =

Both volumes must be expressed with the same unit.

For a liquid phase reaction, taking place at 15°C, the residence time of the feed

on the catalyst is then the reverse of the LHSV. A LHSV of 2 h-1 means a

residence time, at the operating temperature, close to 1/2 hour.

Increasing the residence time (i. e., decreasing the feed hourly flow) results in a

higher conversion of diolefins, and on the contrary, increasing the feed flow rate

results in a lower conversion.

3.7.3 REACTOR PRESSUREAn important criterion for liquid phase hydrogenation is the content of dissolved

hydrogen. The content of dissolved hydrogen depends on the total pressure, the

hydrogen make-up flow and the hydrogen make-up purity. Complete diolefin

hydrogenation requires only a small amount of hydrogen in excess of the

stoechiometric requirement.

Higher operating pressure:

Improves diolefin hydrogenation.

Reduces the polymerization reactions/coke deposits and increases catalyst

cycle length.

Increases hydrogen dissolved in the liquid phase.

Improves liquid distribution in the reactor and reduces pressure drop due to

vaporization.

The reactor operating pressure is fixed at the design stage, operator will maintain

this maximum operating pressure during all normal operation.

3.7.4 HYDROGEN MAKE-UP RATEAn increase in H2 make-up rate will favor light mercaptans conversion and

diolefins hydrogenation. However, a large excess of hydrogen would lead to

partial saturation of olefins, in other words to higher octane loss.

Therefore, operation will aim at feeding unit with a small excess of H2 (25%)

calculated from a chemical consumption assuming 90 to 100% hydrogenation of

diolefins and 3% hydrogenation of olefins.

A 40% excess has also been foreseen at design stage corresponding to EOR

conditions.

3.8 CHEMICAL: HDS REACTOR REACTIONS AND CATALYST3.8.1 CHEMICAL REACTIONS

Sulfur removal is the major purpose of this reactor in order to prepare a

desulfurized stock of the gasoline pool. However, partial olefin saturation

reactions and partial denitrogenation (denitrification) of a small amount of

nitrogen compounds that are present in the feed occur simultaneously with

desulfurization.

The reaction taking place in the reactor can be grouped as follows:

Hydrorefining (i.e. desulfurization, denitrification).

Hydrogenation of olefins (which are undesirable reactions).

All these reactions are exothermic.

3.8.2 HYDROREFININGA) DesulfurizationThe typical sulfur compounds in cracked gasoline are of the thiophenic and

benzothiophenic types.

The desulfurization occurs in several phases.

Thiophene Thiophane Mercaptans H2S

The desulfurization reactions are exothermic, but owing to the limited amount of

reactant involved, they do not lead to a noticeable temperature increase.

The rate of desulfurization reactions follows first-order kinetics. In the reactor, the

desulfurization reactions take place. Benzothiophenes and thiophenes are

essentially converted and the residual sulfur is essentially in the form of

thiophanes (or tetra-hydro-thiophenes) and mercaptans.

B) Denitrification (or denitrogenation)Nitrogen is removed in catalytic hydrotreating by the breaking of the C-N bond

producing a nitrogen free aliphatic and ammonia. The breakage of the C-N bond

is much more difficult to achieve than the C-S bond in desulfurization.

Consequently denitrification occurs to a much lesser extent than desulfurization.

Nitrogen compounds typically found in cracked gasolines are methylpyrrol and

pyridine types.

The heat released by the denitrification reactions is also negligible owing to the

small amount of nitrogen compound involved.

3.8.3 HYDROGENATION OF OLEFINSHydrogenation or olefin saturation is the addition of a hydrogen molecule to an

unsaturated hydrocarbon to produce a saturated product. Olefinic hydrocarbons

are found in high concentrations in cracked gasolines. The olefin saturation

reaction is highly exothermic and is controlled by the process. The comparative

reactivity of olefins is the following (from more reactive to less reactive):

n - olefins > n internal olefins > branched olefins > cyclic olefins > internal branched

olefins

Typical olefins hydrogenation reactions are:

+ H2

CH3 - CH2 - CH2 -CH2 -CH2 - CH = CH2 CH3 - CH2 - CH2 - CH2 -

CH2 -CH2 -CH3

1-heptene (n - olefins) n-heptane

+ H2

CH3 - CH - CH = CH –CH3 CH3 - CH - CH2 - CH2 - CH3

CH3 4 methyl 2 pentene CH3 2 methyl pentane

(internal branched olefins)

The reactions of this type are exothermic ( H = 30 kcal/mol).

3.9 RELATIVE RATES OF REACTIONUnder the selected operating conditions and the choice of catalyst, these

reactions are classified hereafter in decreasing order of reaction rate:

hydrodesulfurization > olefins hydrogenation > > > aromatic hydrogenation

3.9.1 PROCESS VARIABLES IN HDS REACTORThere are four main process variables:

Reactor temperature

Operating pressure and Hydrogen/hydrocarbon ratio

Space velocity.

For each of these variables, we have to distinguish their influence on activity and

on selectivity.

3.9.2 TEMPERATUREThermodynamically, as the hydrodesulfurization and olefin hydrogenation

reactions are exothermic, these reactions are favored by low temperature.

In terms of selectivity, an increase of temperature enhances the selectivity

between hydrodesulfurization and olefin hydrogenation but the impact is very low.

Nevertheless, a control of temperature in reactors makes the process control

easier and avoids some phenomena like runaway.

Practically, temperature must be selected high enough that the naphtha is in

gaseous phase at the operating pressure but keeping a margin for temperature

increase to compensate for catalyst deactivation.

Typical operating temperatures range from 270°C (inlet T, SOR) to 300°C (inlet

T, EOR) for the high sulfur feed (first reactor).

In term of activity, a higher temperature increases the activity of

hydrodesulfurization and olefins hydrogenation reactions.

The target will be to operate at the minimum temperature compatible with the

level of desulfurization required.

In case a lower sulfur feed is processed in the unit, the thermal levels on the first

reactor are lowered to 245°C (inlet T, SOR) and to 275°C (inlet T, EOR), ex: BH

case.

3.9.3 OPERATING PRESSURE AND H2/HC RATIO

A) Hydrogen partial pressure

In terms of activity, an increase of the hydrogen partial pressure enhances the

hydrodesulfurization and olefins hydrogenation.

In addition, a high hydrogen partial pressure reduces the polymerization reactions

and coke deposit, increasing the cycle length.

B) Hydrocarbons partial pressure

This parameter has no impact on the hydrodesulfurization. Nonetheless, to

minimize hydrogenation of olefins, it is necessary to minimize olefin partial

pressure therefore hydrocarbon partial pressure. Hence, the operating pressure

is selected to optimize the HDS reaction rate and the HDS selectivity over the

olefin hydrogenation reactions.

C) H2 / HC ratio

As the operating pressure is selected during the design stage, the most important

operating variable is the H2/HC ratio. An increase of the H2/HC ratio enhances

activity and selectivity in favor of hydrodesulfurization (higher ppH2 , lower ppHC,

lower ppH2S)

In practice, the recycle gas compressor must be operated at its maximum

capacity in order to maximize the H2/HC ratio.

D) Hydrogen sulfide partial pressure

The effect of H2S partial pressure on the hydrogenation of olefins is very slight,

but H2S affects the hydrodesulfurization. Therefore, an increase of the hydrogen

sulfide partial pressure has a negative effect on the selectivity. An amine washing

of recycle gas is provided to decrease the H2S content.

3.9.4 SPACE VELOCITYAs the reactor operates in the gaseous phase with a large amount of recycle

hydrogen, the residence time is only proportional (not equal) to the inverse of the

space velocity.

Space velocity is a parameter readily available to operators. Each time the feed

flow is changed, the space velocity changes in proportion to the flow. A decrease

of the space velocity (i.e. an increase of the residence time) enhances the activity

of reactions, yet without any enhancement of selectivity .

SECTION- 4 UTILITY DESCRIPTION

4.1 INTRODUCTION

The utility system consists of Nitrogen, Instrument Air (IA). Plant Air (AP), Sea

Cooling Water (WC), Service Water (SW), Boiler Feed Water (BFW), HP/MP/LP

Steam, LP Condensate, Bearing Cooling water (BCW) and Fuel Gas (FG).

Closed Blow down (CBD), Amine Blow down (ABD) Flare is also provided within

the unit.

Description related to various utility systems for Prime G+unit is given below.

4.1.1 INSTRUMENT AIR SYSTEM

A 2" Instrument Air header supplies IA to Prime G+ Unit. The header is provided

with isolation valve and a spectacle blind. Various Instrument air tapping are

taken from this header. In DCS FI-4502 with FQ and FAH/FAL, PI-4505 with

PAH/PAL and TI-4502with TAH/TAL and local TI, PI is provided on the 3” header

at B/L.

4.1.2 PLANT AIR SYSTEM

A 6" Plant Air header supplies PA to Prime G+ Unit. The header is provided with

isolation valve and a spectacle blind. Various Instrument air tapping are taken from

this header. Plant air is also used during in-situ regeneration. In DCS FI-4501 with

FQ, and local TI, PI is provided on the 6” header at B/L.

4.1.3 SEA COOLING WATER SYSTEMThe cooling water requirement for cooling purpose in the Prime G+ Unit is met

through Offsite Sea cooling water system. A 16” sea cooling water supply header

supplies cooling water to Prime G+ Unit. The header is provided with isolation

valve and a spectacle blind for positive isolation at the battery limit. PI-4602 with

PAH/PAL, TI-4602 with TAH/TAL and FI-4601 with FQ/FAH/FAL and local TI & PI

are provided on the 14” header at B/L.

Cooling water from the supply header is taken to the following equipment in Prime

G+ Unit.

Recycle Compressor (75-K-01A/B)

FCC Heart cut cooler (75-E-06A/B)

Light Gasoline cooler (75-E-05A/B)

Splitter post condenser (75-E-04A/B)

Reactor effluent trim cooler (75-E-09A/B)

Heavy Gasoline cooler (75-E-12A/B)

The return water is collected in a 16” return header and sent to B/L. Individual return

line from cooler is provided with a Local temperature Indicator (TI) and Thermal

safety valve. The return header is provided with isolation valve and a spectacle

blind for positive isolation at the battery limit. The return header is also provided with

TI-4603, with TAH/TAL, PI-4603 with PAH/PAL and FI-4602 with FAL/FAH in DCS

and local PI & TI at B/L. A 6” Jump over between supply and return header is also

provided at B/L.

4.1.4 BEARING COOLING WATER SYSTEMThe cooling water requirement for cooling purpose of pump cooling in the Prime

G+ Unit is met through Offsite Bearing cooling water system. A 4” Bearing cooling

water supply header supplies BCW to Prime G+ Unit. The header is provided with

isolation valve and a spectacle blind for positive isolation at the battery limit. PI-

4702 with PAH/PAL, TI-4702 with TAH/TAL and FI-4701 with FQ/FAH/FAL and

local TI & PI are provided on the 4” header at B/L.

BCW from the supply header is distributed to various pumps/equipment in Prime

G+ Unit.

The return water is collected in a 4” return header and sent to B/L. Individual

return line from cooler is provided with a Local temperature Indicator (TI) and

Thermal safety valve. The return header is provided with isolation valve and a

spectacle blind for positive isolation at the battery limit. The return header is also

provided with TI-4703 with TAH/TAL, PI-4703 with PAH/PAL, FI-4702 with

FAL/FAH in DCS and local PI & TI at B/L. A 4” Jump over between supply and

return header is also provided at B/L.

4.1.5 SERVIC WATER SYSTEM

The 2” common service water header supplies service water to Prime G+

Unit. It is provided with an isolation valve and a spectacle blind at battery limit. In

DCS FI-4503 with FQ and Local PI/TI is provided at the battery limit. The service

water header supplies water to various hose stations in the units. Service water is

required mainly for cleaning and washing.

4.1.6 NITROGENA 8” header supplies N2 to Prime G+ Unit. N2 is used for various purposes

in equipment, line etc. for inertisation, blanketing, purging, in-situ regeneration

etc. The supply header is provided with DCS FI/FQ-4101 with FAH/FAL, PI-4102

with PAL/PAH along with local PI & TI at B/L.

4.1.7 LP STEAM SYSTEMA 6” header supplies LP steam to Prime G+ Unit. FI/FQ-4401 with

FAL/FAH, PI-4402 and TI-4402 with Low and High alarm is provided in DCS to

monitor LP steam B/L condition. Also local PI & TI are provided. At B/L block

valve along with spectacle blind are provided for positive isolation.

Use of LP steam in the unit is mainly as follows:

Utility hose station

For Tracing Requirement

Various Process User

4.1.8 MP STEAM SYSTEMA 10” header supplies HP steam to Prime G+ Unit. FI/FQ-4403 with

FAL/FAH, PI-4402 and TI-4402 with Low and High alarm is provided in DCS to

monitor HP steam B/L condition. Also local PI & TI are provided. At B/L block

valve along with spectacle blind are provided for positive isolation.

Use of HP steam in the unit is mainly as follows:

Start-up ejector (75-J-01)

For in-situ regeneration burning phase.

Heater De-coking purpose

For Lancing steam

4.1.9 VHP STEAM SYSTEMA 8” header supplies VHP steam to Prime G+ Unit. VHP PRDS (75-X-01) is

provided to reduce the steam pressure. FI/FQ-4301 with FAL/FAH, PI-4302 and

TI-4302 with Low and High alarm is provided in DCS to monitor VHP steam B/L

condition. Also local PI & TI are provided. Block valve along with spectacle blind

is provided at B/L for positive isolation.

Use of VHP steam in the unit is mainly as follows:

SHU Pre-heater (75-E-04)

Splitter Reboiler (75-E-05)

Stabiliser Reboiler (75-E-13)

4.1.10 FUEL GAS SYSTEM

Fuel Gas is received in Fuel gas Knock-out drum (75-V-16) and from KOD

FG is distributed to various users. The FG receiving header is of 3” size and it is

provided with double block valve and spectacle blind at B/L. FI/FQ-2201 with

FAH/FAL is provided in DCS to indicate FG consumption.

Fuel Gas is used in the following points of the unit:

HDS Reactor Feed Heater (75-F-01)

In Amine Blow-down Drum (75-D-18)

4.2 EFFLUENT SYSTEMLiquid and gaseous effluents are generated in the plant. These effluents are

disposed off the plant to a safe location.

1. Sour water from 75-V-03 separator drumAbout 5100 kg/hr during water injection in 75-A-03 for salt removal.

NIT CASE AM CASE BH75-V-03

Flow rate kg/hr 5100 5100 NA

HC content wt ppm 300 300 NA

Dissolved H2S wt

ppm

600 320 NA


2. Sour water from HDS stabilizer reflux drum 75-V-05This stream is less than 20 kg/hr during normal operations.


Flow rate, kg/hr 10 11 NA

HC content wt ppm 200 200 NA

Dissolved H2S wt

ppm

2260 2100 NA


3. Gas purge from splitter reflux drum 75-V-02Continuous service for light ends removal: 537 to 905 kg/hr, 400C at operating

temperature.

4. Gas purge from HDS reaction sectionIn NIT case, the Amine absorber is bypassed and the purge gas (216 kg/hr) is

routed to sour purge gas.

In AM case, the amine absorber is in service and the purge gas (56 kg/hr) is

routed to sweet purge gas.

5. Gas purge from HDS stripper reflux drum 75-V-05This stream exist during normal operation and is sent to the sour purge for

treatment. This stream is sour (about 11.2 to 12.4 %mol).

Continuous sevice for light ends and H2S removal: about 428 to 855 kg/hr, 400C

at operating temperature.

6. Regeneration gas purge to atmosphere

During PRIMEG+ reactors catalyst in situ regeneration operation, waste vapour

stream is routed to 75-F-01 heater stack at safe location under pressure control.

This waste vapour stream contains, during burning and polish burning phases:

Coke burning Phase

Effluent CO2 H2O Duration

Kg/hr Kg/hr days

75-R-01 83 4495 7

75-R-02 241 12048 1

Polish burning phase

Effluent SO2 SO3 H2O Duration

Kg/hr Kg/hr Kg/hr days

75-R-01 599 15 2485 9

75-R-02 1206 31 5992 1.5

SECTION- 5 PREPARATION FOR START-UP

5.1 GENERALAs the new unit nears completion, there is a large amount of preparatory

work, which should be performed by the operating crew. A planned check of the

unit will not only set the foundation of a smooth start-up, but will also provide a

firm basis for acquainting operators with the equipment. Start-up is a critical

period and the operator must know exactly the operation of each equipment.

Some of the pre-commissioning works can be carried out simultaneously

along with construction. But, care in the organisation of this work is necessary so

that it does not interfere in the construction activities. It is most important to plan

schedule and record with checklists and test schedules all the preliminary

operation and to co-ordinate the constructions programme.

5.2 PRE-COMMISSIONING ACTIVITIESThe material in this section gives general guidelines for preparing a unit for

start-up. Some sections need to be expanded to give specific directions (water

flushing procedure, inerting procedure for example); this is prepared by

commissioning personnel prior to start of the pre-commissioning/start-up.

5.2.1 INSPECTION / CHECKINGSections of the unit should be checked out as soon as the contractor

completes work in those areas. Immediately followed by inspection of those

areas, punch lists which indicate the deviations from the design specifications

should be written and distributed to the contractor. In this manner mistakes in

construction can be found and corrected early.

Inspection of the plant can be basically divided into the following areas:

Vessels

Piping

Heaters

Exchangers

Pumps

Instrumentation

5.2.2 INSPECTION OF EQUIPMENTSInspection of the interior of the vessels, columns, heaters and other

equipment normally accessible during operation should be made to ensure that

they are complete, clean and correctly installed. Tray assemblies in columns

should be checked with reference to the engineering drawings to detect any

defect in assembly or construction and to ensure cleanliness. Packing if any to be

done after internal inspection and flushing. The vessels are to be checked with

reference to engineering drawings. The demister is to be fitted after internal

cleaning and water washing.

In heaters, the burner assemblies should be checked for easy operation of

air registers, contour of the burner throat, debris material etc. The heater coils

supports to be checked for proper installation.

Checklist formats are attached as Annexure

5.2.3 PIPING AND ACCESSORIESPiping and accessories will be checked against drawings and specifications.

Piping support and hangers will be inspected to ensure that all anchorage’s are

firm. Valves will be checked for proper packing and mounting direction and

accessibility for operation and maintenance. Spring supports, if any, to be

checked for the cold setting and later for hot settings while plants is in operation.

5.2.4 INSTRUMENTSAll instrument tapings for pressure, level and flow should be clear and

Thermowells should not foul with the internals. These should be checked prior to

box up of the equipment.

Instruments will be checked, starting from the controller and proceeding

logically through the control loop. Cascade control system will be checked from

the impulse point of primary loop. Operating crew should check proper mounting

of control valves. Control valves responses should be checked for controller

outputs. The shutdown systems of the equipment and machinery will be checked

by simulating the various conditions in the control circuits.

5.2.5 RELIEF VALVESRelief valves will be set in the shop and mounted before the system

pressure test. Block valves ahead and after relief valves will be checked for lock

open or lock close position as per P&ID. Relief valves will be checked against

specifications.

5.2.6 ROTARY EQUIPMENTAll rotary equipment such as pumps, fans etc. are to be checked for

bearings, internals and free movement. The auxiliaries, control systems on this

equipment should be thoroughly inspected.

5.2.7 DRAINAGE SYSTEMCheck the OWS and blow down system against drawings. Check for free

flow.

5.3 PREPARATION FOR PRE-COMMISSIONING

Check the unit for completion of mechanical work against P&ID.

Check list points are liquidated. Any pending point will not affect pre-

commissioning operation.

Remove all construction debris lying around in the unit and clean up the area.

Install blinds as per master blind list.

Safety valves should be kept blinded during flushing and re-installed

afterwards.

These should be shop tested and set at the stipulated values.

Ensure that underground sewerage system is in working condition. Clear

plugging, if any. Check by flushing with water.

Check that communication between units, control room, offsite and utilities are

complete and in working condition.

Ensure that the required lube oil, grease and other consumable are available

in the unit.

5.4 PRE-COMMISSIONING Prior to the commissioning of the plant there are several pre-commissioning

operations that must be conducted to prepare the plant for the actual start-up

these are:

1. Commissioning of utilities

2. Final inspection of vessels

3. Pressure test equipment

4. Wash out lines and equipment

5. Functional test of rotating equipment

6. Instruments checking

7. Safety device checking

8. Heater Refractory dry-out

9. Purge and gas blanketing

10. Tightness test

11. Catalyst loading procedure

12. Charging of chemicals

It is important that these operations be carried out as thoroughly and as well

as possible to help achieve a smooth and trouble-free start-up and later steady

normal operation. A discussion detailing the major items to monitor in each of

these operations follows.

The above outline may be expanded somewhat as follows:

5.4.1 COMMISSIONING OF UTILITIESThe various utility lines should be tested and placed into service as soon as

the construction schedule allows. Pressure tests should be carried out on all

steam condensate, air, fuel gas, flare, and nitrogen lines as are done on all

process lines.

a) Steam NetworkNetwork is blown through completely from battery limit with a strong steam

flow in order to clean the lines. The following steps are recommended:

Check network, all equipment will be disconnected to avoid entry of flushed

material.

Drain all the low points. If necessary open steam trap inlet flanges.

Open slowly battery limit valve and let the temperature rise in the header,

slowly and steadily.

Check support of fixed points and expansion loops.

When line is hot, blow it through completely with a strong steam flow.

Close battery limit valves and prepare another network. When the blowing are

satisfactory, reconnect all equipment and remount steam traps. Recharge

header as above.

To gauge the effectiveness of the steam blowing (and the amount of scale left

in the lines), target plates should be installed at the blow-down points. The

lines should be repeatedly blown down until virtually unmarked target plates

are obtained. Condensate lines should be continually checked and traps

removed and cleaned if plugged.

Note: The following precautions to be taken while blowing / commissioning steam

header.

To drain the low points of the lines before and during heating period in order

to avoid water accumulation, that causes hammering.

To open drain / vent during cooling period to prevent vacuum formation

To isolate the instruments, remove orifice plates and control valves; to re-

install the orifice plates and control valves after blowing is over.

b) Sea Cooling Water and Service Water:

Network shall be cleaned from battery limit with a strong water flow. All

equipment will be disconnected at the inlet and reconnected when lines are

cleaned. Control valves and orifice plates will be removed and re-installed, after

the lines become clean. When system has been flushed, charge the lines to the

operating pressure.

The following precautions to be taken:

To open vents at high points in order to expel air from equipment and piping

To open the battery limit valve, slowly and steadily.

c) Instrument Air and Plant Air:

Network shall be blown through completely from battery limit with strong flow

of air in order to clean and dry the lines. All joints and connections shall be

checked for tightness with soap solution. Header and branch lines will be blown

through with a high flow rate of air. During all tests, the instruments and control

valve shall be carefully isolated from the system.

d) Fuel Gas Networks:Networks shall be blown through from battery limit with a strong airflow in

order to clean the lines. During the operations, orifice plates and control valves

shall be removed. Special care shall be taken to prevent water from entering the

furnace. The fuel oil and fuel gas headers will be commissioned before firing the

Heaters.

5.4.2 FINAL INSPECTION OF VESSELSAll vessels should be inspected before final closing and any loose scale,

dirt, etc. should be removed. Any line coming directly off of the bottom of a dirty

vessel should be removed.

It is very important that the internals of the hydro-treating reactor be

inspected very carefully. The hydro treating reactor internals should be checked

for holes and/or damage and repaired as required. The catalyst support basket

and unloading sleeve should be checked to ensure correct fit in the nozzles.

The separator should be checked carefully to be sure the cement lining is

installed well and that the mesh blanket is securely fastened to the support ring.

There should be no gaps in the mesh blanket.

5.4.3 PRESSURE TEST EQUIPMENT It is normally the mechanical contractor’s responsibility to hydrostatically

pressure test the unit during construction. The following suggestions are

generally made by Licenser to help during the stage of start up activity.

Before any vessel is filled with water, the foundation design must be checked

to see if it is rated for this load.

Screens should be placed in the lines before the unit is pressure tested so

that test water can be pumped through the lines for the purpose of washing

them.

Screens should be placed in a flange between the suction valve and the pump

so that the screen may be removed without de-pressuring any vessels. The

flow through the screen should preferably be downward or horizontal.

Precautions should be taken to place the screen in a location where the dirt

particles will not drop into an inaccessible place in the line when the flow

through the pump stops. If this should happen, it would not be possible to

remove the dirt upon removal of the screen.

An air pressure test can be placed on the sections of the unit prior to a water

test so that any open lines or flanges may be discovered and taken care of

before liquid is admitted. It would be remembered that in pressure testing

vessels, the test gauge should be placed at the bottom of the vessel so that

the liquid head will be taken into account. Before draining any liquid from a

vessel, a vent must be opened on top of the vessel to prevent a vacuum from

pulling in the vessel sides.

In pressure testing equipment, particularly in cold weather, care should be

taken that the testing of the vessels is not carried out at temperature levels so low

that the metal becomes brittle. As metal temperatures decrease, the tending for

brittleness increases. Temperatures above 17°C (60°F) are considered

satisfactory for testing to eliminate the possibility of cold fracturing of equipment.

Such temperatures can be attained by warming the testing medium.

It will not be practical to test all of the equipment together. Thus, the unit will

be divided into sections as governed by the location of the various items of

equipment and the test pressures to which each item will be subjected. Suitable

blanks must be made up for insertion on nozzles and between flanges to isolate

the various sections of equipment as required. Normally, the exchangers,

receivers, etc., for the various towers will be tested together with the main

vessels. Test pressures will be determined from the pressure vessel summary

for the unit. During pressure testing, all safety valves must be blinded off since

their normal relieving pressure will be exceeded.

It may be convenient to test the heaters and reactors in one group. A field

hydrostatic test on the gas compressor after installation could result in damage to

the internals, so the compressors must be isolated from the reactor system. As

the heaters are normally tested at a higher pressure than the reactors, it would be

simplest to blind off the heaters and test them first and then test the entire system

at the reactor test pressure. Blanks can be provided with connections for

introduction of water for testing and for venting of air as the system is filled with

water. It may be necessary to use Thermowells connections and pressure taps

for additional vents in the reactor system. At the completion of the hydrostatic

test, all water should be removed from the equipment. Where necessary, flanges

may be broken to drain low points and the equipment air blown to remove as

much water as possible before flanging up.

After hydrostatic pressure testing, a tightness test must be conducted to

check all flanges and fittings, especially the ones opened during hydro testing.

This final tightness test must be witnessed by Licenser representatives and is

normally done just prior to start-up.

5.4.4 WASH OUT LINES AND EQUIPMENT After pressure test has been completed on any vessel with its connected

piping, receivers, exchangers, etc., required blanks are pulled and water is

circulated for the purpose of removing any dirt, scale, etc. Much of the dirt is

picked up in the pump screens where it is taken from the system by removing

and cleaning the screen.

All possible lines and pumps should be used during the washing procedure for

complete clearout of the system. Of course, no water circulation should be

carried out in the gas sections of the unit. Temporary water connections should be

provided at convenient locations in the system for carrying out water flushing. The

following points should be remembered during water flushing.

Low point drains and high point vents should be purged.

All instrument connection should be isolated, orifice plates removed, control

valves isolated and by-passed. In case there is no bypass, remove control

valve and flush the line. The valve will be installed after clean water starts

coming out and further flushing may be continued.

If there is any heat exchanger in the line, flushing should be done up to and

around the exchanger using by-pass line. It should be ensured that dirty water

from initial flushing does not get into the exchanger. Wherever bypasses are

not available, the flanged joints at the inlet of heat exchanger should be first

opened and the line flushed till clear water starts coming out. Then reconnect

flange and flush through the exchanger.

At each opening of the flanged joints, a thin metallic sheet should be inserted

to prevent dirty water from entering the equipment or piping.

The flow of water should preferably be from top to bottom for flushing of heat

exchanger coolers. The bottom flange of the equipment should be opened to

permit proper flushing.

The flushing should be carried out with maximum possible flow of water till

clear water starts coming out.

Vertical lines, which are long and rather big (say over 100-mm dia) should

preferably be flushed from top to bottom. This will ensure better flushing.

Filling the lines and releasing from bottom is also helpful. The rundown lines

can also be flushed conveniently from the unit to the respective tanks.

It should be ensured in all flushing operation that design pressure of lines and

equipment is never exceeded. After flushing of lines and equipment, water

should be thoroughly drained from all low points. Lines and equipment

containing pockets of water should not be left idle for a long time; it is

preferable to dry these lines and equipment with air after water flushing.

Recommended air/water velocity during flushing or blowing to be maintained for proper flushing

5.4.5 FUNCTIONAL TEST OF ROTATING EQUIPMENTAll rotary equipment (including dosing pumps) will undergo functional test to

check their performance.

a) MotorsEach motor should be checked and started to ensure that it has the correct

direction of rotation. The motor speed should be checked with tachometer to

ensure that RPM is correct. The manufacturer's lubrication schedule should be

used to ensure that all lubrication points have been serviced. After a short run

each bearing should be felt to ensure that it is free and not overheated.

b) PumpsPrior to unit start up, all centrifugal pumps should be thoroughly checked and

run in properly (after pressure testing and water flushing) as indicated in the

following outline: The pumps will be started and operated according to the

manufacturer’s instructions.

CAUTION: Many high head pumps are not designed to pump water. To do so can result in damage to the pump internals. Check the vendor’s specifications before attempting to run in pumps with water.

Check to see that all necessary water piping has been made to stuffing boxes,

bearing jackets, pedestals and quench glands. Make sure that all necessary

lube oil piping is installed, and that this piping is not mistakenly connected to

the water system.

Check arrangements to vent the pump for priming if the pump is not self-

venting. See that special connections such as bleeds and drains are properly

installed.

Check strainers in pump suction lines. Strainers must be installed before

aligning pumps. A 4-mm (three to five mesh) strainer is provided for each

pump suction line during start-up. To avoid pump damage during flushing

with water, the strainers should temporarily be lined with 1-mm (20-mesh)

screen.

Remove this screen after water flushing is completed. All strainers should be

flagged, and a list similar to the blind list should be kept, so as to prevent a

“lost” screen from plugging and upsetting unit operation later on.

Check that power is available for running in the pump. Check that pressure

gauges and any special instrumentation are in working order.

Water circulation on motor driven hydrocarbon pumps can result in motor

overloading if the full pumping capacity is used. In this type of equipment, the

capacity must be reduced by throttling the discharge during such periods. An

ammeter can be used to determine the required throttling.

Before lubricating oil-lubricated bearings, check bearing chamber in pumps to

see that no flushing compounds or shipping grease is left in the chamber.

Mechanical-type pumps should be flushed with water prior to pump operation

so no dirt gets into the seal and scores the seal faces.

It is extremely important that the proper type and viscosity oil and proper

grade of grease is used to lubricate the equipment. Refer to manufacturer’s

instructions and lubricating schedule for this information.

Motor should be checked and started to ensure that it has the correct direction

of rotation. The motor speed should be checked with tachometer to ensure

that RPM is correct. The manufacturer's lubrication schedule should be used

to ensure that all lubrication points have been serviced. After a short run each

bearing should be felt to ensure that it is free and not overheated.

See that the driver rotates the pump in the direction indicated by the arrow on

the pump casing. Rotate the pump by hand to see that it is clear before

starting.

Couple up and align the pumps, then check for cooling water availability and

start flow of cooling water to the pumps requiring external cooling, before they

are run in.

Open pump suction valve and close discharge valve (crack discharge valve

for high capacity, high head pumps). Make sure the pump is full of liquid.

Start the pump. As the pump is motor driven, the pump will come up to

speed. Immediately check discharge pressure gauge. If no pressure is

shown, stop the pump and find the cause. If the discharge pressure is

satisfactory, slowly open the discharge valve and give the desired flow rate.

Check the amperage of the motor. Do not run the pump with the discharge

block valve closed except for a very short time. Note any unusual vibration or

operation condition.

Check bearings of pumps and drivers for signs of heating. Recheck all oil

levels.

Run the pump for approximately one hour, then shut off to make any

adjustment necessary and check parts for tightness. Since it is not possible

to run the pump at operating temperature, a final check of alignment must be

made during normal operation by switching to the spare pump.

Start the pump and run it for at least four hours.

Shut the pump down and pull the strainer. Clean the strainer and replace it in

the suction line. Remove the temporary fine mesh liner from the strainer after

water flushing is complete.

On a new unit, the screens are sometimes left in service for the first run on all

locations where spare pumps have been provided.

When water is used for pressure testing and washing, it is sometimes better

to have packing in the pumps for a seal to prevent dirt from ruining the

mechanical seal.

After the lines and equipment are judged to be clean and all the pumps have

been run in, the water should be drained from the various systems. Lines

containing low spots should be broken at the low spot if no drain is provided.

Underground lines, without drains, should be blown free of water. Before

draining any vessel, a vent must be opened on that vessel so that a vacuum will

not be created on draining. If the towers are to be left standing for a long period

of time before steam drying or before operation, an inert gas, such as nitrogen or

sweet fuel gas, must be introduced to the vessels to prevent rusting of the

internals from oxygen in the air.

Of course, no water circulation should be carried out through the gas

compressors. It is important that the catalyst and the compressors are not

exposed to excessive moisture.

5.5 INSTRUMENTS CHECKINGNormally, instrument lead lines will be tested hydrostatically up to block

valves when the balance of the unit is tested. Hydrostatic test pressure will not be

made on instruments, which normally handle gas, and no pressure-measuring

element should be subjected to test pressures above its range. Also, never pull a

vacuum on a pressure instrument or gauge unless it is specifically designed for it.

All instrument air piping should be tested at 7kg/cm2g (100 psig) with compressed

air. Soap should be used on all joints to check for leakage. Care should be

taken to ensure that this high air pressure is not put on any instruments or control

valve diaphragms. Likewise, when pressure testing the unit, care must be taken

that the fuel gas pressure balance valves are blinded off to keep high pressure off

the diaphragm. Before starting up, all instruments should be serviced and

calibrated. This includes carefully measuring all orifice plate bores with a

micrometer.

A) Prior to unit start-up, all instruments must have been checked with regard to:

Proper tagging,

Proper location in the process,

Correctness of assembly,

Operating range consistent with the operating conditions,

Calibration,

Flow orifice size, coefficients, orientation versus flow,

Level instruments will be calibrated using the design liquid density,

Instrument wiring integrity, polarity, and grounding.

B) The following guidelines may be adopted for checking and calibration of all

instruments.

a) Orifice PlatesBefore each orifice plate is installed the orifice taps should be blown clear.

The plate should be callipered to check if the correct size orifice plate is installed.

The plate should then be installed after checking for the correct direction.

b) Differential pressure Transmitters and ReceiversOrdinarily these should be calibrated locally against a manometer. The

calibration should be checked at the receiver, which may be board or locally

mounted recorder or indicator.

c) Pressure Transmitters and ReceiversThese should be checked in place. The calibration of the receiver should be

checked at the same time.

d) Alarms checkingAll alarms, auto start and cut off systems should be checked by simulating the

conditions. Make sure that the field instruments actuate the corresponding light or

audible alarm in the control room or DCS printer.

e) ValvesThe control valves are removed during washing operations. They should be

checked for cleanness of the seats and free movement of the plug or ball.

Check the valves motion and their response to the controller signal.

When all the single instruments have been individually checked, when all

their addresses have been verified in the DCS, then the loop checking can take

place for each loop or group of control loops.

5.6 SAFETY DEVICES CHECKAll the safety devices, Interlock(s) and Emergency shutdown devices must

be checked. These devices are designed either to protect the catalyst against

mal-operation or to fulfil safety actions.

Safety sequences (Interlocks) are sequences of actions programmed into

the DCS/PLC and designed to ensure automatically a safe sequence of operation

when selected undesirable events occur.

5.7 HEATER REFRACTORY DRY-OUT AND REACTION SECTION DRY-OUT The furnace refractory must be thoroughly dried out so that it does not crack

when the Heater is brought into operation. The drying should be done by gradual

heating of the refractory so that no cracking takes place due to sudden

vaporisation of moisture from the refractory.

The refractory drying out of reactor feed heater can be done simultaneously with

the drying of the reaction section. Drying out can be done under air or nitrogen,

depending on the availability, using the recycle compressor.

Detail procedure is given in Annexure-I

5.8 PURGING AND GAS BLANKETINGIt must be remembered that oil or flammable gas should never be charged

into process lines or vessels indiscriminately. The unit must be purged before

admitting hydrocarbons. There are many ways to purge the unit and ambient

conditions may dictate the procedure to be followed: nitrogen or inert gas

purging, displacement of air by liquid filling followed by gas blanketing, or

steaming followed by gas blanketing.

For the remainder of the unit other than the reactor section, steam purging

followed by fuel gas blanketing can be used to air free the unit. The following

steps will briefly outline this method.Potential problems or hazards could develop

during the steam purge are as follows:

Collapse due to vacuum: some of the vessels are not designed for vacuum.

This equipment must not be allowed to stand blocked in with steam since the

condensation of the steam will develop a vacuum. Thus, the vessel must be

vented during steaming and immediately followed up with fuel gas purge at the

conclusion of the steam out.

Flange and gasket leaks: thermal expansion and stress during warm-up of

equipment along with dirty flange faces can cause small leaks at flanges and

gasket joints. These must be corrected at this time.

Water hammering care must be taken to prevent ‘water hammering” when

steam purging the unit. Severe equipment damage can result from water

hammering. Block in the cooling water to all coolers and condensers.

Shutdown fans on fin-fan coolers and condensers. Open high point vents

and low point drains on the vessels to be steam purge.

Start introducing steam into the bottom of the columns, towers, and at low

points of the various vessels. It may be necessary to make up additional steam

connections to properly purge some piping which may be “dead-ended.”

Thoroughly purge all equipment and associated piping of air. Be sure to

pen sufficient drains to drain condensate, which will accumulate in low spots and

receivers.

When purging is completed, close all vents and drains. Start introducing

fuel gas into all vessels and cut back the steam flow until it is stopped completely

when the systems are pressured. Regulate the fuel gas flow and the reduction of

steam so that a vacuum due to condensing steam is not created in any vessel or

that the fuel gas system pressure is not appreciably reduced.

5.9 TIGHTNESS TESTThe guideline given below is to check the tightness of flanges, joints,

manholes etc. (except pumps and control instruments) in the unit.

The initial leak tests can be performed using air or nitrogen depending upon local

facilities. The test pressure will be the air or nitrogen system pressure or the unit (or

section of unit) design pressure, whichever is the lower. This operation can be

integrated with steam purging activity aimed at expelling air (from feed, and Product

section) prior to introducing hydrocarbon into the unit.

The unit is isolated with blinds from adjacent sections containing hydrocarbons

(liquid or gaseous), and from utilities systems where pressure is lower than air

(or nitrogen) pressure.

The pressure rise must be checked on several pressure gauges and possibly

checked on a pressure recorder. Leaks must be carefully located and

tightened. Their location must be recorded. The leak test is satisfactory when the pressure decrease is lower than 0.05 Kg/cm2/hour over a period of 4 consecutive hours (at approximately constant temperature). Pumps,

compressors are to be isolated to prevent leak through seals.

The air (nitrogen) used for leak tests should be purged out of the unit using low

points drains to remove free water, if any.

In case of steam of steam purging:

Drains at low points will be opened; after draining is over, these will be closed.

Vent will be opened; pressure gauges will be installed on each circuit.

Steam is progressively admitted where connections are available. Circuits,

which do not have direct admission of steam, will be supplied through hoses.

The temperature of the whole installation is increased slowly and free expansion

of lines is checked. The condensed water is drained while the temperature of the

circuit rises.

When temperature is steady, vents are progressively closed in order to get the

desired pressure by keeping a vent slightly opened. A steam make-up is

maintained. All joints will be checked for leaks. If leaks are detected, system will

be depressurised, leaks attended and the system retested.

For the purpose of leak tests the unit will be divided into sections of

approximately the same design pressure. Air or nitrogen will be injected at

different locations depending on check valves locations.

Recommended sections for leak tests:A) Feed section Feed filters 75-X-01 A/B

Feed drum 75-V-01

This section will be isolated from the other sections by blinds and/or valves.

B) Selective hydrogenation reaction section SHU feed/HDS effluent heat exchanger 75-E-01 (tube side)

SHU feed/effluent heat exchanger 75-E-02 (tube and shell sides)

SHU preheater 75-E-03

Hydrogen from isomerization make-up compressor discharge

Feed exchangers bypass lines

Selective hydrogenation reactor 75-R-01

The selective hydrogenation reaction section is isolated from the other

sections by blinds and/or valves.

C) Splitter section Gasoline Splitter 75-C-01

Splitter reboiler exchanger 75-E-07

Splitter overhead air condenser 75-A-01

Splitter post condenser 75-E-04

Splitter reflux drum 75-V-02

Light FCC gasoline trim cooler 75-E-05

FCC heart cut cooler 75-E-06

SHU recycle air cooler 75-A-04

D) HDS section HDS Feed/Effluent exchangers 75-E-08 A/B/C (shell and tube sides).

HDS reactor 75-R-02

HDS reactor feed heater 75-F-01

SHU feed/HDS effluent exchanger 75-E-01 (shell side).

HDS effluent air condenser 75-A-03

HDS effluent trim condenser 75-E-09 A/B(shell side)

Separator drum 75-V-03

Amine K.O. drum 75-V-06

Amine absorber 75-C-02

Lean amine preheater 75-E-10 (shell side)

Recycle compressor K.O. drum 75-V-04

The HDS section shall be isolated from other sections by blinds or valves.

E) Stabilization section Stabilizer feed/bottom exchanger 75-E-11 A/B (tube and shell sides)

Stabilizer column 75-C-03

Stabilizer overhead condenser 75-A-05

Stabilizer reflux drum 75-V-05

Stabilizer reboiler 75-E-13

Heavy gasoline trim cooler 75-E-12 (shell side)

5.10 CATALYST LOADING PROCEDURE

Detailed catalyst loading procedure is given in Annexure-II

5.11 CATALYST SPECIAL PROCEDURE

Detailed procedure is given in Annexure-III

SECTION- 6 START-UP PROCEDURE

6.1 INTRODUCTION Start up and Operating Procedure are described in this section. Start up

and shutdown are the most critical periods in operation. It is then that the

hazardous possibilities for fire and explosion are greatest.

The hazards encountered most frequently in start up and shut down of units

are accidental mixing of air and hydrocarbons / hydrogen and contacting of water

with hot oil. Other hazards primarily associated with start up are pressure, vacuum

and thermal and mechanical shocks. These can result in fires, explosions,

destructive pressure surges and other damages to unit as well as injury to

personnel.

Fires occur when oxygen and fuel vapour or mists are mixed in flammable

proportions and come in contact with an ignition. They may run out of control or

touch off devastating explosion. Pressure surge from unplanned mixing of water

and hot oil may cause damage of equipment and or loss of valuable production.

Extensive, costly down time on process unit may result. Fires usually follow if the

explosion bursts lines or vessels.

Preparation for start-up begins with a complete review of the start up

procedure by the operating crew. Activities of Prime G+ unit should be co-

ordinated with control room, other units, and utility section.

6.2 PRE-START-UP CHECKLIST FOR PRIME G+ UNITa) Pre start-up checklist

Prior to actual start-up of the plant it should be established that all preparatory

works have been successfully completed and all equipment are ready to function.

Ensure that:

Blinds are installed as per master blind list. Each removal and insertion of a blind

should be noted and installed by the operator- in-charge.

All unnecessary blind are removed.

All construction tolls, debris are removed. Plant is cleaned.

All vessels, piping, equipment are pressure tested, flushed and ready for service.

All rotating equipment such as pumps, compressors, motors etc. have

undergone functional test successfully.

All instruments have been checked, calibrated and ready for service. Control

should be on manual.

All safety valves are in position after setting and testing. Isolating valves will be

left in lock open position. Spare valves should be kept isolated.

Necessary utility headers (cooling water, steam, air, fuel gas, fuel oil, water etc)

are charged.

Flare, closed blow down and sewer systems are in operable condition.

All related units are informed of the start-up plan.

All other pre-commissioning activities such as flushing, cleaning, purging,

tightness testing etc are completed.

Fire and safety related equipment are checked.

All safety devices and emergency sequences have been tested.

General Service system such as lighting, PA, telephone etc is in working

condition.

The proper quantity and quality of nitrogen is available.

The unit is under a slight nitrogen pressure.

The reaction section has been dried out.

The feed, splitter and stabilizer sections have been thoroughly drained of free

water.

Catalysts have been loaded into the reactors.

b) The unit is isolated with blinds:

On the feed and product lines,

On the flare and fuel gas headers,

On sour water lines to battery limits,

On the sewer lines and utilities except cooling water and nitrogen,

On pressure relief valves to flare.

On amine supply and return lines

H2 make-up lines are isolated.

Gasoline feed is available.

c) Inert naphtha is available with the following characteristics:

Bromine number < 5 g Br/100 g.

Diene Value< 0.5

Specific gravity between 0.725 and 0.850

ASTM D86 5%vol between 5°C and 70°C

ASTM D86 95%vol between 145°C and 225°C

Sulfur < 0.3 wt %

6.3 FIRST START-UPThe following describes the first start-up of a newly built unit. Any

subsequent start-up of the same unit may or may not include all of the following

steps, depending upon the status of the unit after the shutdown. For instance,

catalyst sulfiding will not be required if the catalyst was not regenerated or

replaced.

6.3.1 CHRONOLOGY OF START-UP OPERATIONSThe chronology of the various start-up tasks is shown on the attached

schedule. The duration has shown are those required to perform the tasks. The

time gap between two consecutive operations has not been taken into

consideration.

6.3.2 PURGING OF AIRa) General

The purpose of this step is to reduce the O2 content in all the sections below

0.2% by volume prior to the introduction of hydrogen or hydrocarbons.

The air can be eliminated by two methods:

a) By repeated filling and pressuring the system with nitrogen and then releasing

the air enriched in nitrogen to atmosphere until the oxygen content reaches

the required minimum value. This method will be used in reaction section and

in compressor section where humidity has adverse effect on equipment or

catalyst. The vacuum ejector installed in this section is used for decreasing

the number of purging and nitrogen refilling cycles.

b) By steam out and subsequent refilling the equipment with fuel gas. This

method will be used for all equipment where humidity and steam can not

deteriorate the equipment or catalyst.

Note: During steam out operation, Reaction section and Compressor section are isolated with blinds and filled with nitrogen. It is recommended to start filling with nitrogen on reaction section, SHU preheating section including.

b) Purging of air in Reaction Section This section involves the following equipment:

1. 75-R-01 Selective Hydrogenation reactor

2. 75-R-02 First HDS reactor

3. 75-E-02 SHU feed /effluent heat exchanger

4. 75-E-03 SHU feed pre heater

5. 75-E-08 A/B/C HDS feed/effluent heat exchangers

6. 75-F-01 HDS reactor feed heater

7. 75-E-01 SHU Feed/HDS effluent exchanger (shell side)

8. 75-A-03 HDS effluent air condenser

9. 75-E-09 HDS effluent trim condenser

10.75-V-03 Separator drum

11.75-V-06 Amine K.O. Drum

12.75-E-10 Lean amine preheater (shell side)

13.75-C-02 Amine Absorber

14.75-V-04 Recycle compressor K.O. Drum

The ejector (75-J-01) is connected to the vapor outlet line from the separator

drum. Isolate Reaction section with valves and blinds from remaining sections

of the Unit.

Isolate selective hydrogenation reactor (75-R-01) from Splitter (75-C-01) and

from SHU feed/HDS effluent heat exchanger (75-E-1001) (tube) and

interconnected to HDS reaction section by start-up vacuum line.

Ejector evacuation, nitrogen filling and pressuring are repeated until the

required oxygen concentration is reached (0.2% volume of O2)

Usually, no more than 3 purging operations are necessary to obtain

satisfactory results.

Recycle compressor must be isolated on suction and discharge lines. Purging

of compressor is usually done by repeated pressurizing with nitrogen and

releasing to atmosphere without use of vacuum which may affect the

compressor seals.

Also pumps connected to reaction system such as the quench pumps 75-P-06

will be isolated by block valves.

After air purge, the system is filled with nitrogen and kept under positive

pressure of 0.5 to 0.8 kg/cm² g until start-up and introduction of hydrogen.

c) Purging of air in Splitter and Stabiliser Sections The purging of air by repeated pressuring with nitrogen and releasing to

atmosphere can be done but it is time consuming operation due to volume of

involved equipment and also the demand in nitrogen is very large.

The steam out operation is commonly used.

Feed and Splitter SectionThis section involves the following equipment and interconnecting piping:

75-V-01 Feed surge drum

75-A-04 SHU recycle air cooler

75-C-01 Splitter

75-A-01 Splitter overhead air condenser

75-E-07 Splitter reboiler

75-V-02 Splitter reflux drum

75-A-06 Light gasoline air cooler

75-E-06 FCC heart cut cooler

75-E-05 Light FCC gasoline cooler

75-A-02 FCC heart cut air cooler

This section is isolated from the SHU and HDS reaction section by valves

and/or blinds. Isolate Pumps from the section by the valves at suction and

discharge and purged separately by nitrogen pressurizing/ depressurizing.

Stabilizer sectionThis section involves the following equipment and interconnecting piping:

75-C-03 Stabilizer

75-E-13 Stabilizer Reboiler

75-A-05 Stabilizer overhead air condenser

75-E-14 Stabilizer overhead trim cooler

75-V-05 Stabilizer reflux drum

75-E-11 A/B Stabilizer feed/bottom exchangers

75-A-07 Heavy gasoline air cooler

75-E-12 Heavy gasoline trim cooler

Isolated this section from the HDS reaction section by valves and/or blinds

Isolate Pumps from the section by the valves at their suction and discharge

and purged separately by nitrogen pressurizing/ depressurizing.

Eliminate air In the splitter and stabilizer sections by steam out and

subsequent filling with sweet fuel gas.

The start-up steam hoses for LP steam should be connected to the maximum

points, usually on suction-discharge of pumps, vessel bottoms. All vents on

columns reflux drums and other high points of lines should be opened. The air

coolers should be shut-down and cooling water circulation through coolers

and condensers stopped.

Introduced steam slowly to heat up slowly all parts of equipment/lines. Drain

the condensate at low points of piping and drums. The steam out operation

can be used for tightness test. This can be done by pressurizing the system

with steam and observing the flange connections to determine possible leaks.

The steam out operation for a period of 24 hours is usually sufficient to

eliminate air from the system. The steam out is followed by filling with fuel gas

or nitrogen. Ensure that fuel gas/Nitrogen is flowing without interruption and

positive pressure is maintained in all sections of the piping and equipment.

Note: Do not allow any part of the system to develop vacuum. This will result in introduction of air and danger of explosion.

6.4 START-UP PRELIMINARY OPERATION

6.4.1 UNIT STATUS The feed and splitter sections are under nitrogen or fuel gas pressure but

still isolated from the reaction section by the block valves.

The reaction sections are isolated and kept under nitrogen pressure.

The stabilizer and splitter are under nitrogen pressure or fuel gas pressure,

isolated from reaction section.

All blinds have been removed including those located on the start-up lines,

utilities, sewers, PSV's, etc.

The feed control valve is closed and blocked by inlet and outlet valves.

6.4.2 INERT NAPHTHA CIRCULATION (REACTION SECTIONS BY-PASSED)When starting-up the SHU and the HDS section, isolate the reaction section

and establish an oil circulation loop. This allows an efficient flushing of foreign

material from the equipment and liquid lines and a thorough checking of the

pumps, including standby's and instruments. Inert naphtha would be pumped

from storage, bypassing the reaction section to feed the splitter. See attached

block diagram.

a) Cold circulation in Splitter Put in service pressure control loop PIC-1601 on splitter reflux drum and

increase pressure in the system by introduction of nitrogen, set point as per

the Process Flow Diagram.

Start pumping inert naphtha from storage or from the upstream units and

establish a level in the feed drum (75-V-01).

Put in operation the level control of the feed drum LIC-1102.

When the level in the feed drum reaches 40%, start the feed pumps (75-P-01

A/B) and through the start-up lines that by pass the reactors, establish a level

in the splitter bottoms (75-C-01).

When the level in the splitter reaches 40%, start the HDS feed pump 75-P-02

A/B and open the FV-1103 to recirculate the naphtha back to the feed surge

drum via SHU recycle line.

Drain lines on low points to eliminate water and remove foreign materials from

lines and equipment.

Provide cleaning of pumps strainers.

During the circulation it is good practice to switch to the standby's to check out

both pumps.

b) Cold circulation in StabilizerThe circulation of naphtha is recommended through Stabilizer in order to

provide flushing of the system and checking of pumps operation and instruments.

The circulation circuit should be established from HDS feed pumps (75-P-02A/B)

to the stabilizer (75-C-03) through the filling line and then back to the feed drum

via the recirculation line.

Close the block valves routing the naphtha to 75-E-01 and UV-1901 with its

block valve to 75-E-08, at the same time open the startup filling line valves.

When the level is established in stabilizer reflux drum (75-V-05) at around

50% start the stabilizer reflux pump (75-P-09 A/B) and start filling the

stabilizer (75-C-03).

Let the stabilizer pressure floating at flare pressure

Admit more inert naphtha into the unit to make the level in the stabilizer

bottoms reach 40%.

When the bottoms level has reached 40%, start to recirculate the naphtha

back to the feed drum via the recirculation line.

Stop the inert naphtha feed to the feed surge drum.

Adjust the circulation at a rate of 60% of design throughput.

Drain lines on low points to eliminate water and to remove foreign matters

from lines and equipment. Provide cleaning of pump strainers.

Note:

1. During the circulation it is good practice to switch to the standby's to check out both pumps.

2. During the circulation minimum flow line of pumps must be kept in line.

Naphtha feed :10”-P-75-1101-A9A-IH

A 10”-P-75-1110-A9A-IH g) 6”-P-75-2414-B9A

a) 10”-P-75-1104-A9A-IH h) 6”-P-75-1807-B9A-IH

b) 6”-P-75-1210-D9A-IS i) 4”-P-75-3105-A16A

c) 10”-P-75-1602-A9A j) 3”-P-75-3107-A16A

d) 6”-P-75-1209-B9A-IS k) 8”-P-75-3002-A9A-IH

d

g

V-01 P-01A/B V-02 P-03A/B

C-01

P-02A/B

V-05

P-09A/BC-03P-07A/B

E-11A/BE-12A/B

Start-up Naphtha a b c

e

fh

i

Jkl

m

X-01 A

n

e) 8”-P-75-1605-A9A l) 8”-P-75-3004-B9A-IH

f) 10”-P-75-1506-A9A-IH m) 6”-P-75-2912-A9A

n) 6”-P-75-1908-B9A

Schematic Naphtha circulation circuit is given in the attachment

6.4.3 START-UP OF HOT NAPHTHA CIRCULATION IN SPLITTER AND STABILIZER In order to prepare the unit for start-up with fresh feed it is recommended to put in

operation splitter and stabilizer.

This operation enables to commission instruments, air condensers, coolers and

Reboiler.

a) Splitter start-up at total reflux Commission Splitter overhead air condenser (75-A-01A~D)

Start Splitter Reboiler (75-E-07)

Do not increase the Reboiler outlet temperature too rapidly. Increase the

inventory temperature in the splitter very slowly so that trapped water, or

water that is emulsified in the start-up naphtha, has time to change state

(water to steam) in as controlled a manner as possible. It is recommended to

hold the Reboiler outlet temperature at 150°C for some time.

Increase Splitter’s bottom temperature at a rate of 30°C per hour up to 180°C

to 200°C, depending on distillation range of used inert naphtha and operating

pressure.

Commission temperature control loop TIC-1501.

As soon as the level in the reflux drum is established, start the reflux pumps

(75-P-03 A/B) and commission level and flow instruments on the reflux line,

(LIC-1601 and FIC-1601 respectively). The light FCC gasoline draw off and

the FCC heart cut draw off are closed.

The splitter is left operating at total reflux for several hours as necessary to

commission all involved equipments and instruments.

The pressure in the reflux drum must be kept at constant value by injecting N2

at the reflux drum if necessary.

Shutdown the splitter Reboiler heater while keeping circulation until the

temperature decreases in the splitter column bottom to 50°C. Splitter should

be kept under pressure with nitrogen.

b) Stabilizer at total reflux Put in service pressure control loop PIC-3101 on stabilizer reflux drum.

Commission the overhead air condenser 75-A-05 and overhead trim cooler

75-E-14 with set point as per the Process Flow Diagram. Pressurize with

nitrogen.

Start stabilizer Reboiler (75-E-13)

Do not increase the Reboiler outlet temperature too rapidly. Increase the

inventory temperature in the stabilizer very slowly so that trapped water, or

water that is emulsified in the start-up naphtha, has time to change state

(water to steam) in as controlled a manner as possible. It is recommended to

hold the Reboiler outlet temperature at 150°C for some time.

Increase temperature on stabilizer bottom at a rate of 30°C per hour up to

150°C to 180°C depending on distillation range of used inert naphtha and

actual operating pressure in the column.

As soon as the level is established in Stabilizer reflux drum (75-V-05), start

the Stabilizer reflux pumps (75-P-09 A/B) and commission level and flow

instruments on the reflux line (LIC-3102 and FIC-3001).

Keep constant the pressure in the stabilizer by admission of nitrogen.

Adjust a make up of inert naphtha coming from the splitter to fill the stabilizer

bottoms and the stabilizer reflux drum at 60 % of the design throughput.

The stabilizer (now isolated from the splitter) is left operating at total reflux for

several hours as necessary to commission all involved equipments and

instruments.

Shutdown the stabilizer heater while keeping circulation until the temperature

decreases in the stabilizer column bottom to 50°C. Stabilizer should be kept

under pressure with nitrogen.

6.5 PRESSURIZATION OF THE REACTION SECTIONS AND HYDROGEN LEAK TESTS

6.5.1 UNIT STATUSThe reaction sections are still under nitrogen pressure. Selective

hydrogenation and HDS reaction sections have to be filled with hydrogen. The

selective hydrogenation reactor (75-R-01) is isolated from naphtha circuit by

block valves on the feed valve FV-1201 and on the reactor outlet PV-1501 and

PV 1401.

HDS feed/effluent heat exchangers (75-E-08 A~C),

First HDS reactor (75-R-02),

HDS Reactor feed Heater (75-F-01),

Air condenser (75-A-03 A/B),

Trim cooler (75-E-09 A/B),

Separator drum (75-V-03),

Amine absorber (75-C-02),

Amine Preheater (75-E-10),

Recycle compressors KO drum (75-V-04) and

Recycle compressors (75-K-01 A/B)

are isolated from naphtha circuit and stabilizer by the following block valves

- Feed valve FV 1901, and UV-1901

- On UV 2401 and block valves of FV 2402

- and H2 make-up line to 75-V-04 Recycle compressor KO drum (on FV-2701 &

FV-2702).

6.5.2 H2 INRODUCTION IN SHU SECTION Gradually introduced H2 through the H2 makeup line to 75-E-01.

Increased the pressure up to 7 Kg/cm2/g.

Carry out the leak test at this pressure on all flange joints, couplings, valves.

The test duration is minimum 4 hours. The checking of tightness should be

checked with explosive meter. The pressure drop should not exceed 0.05

Kg/cm2/h.

6.5.3 H2 INRODUCTION IN HDS SECTION Gradually introduced H2 through the make-up hydrogen line to Recycle

compressors KO drum (75-V-04) (by-pass of recycle compressor 75-K-01 A/B

should be opened), and then to other lines and equipment involved in the

HDS reaction section.

Increased the pressure up to 7 Kg/cm2/g at the first step.

Carry out the leak test at this pressure on all flange joints, couplings, valves.

The test duration is minimum 4 hours. The checking of tightness should be

checked with explosive meter. The pressure drop should not exceed 0.05

Kg/cm2/h.

Once all leaks have been tightened, resume hydrogen injection and

pressurize up to the normal operating pressure.

Perform a final leak test (two hours).

Commission the reaction section pressure controller PIC-2409.

Close the by-pass of 75-K-01 A/B.

Start the recycle compressor 75-K-01A/B and circulate hydrogen through the

reaction section.

6.6 CATALYST SULFIDING – DRY SULPHIDINGThe metals of the catalysts HR-845, HR 806, as delivered are in the oxide

form. As the active catalytic component is the metal sulfide, the catalysts must

therefore be sulfided. DMDS, which thermally decomposes into H2S, is used for

this purpose.

It is important that sulfiding of the catalyst metal is complete. If not, the

catalyst metals convert to their reduced form (metal) which could lead to metal

sintering resulting in agglomeration and consequently poor activity due to a

decrease in metallic area. In addition, the reduced metals will act as

hydrocracking catalysts with the gasoline and could cause local overheating and

heavy coke deposits.

The sulfiding of HR-845 catalyst in the Diolefin Reactor, HDS catalyst in first

HDS reactor should be performed separately.

Ensure there is adequate supply of DMDS for each catalyst, the facilities are

operational and the pump is calibrated. Remove the blind on the injection line

but keep blocked in.

Both recycle gas compressors 75-K-01 A/B (one for SHU reactor) need to be

operated in order to get sufficient flow through catalytic bed.

6.6.1 SULFIDING OF HR-845 CATALYST IN THE DIOLEFIN REACTOR (75-R-01)The sulfiding flow scheme for the SHU Reactor catalyst is:

Recycle compressor (75-K-01 A&B) ® HDS feed / effluent exchangers shell side ® Heater (75-F-01) ® SHU reactor (75-R-01) ® HDS feed / effluent exchangers tube side ® HDS effluent air condenser (75-A-03) ® HDS effluent trim cooler (75-E-09)® Separator drum (75-V-03)® Recycle compressor KO drum (75-V-04) ® Recycle compressor (75-K-01 A&B). The recycle compressor is operating with Hydrogen at lower pressure than

the normal operating pressure.

HP Amine Absorber (75-C-02), is isolated and its by-pass open.

6.6.2 SULFIDING OF HR-806 CATALYST OF FIRST HDS REACTOR (75-R-02)Unit status is:

The SHU Reactor (75-R-01) sulfiding is complete.

The recycle gas compressor is operating with Hydrogen at normal operating

pressure.

Amine Absorber, 75-C-02, is isolated and its by-pass open.

The sulfiding flow scheme for the first HDS reactor catalyst is:

Recycle compressor 75-K-01 A&B ® HDS feed / effluent exchangers shell side ® Heater 75-F-01 ® First HDS reactor 75-R-02 ® HDS feed / effluent exchangers tube side ® HDS effluent air condenser 75-A-03 ® HDS effluent trim cooler ® Separator drum 75-V-03 ® Recycle compressor K.O. drum 75-V-04 ® Recycle compressor 75-K-01 A&B.

6.6.3 SULPHIDING PROCEDUREThe sulphiding procedure is the same for both catalysts HR 845, HR 806 is as

described below:

Ensure that 75-E-01 has not been filled by mal-operation with SR Naphtha

during cold circulation. Open the bypass of the exchanger and isolate it.

Isolate and bypass of the Amine Absorber.

Start recycle compressor to circulate hydrogen in the reaction section at

maximum flow rate.

Fire the HDS reactor heater 75-F-01 and increase the reactor inlet

temperature up to 180°C at a rate of 30°C/h.

Start the sulfiding agent injection at the inlet line of reactor (outlet of sulfiding

agent pump). Adjust the injection flow rate.

Increase the reactor inlet temperature up to 220°C.

Keep these conditions. After 3 hours at 220°C, check every hour at least the

H2S content of the recycle gas. Normally H2S appears after 3 to 5 hours

from the beginning of sulfiding agent injection.

When the H2S breakthrough occurs (H2S > 0,2 % vol.) or after four hours at

220°C, whichever is the later, continue the sulfiding agent injection and

increase the reactor inlet temperature up to 315°C at a rate of 30°C/h.

Hold this temperature for a minimum of 4 hours.

During sulfurization: The reactor DT must not exceed 30°C. Should it happen, decrease the

sulfiding agent injection.

From the actual recycle gas flow and the sulfiding agent injection, one can

calculate the H2S percent volume at reactor inlet which should be within 0.5%

to 1%. If required, adjust the sulfiding agent injection to match this range.

The sulfurization reactions produce water and the amount of water recovered

in the separator confirms the progress of the sulfurization. Drain the separator

when necessary.

Note: Proceed with caution, since the water is saturated with H2S.

The decomposition of sulfiding agent (DMDS), in addition to H2S, gives

butane which accumulates in the recycle gas. A purge of the reaction section

and a make-up of hydrogen could be necessary to keep the recycle gas

hydrogen purity above 50% volume.

Stop the sulfiding agent injection when the required amount is reached.

However proceed to intermittent injections if the H2S content in the recycle

gas was to fall below 0.5% volume.

Then:

Check that the H2S contents inlet and outlet of the reactor are equal.

Check that an injection of sulfiding agent results instantaneously in an

increase of the H2S content in the recycle gas.

The catalyst sulfurization is then considered as completed. Decrease the

reactor inlet temperature down to 100°C at a rate of 30°C/h.

At 100°C, stop the HDS heater 75-F-01.

Remark: During sulfiding operation, the recycle gas is highly toxic and flammable owing to its H2S content. It must not be vented to atmosphere. The operators must be equipped with H2S protective masks when checking the H2S content. Access to the unit must be forbidden to non-operating personnel.

6.7 UNIT START-UP6.7.1 UNIT STATUS

The sulfiding of the all the reactors is completed.

The H2 recycle are flowing through the HDS Reactor.

Recycle gas rate is set at 100% of design value.

The Diolefin (SHU) Reactor is under hydrogen gas pressure.

The Stabilizer is under N2 atmosphere.

The Splitter is under N2 atmosphere.

Filling up of the SHU reactor

The procedure is as followed : 1. Line up from SHU feed pumps (75-P-01 A/B) to SHU reactor (75-R-01) via 75-

E-01 tube side, 75-E-02 tube side, 75-E-03 tube side.

2. Open all valves and blind from 75-R-01 bottom up to PV-1404, which is kept

closed but can be operated if needed.

3. Open slowly safety valve PSV-1401 bypass located at top of 75-R-01 reactor.

This is to allow flaring of the gas while filling up the system.

4. Crack open the globe valve located on the bypass of FV-1201 and start filling

and pressurising the SHU preheating system and reactor. Proceed slowly in

order to soak efficiently the catalyst bed. (SHU reactor pressure should be

controlled at least 2 to 3 Kg/cm2 below the normal operating pressure in

order to avoid risk of overpressure during filling up).

5. When the pressure in the reactor reaches the pressure of the system, open

completely the bypass globe valve of the PSV-1401 in order to flare hydrogen

and complete the filling.

6. When the hissing of the gas escaping through the PSV-1401 bypass stops,

the filling of the reactor is over.

7. Close the bypass of the reactor PSV-1401, but keep the filling globe valve

slightly open to maintain the pressurisation with 75- P-01 A/B.

8. Maintain these conditions for 4 hours in order to soak the catalyst. Check and

confirm that no gas remains at the top of the reactor using the PSV-1401

bypass.

6.7.2 LINING UP OF THE SHU REACTION SECTION Commission the pressure controller, PIC-1501, at the outlet of reactor 75-R-

01. Put on auto at a setpoint.

Pressurize the Splitter to 6 kg/cm2g using nitrogen and put PIC-1601 on auto

at a setpoint of 6.0 Kg/cm2g.

Commission the Splitter Overhead Air Condenser (75-A-01A~D), Splitter

Reboiler (75-E-07), Light FCC gasoline cooler (75-E-05A/B) and the splitter

post condenser (75-E-04A/B).

Commission the FIC-1203 ratio control loop on hydrogen make-up line. Start

to inject H2 at the nominal SOR H2/HC flowrate.

Circulate through the reactor in once through mode (no recycling) until the

sample collected at splitter bottom is found clear (no more scales or catalyst

fines). The splitter bottom is sent to stabilizer (via pumps 75-P-02 A/B) from

where it is sent to slop/off spec.

Gradually increase the operating temperature in the reactor at a rate of 20°C

per hour by increasing steam flow rate to SHU Reactor heater (75-E-03) to

reach the required SOR temperature.

Re-start splitter (75-C-01).

Put in operation the pressure controller in the splitter overhead system by the

pressure control loop PIC-1601. Ensure that Hydrogen make-up gas sent to

the reaction section should be sufficient to keep pressure in the splitter, if not,

N2 can be used.

Draw-off of light cut and heart cut is closed. When SHU effluent is found clear,

start routing splitter bottoms to the feed surge drum via the hydrogenated

naphtha recycle line through SHU recycle air condenser (75-A-04).

Since SHU feed is also preheated via 75-E-02 SHU feed/splitter bottom

exchanger, decrease 75-E-03 steam preheater duty as much as possible

while maintaining SHU inlet SOP temperature.

Wait until all temperature(s) indicators in the reactor give a steady indication

and maintain this circulation for 6 hours.

6.7.3 LINING UP OF THE HDS REACTION SECTION By using 75-P-02 A/B send inert naphtha to HDS reaction section.

Commission FV-1901 control valves and flow controller FIC-1901. As flow is

increased to HDS section, reduce bypass flow from splitter to stabilizer (as set

during SHU section lining up).

The inert naphtha is then routed to the HDS Feed/Effluent Exchangers (75-E-

08 A/B/C) shell side, First HDS reactor (75-R-02), HDS Reactor heater (75-F-

01), , HDS Feed/Effluent Exchangers (75-E-08 A/B/C) Tube side, SHU reactor

feed / HDS effluent exchanger (75-E-01), HDS effluent air condenser (75-A-

03A/B/C/D), Reactor effluent trim cooler (75-E-09A/B) and to the separator

drum (75-V-03).

When the level in the separator drum (75-V-03) has reached 40%,

commission the level flow control instrument FIC-2402 and LIC-2404.

Start injecting wash water upstream of the reactor effluent air cooler. When a

water interface is appeared in the separator boot, commission the interface

level controller LIC-2401 and check it operates correctly.

At this step, check the proper functioning of instrumentation, control valves

and pumps.

The recycle compressor remains in operation and hydrogen gas is recycled

through the HDS feed/effluent exchangers (75-E-08 A/B/C shell side), First

HDS reactor (75-R-02), HDS reactor heater (75-F-01), HDS feed/effluent

exchangers (75-E-08 A/B/C tube side), SHU feed / HDS effluent exchanger

(75-E-01), HDS effluent air cooler (75-A-03), Reactor effluent trim cooler (75-

E-09), Separator drum (75-V-03) and the Recycle compressor KO drum (75-

V-04). Keep the Amine KO drum (75-V-06) and Amine Absorber (75-C-02) still

bypassed.

The pressure in HDS reaction section separator should be maintained at

approximately 15 Kg/cm2g by hydrogen gas make-up. Recycle compressor is

operating at full load.

Light burners of HDS reactor heater (75-F-01) and commission control loops

on reactor

Gradually increase the operating temperature of the HDS reactor at a rate of

30°C per hour in order to reach 180° C.

6.7.4 INERT NAPHTHA CIRCULATION After the commissioning of FIC-2402, inert naphtha is sent to Stabiliser

column (75-C-03).

Re-start to Stabiliser column (75-C-03).

An open loop circulation through the HDS reactor at 150-200° C will allow an

efficient cleaning of the reactor as the naphtha will be mainly in liquid phase.

This naphtha circulation in open loop has to be done with H2 circulation and

gradual warming of the reactor. After 4 hours of open loop, naphtha should be

circulated in close loop.

Send inert naphtha back to the SHU feed surge drum (75-V-01) from the

bottom of stabiliser via recirculation line. Commission flow controller FIC-

2901.

Commission SHU feed pumps (75-P-01 A/B) for a continuous use in the

overall inert naphtha circulation around unit in order to reach 60% of the

design unit capacity.

Line up Amine Absorber with other equipment of the HDS reaction section,

which is currently filled with hydrogen.

Open the Lean and Rich amine block valves at B.L and start circulation of

solution through the HP Amine Absorber. Allow the HP Amine Absorber to fill

until a level is established at the bottom. Commission the level control loop,

LIC-2601, as well as flow control loops on the lean amine FIC-2501. The

recycle gas is gradually circulated through the absorber by cutting back on the

bypass gas stream.

6.7.5 FCC GASOLINE FEED After establishing smooth operating conditions with inert naphtha, the unit is

ready for introduction of FCC gasoline.

Start introduction of light gasoline from the FCC unit to SHU feed surge drum

(75-V-01) at approximately 10% of the normal flow rate through FIC-1201. At

the same time reduce the recirculation rate from the 75-V-01 by the same

amount.

Adjust the make-up hydrogen gas as necessary to keep the pressure in the

Splitter and SHU Reactor at the normal operating values.

Ensure that the pressure difference between the reactor and the Splitter is

maintained through pressure control loop (PIC-1501).

Gradually increase the flow of raw FCC light gasoline to the feed surge drum

75-V-01, by increments of 10% of the normal flow rate. In the same

proportion, decrease the recirculation of naphtha from cooler 75-E-12 to the

feed surge drum (75-V-01). Excess naphtha is sent to off-spec storage tank.

Stabilize operating conditions after each increase of FCC light gasoline in the

feed.

Watch carefully the temperature gradient on the reactors. Decrease the inlet

temperature to the reactors if the temperature rise is too fast.

If there is no temperature rise in the reactors, increase the reactor inlet

temperature in steps of 2°C maximum.

Monitor the temperature rise on each catalyst bed.

Adjust the operating conditions according to the analysis of the product

(MAV).

The Gasoline Splitter (75-C-01), light FCC gasoline draw-off, is put into

operation when the column top temperature reaches the design value and

reflux drum (75-V-02) liquid level is stabilized.

The FCC heart cut gasoline draw-off is put into operation if required (high

benzene content in FCC feed) when TIC-1502 reaches the operating value.

Gasoline should be sent to slop if it is not on-specification.

Once draw-off has started, start to add FCC gasoline to the SHU feed surge

drum (75-V-01).

The Stabilizer is operated with vapor distillate product only. The condensate is

returned to the column as reflux. The RVP of Hy. Gasoline and the H2S

stripping required to be monitored to define the proper operating pressure and

Reboiler temperature in the column.

Send off-spec Hydrotreated gasoline to slop until it is on-specification.

When the product is on-specification slowly increase unit feed flow rates in

steps of 5% up to 100%.

System is now ready for normal operation.

SECTION- 7 NORMAL OPERATING PROCEDURE

7.1 GUIDELINES FOR NORMAL OPERATION

This section deals with normal operating procedures of Prime G+ Unit

7.2 INTRODUCTIONNormal operation implies that the unit is lined out at the desired capacity

and the products meet the required specifications. However it is possible, to

optimize the unit so that utility consumption is reduced. This is accomplished by

adjusting the parameter while maintaining the desired product qualities. The

reflux flow rate and the heat input to the column are directly related as discussed

in process description section.

7.3 OPERATING PARAMETEROperating Conditions and Parameter are given in the table below.

S. No.

Description Tag no. Unit Value

1.FCC Gasoline from FCC unit to SHU FEED

SURGE DRUM.TI-1101 o C 70

2. SHU Feed Surge Drum PIC-1101 Kg/cm2g 3

3. FCC Gasoline feed to SHU feed surge drum. FI-1101 M3/hr 163.5

4. FCC Gasoline Feed to SHU Feed Surge Drum FIC-1102 M3/hr 163.5

5.FCC Gasoline from storage to SHU FEED

SURGE DRUMTI-1103 o C 40

6.Recycle Heavy Gasoline from SHU recycle air

CondenserFIC-1103 M3/hr *

7.Cold Gasoline feed from storage to SHU feed

surge drumFIC-1104 M3/hr 157.0

8.Mixed stream of FCC Gasoline from FCC unit &

Storage to SHU FEED SURGE DRUMTI-1105 o C 40

9. FCC Gasoline cold feed filters PDI-1106 Kg/cm2g 0.3

10.Gasoline from SHU FEED PUMP to SHU

FEED/HDS Effluent ExchangerTI-1201 o C 40-70

11. Gasoline SHU Feed FIC-1201 M3/hr 163.5

12. Gasoline after SHU feed pumps. FIC-1202 M3/hr 163.5

13.Gasoline mixed with H2 to SHU FEED/HDS

Effluent ExchangerTI-1203 o C 66

S. No.


14. H2 to SHU section FIC-1203 Nm3/hr 1513

15.H2 from Isomerisation Make-up Compressor

DischargeTI-2701 o C 40

16.Gasoline & H2 stream from SHU FEED PUMPS

to SHU FEED/HDS Effluent ExchangerPI-1206 Kg/cm2g 36

17.Gasoline bypass before SHU Feed/HDS Effluent

ExchangerFIC-1204 M3/hr 31.3

18.Gasoline & H2 stream from SHU FEED PUMPS to

SHU FEED/HDS Effluent ExchangerPI-1206 Kg/cm2g 33.4

19.Gasoline & H2 after SHU Feed/HDS Effluent

ExchangerPI-1207 Kg/cm2g 32.9

20.Gasoline & H2 stream before & after 1ST SHU

Feed/HDS Effluent ExchangerPDI-1208 Kg/cm2g 0.4

21.Gasoline & H2 at the inlet of SHU

FEED/EFFLUENT EXCHANGERTI-1301 o C 65-162

22. VHP condensate from SHU Preheater FIC-1301 M3/hr 15.4

23.Reactor Effluent (Gasoline & H2) after passing

through SHU FEED/EFFLUENT EXCHANGERTI-1302 o C 162-189

24.Gasoline & H2 stream before & after SHU

Feed/Effluent ExchangerPDI-1302 Kg/cm2g 0.4

25. Gasoline & H2 stream before SHU Preheater PI-1303 Kg/cm2g 32.4

26.Reactor feed from SHU FEED/Effluent Exchanger

to SHU PreheaterTI-1304 o C 86-189

27.Reactor feed from SHU Preheater to SHU

ReactorTI-1305 o C 160-200

28. VHP steam inlet to SHU Preheater PI-1306 Kg/cm2g 31.9-37.6

29.Reactor feed from SHU FEED/Effluent Exchanger

to SHU PreheaterTI-1303 o C 189

30. Gasoline & H2 stream after SHU Preheater PI-1307 Kg/cm2g 32

31.Gasoline & H2 stream before & after SHU

PreheaterPDI-1308 Kg/cm2g 0.4

32. Reactor feed stream before & after the Preheater TDIC-1306 o C 5-74

33.Reactor feed stream from SHU Preheater to SHU

ReactorTIC-1401 o C 160-200

34. Gasoline & H2 stream by pass to SHU Reactor PDIC-1401 Kg/cm2g 0.8

35.A Bypass line of reactor feed stream to SHU

reactorTIC-1402 o C 160-200

S. No.


36.Gasoline & H2 stream Inside SHU Reactor on the

first bed of catalystTI-1403 o C 160-219

37.Gasoline & H2 stream before entering SHU

ReactorPI-1403 Kg/cm2g 30



39. Gasoline & H2 stream by pass PI-1404 Kg/cm2g 30



41. Gasoline & H2 stream by pass PI-1405 29

42.Gasoline & H2 stream after passing through the

1st bed of catalyst in SHU ReactorPI-1407 Kg/cm2g 30

43.

Gasoline & H2 stream before entering SHU

Reactor & after passing through the 1st bed of

catalyst in SHU Reactor

PDI-1408 Kg/cm2g 0.5

44. SHU Reactor Effluent PI-1409 Kg/cm2g 28

45.Gasoline & H2 stream after 1st bed of catalyst in

SHU Reactor & Effluent from SHU reactorPDI-1410 Kg/cm2g 0.5

46. SHU Reactor Effluent PI-1411 Kg/cm2g 28


second bed of catalystTI-1407 o C 160-219





50. Effluent from the SHU Reactor TI-1415 o C 160-219



53. Gasoline & H2 stream inside the Splitter TIC-1501 o C 107-117

54. SHU Reactor Effluent to Gasoline Splitter PKIC-1501 Kg/cm2g 6.3

55. VHP Steam to Reboiler Splitter FIC-1501 M3/hr 26.7

56. Gasoline & H2 stream inside the Splitter TIC-1502 o C 139-142

57. SHU Reactor Effluent to Gasoline Splitter PI-1502 Kg/cm2g 6.3

58. Heavy Naphtha at the bottom of Gasoline Splitter LIC-1502 Mm *

59.Inert Naphtha in Start-up filling line from SHU

Feed pump to Splitter inletFI-1502A/B M3/hr *

S. No.


60.Heavy naphtha from the splitter bottom to HDS

sectionTI-1504 o C 174-181

61. Splitter overhead i.e. Gasoline vapour PI-1505 Kg/cm2g 6

62.Inside the Splitter column above the heart cut

naphtha plate at 37th trayPI-1507 Kg/cm2g 6.2

63. Reboiler outlet to Splitter bottom TI-1507 o C 218-221

64.Inside the Splitter column above the feed plate at

20th trayPI-1508 Kg/cm2g 6.5

65. Splitter outlet to Reboiler inlet TI-1508 o C 214-217

66. Inside the Splitter column below 1st tray PI-1511 Kg/cm2g 6.5

67.Gasoline & H2 stream on the 19th tray inside the

Splitter columnTI-1505 o C 181-199

68. Splitter overhead & splitter underflow PDI-1506 Kg/cm2g 0.5

69. Gasoline & H2 stream to the Splitter Feed TI-1504 o C 122-160

70. Light gasoline vapor in splitter reflux drum PIC-1601 Kg/cm2g 5.5

71. Splitter overhead (vapor gasoline) TI-1602 o C 93-97

72.Splitter overhead to Splitter Reflux drum after

Splitter overhead air condenserTI-1603 o C 55

73.Fuel gas from Splitter Reflux Drum to Fuel gas

headerTI-1605 o C 40

74. Fuel gas to FCC inlet PI-1610 Kg/cm2g 4.5

75. Splitter overhead to splitter reflux drum PI-1603 Kg/cm2g 5.5

76. Light FCC Gasoline to MS POOL TI-1706 o C 40

77.Light Gasoline from Accumulator tray no.48 of

SplitterPI-1703 Kg/cm2g 7.6

78.Light Gasoline after light gasoline cooler to light

gasoline MS POOLPI-1704 Kg/cm2g 7.7

79. FCC HEART CUT GASOLINE TI-1702 o C 65

80.FCC Heart cut gasoline from accumulator tray

no.36PI-1707 Kg/cm2g 7.6

81.FCC Heart cut gasoline after FCC Heart cut

cooler to storagePI-1714 Kg/cm2g 7

82.FCC Heart cut gasoline after FCC Heart cut

cooler to storageTI-1713 o C 40

83.Light Gasoline to storage after light gasoline

coolerPI-1710 Kg/cm2g 7

S. No.


84.Gasoline & H2 at the inlet of First HDS Feed /

Effluent ExchangerPI-1901 Kg/cm2g 23.5-30

85.HDS feed & HDS recycle to HDS feed / effluent

exchanger.TI-1901 o C 148-176

86. Vapor gasoline to HDS feed PI-1904 Kg/cm2g 22-28.5

87.

Gasoline & H2 at the inlet of 1st HDS Feed/Effluent

Exchanger & at the outlet of 3rd HDS

Feed/Effluent Exchanger

PDI-1905 Kg/cm2g 1.2

88.

HDS feed from First HDS Feed/Effluent

Exchanger to second HDS Feed/Effluent

Exchanger

TI-1902 o C 210-240

89.HDS feed from second HDS Feed/Effluent

Exchanger to third HDS Feed/Effluent ExchangerTI-1903 o C 242-271

90.Gasoline & H2 at the outlet of 2nd HDS

FEED/EFFLUENT ExchangerPI-1903 Kg/cm2g 22.5-29

91.HDS Reactor Effluent after 3rd HDS Feed/Effluent

ExchangerPI-1904 Kg/cm2g 22-28.5

92.HDS rector effluent from HDS feed/effluent

exchanger tube side outlet.TI-1906 o C 207-227

93.HDS rector effluent from HDS feed/effluent

exchanger tube side outlet.PI-1908 Kg/cm2g 16.3-22.8

94.Heavy FCC Gasoline after 3rd HDS Feed/Effluent

Exchanger to first HDS ReactorTIC-2001 o C 275-312

95.Heavy FCC Gasoline before entering first HDS

ReactorPI-2001 Kg/cm2g 22.9

96.Heavy FCC Gasoline after third HDS

Feed/Effluent Exchanger to first HDS ReactorTI-2002 o C 275-312

97.Heavy FCC Gasoline before entering first HDS

ReactorPI-2002 Kg/cm2g 22.9

98.On the First bed of catalyst inside first HDS


99.Liq. Gasoline on 2nd bed of catalyst in 1st HDS

ReactorPDI-2006 Kg/cm2g 0.5

100.On the First bed of catalyst inside first HDS


101.Liq. Gasoline on 1st bed of catalyst in 1st HDS

ReactorPDI-2004 Kg/cm2g 0.5

S. No.


102.Gasoline after passing through first bed of catalyst

in first HDS ReactorPI-2003 Kg/cm2g 28.4

103. First HDS Reactor Effluent PI-2007 Kg/cm2g 28.4

104.On the 2nd bed of catalyst inside first HDS


105. First HDS Reactor Effluent TI-2019 o C 275-355

106. First HDS Reactor Effluent to HDS Fired Heater TI-2102A/B o C 301-355

107. First HDS Reactor Effluent to HDS fired heater PI-2102A/B Kg/cm2g 19.8-26.3

108. Effluent of HDS Fired Heater TI-2104A/B o C 336-373

109. HDS fired heater outlet to second HDS Reactor PI-2103A/B Kg/cm2g 17.8-24.3

110.HDS Reactor Effluent from SHU feed/HDS

Effluent Exchanger to HDS Effluent Air CondenserTI-2301 o C 144-157

111.Gasoline from SHU Feed/HDS Effluent Exchanger

to HDS Effluent air condenserPI-2301 Kg/cm2g 16-22.5

112.HDS Reactor Effluent after HDS Effluent Air

CondenserTI-2303 o C 65

113.Gasoline after passing through HDS Effluent air

condenserPI-2303 Kg/cm2g 15.6-22.0

114. Separator drum outlet PI-2409 Kg/cm2g 15-21.5

115. Stabilizer feed from separator drum FIC-2402 M3/hr 82.3

116. Off gas from Separator Drum PIC-2403 Kg/cm2g 15

117. separator drum boot drain LIC-2401 M3/hr *

118.Lean Ammine from ARU after being pre-heated in

the lean amine pre-heaterTI-2501 o C 50

119. Lean Ammine from ARU TI-2504 o C 40

120.OFF GAS from Amine K.O. Drum to Amine

AbsorberTI-2502 o C 40

121. LP Steam to Lean Amine Preheater TDIC-2503 o C 10

122. Off gas to Amine Absorber PI-2601 Kg/cm2g 14.8

123. Amine & Fuel gas in Amine Absorber PDI-2602 Kg/cm2g 0.3

124. Fuel gas from Amine Absorber PI-2603 Kg/cm2g 14.7-21.5

125. Rich amine from amine absorber LIC-2601 M3/hr *

126. Amine & Fuel gas inside Amine Absorber PI-2608 Kg/cm2g 14.7

127. Rich Amine from Amine Absorber PI-2609 Kg/cm2g 6

128. Make-up H2 to Recycle Compressor K.O. Drum TI-2701 o C 40

129. Make up H2 to Recycle Compressor K.O. Drum PI-2701 Kg/cm2g 38.9

130. make up H2 to Recycle Compressor K.O. Drum FIC-2701 Nm3/hr 6944

S. No.


131.Recycle gas from Recycle Compressor K.O. drum

to Recycle compressorPI-2705 Kg/cm2g 14.4-21.4

132. H2 from Recycle Compressor to HDS Section FI-2803 Nm3/hr 35145

133. H2 to HDS section FI-2804 Nm3/hr 35145

134.Gasoline from Separator to Stabilizer

Feed/Bottom ExchangersTI-2901 o C 41

135. Stabilizer Feed from Separator Drum PI-2901 Kg/cm2g 9

136.Heavy Gasoline from Heavy Gasoline Trim Cooler

to MS POOLFI-2901 M3/hr *

137.Gasoline after Stabilizer Feed/Bottom Exchangers

to stabilizerPI-2903 Kg/cm2g 7

138.Heavy Gasoline from Stabilizer Bottom to

Stabilizer Feed/Bottom ExchangersTI-2903 o C 225-226

139. Heavy Gasoline after Heavy Gasoline Trim Cooler TI-2903 o C 40

140.Heavy Gasoline from Stabilizer Feed/Bottom

Exchanger to Heavy Gasoline Trim CoolerTI-2905 o C 106-107

141. Heavy Gasoline to MS POOL via Storage TI-2909 o C 40

142. Heavy Gasoline from Stabilizer Bottom Pumps PI-2909 Kg/cm2g 9.5

143.Heavy Gasoline at the bottom of Stabilizer

ColumnLIC-3001 mm *

144. Stabiliser reflux from, stabiliser Reflux Pumps FIC-3001 M3/hr 15

145. Stabilizer Feed TI-3002 o C 168-169

146. VHP Steam to Stabilizer Reboiler FIC-3002 M3/hr 9.7

147. Vap. Gasoline from Stabilizer overhead PI-3003 Kg/cm2g 6.8

148.From Stabilizer bottom to Stabilizer Feed/Bottom

ExchangersFIC-3003 M3/hr 106

149.Stabilizer overhead to Stabilizer overhead

CondenserTI-3004 o C 134-140

150. Vap. Gasoline below 1st tray in Stabilizer PI-3004 Kg/cm2g 7

151. VHP Condensate Pot for Stabilizer column LIC-3004 MM *

152. Top of Stabilizer column TI-3005 o C 160-200

153. Gasoline vapour at the top of Stabilizer column PI-3005 Kg/cm2g 6.9

154. Inside Stabilizer column below the feed plate TI-3006 o C 203-217

155.Treated Heavy Gasoline from the bottom of

StabilizerTI-3013 o C 225-226

156.Heavy Gasoline from the bottom of Stabilizer to

VHP steam reboilerTI-3009 o C 221

S. No.


157.Heavy Gasoline from VHP steam reboiler to

StabilizerTI-3010 o C 225

7.4 ALARMS:S. No. Descriptions Tag no. Unit Value

1. Mixed stream of FCC Gasoline from

FCC unit & Storage to SHU FEED

DRUM

TAHH-1105 o C 77

2. Gasoline & H2 at the inlet of SHU

FEED/EFFLUENT EXCHANGER

TAL-1301 o C 60

3. Reactor feed from SHU FEED/Effluent

Exchanger to SHU Preheater

TAL-1304 o C 80

4. Reactor feed stream from SHU

Preheater to SHU Reactor

TAH-1401 o C TAH-210

5. Reactor feed stream from SHU

Preheater to SHU Reactor

TAL-1401 o C TAL-150

6. A Bypass line of reactor feed stream to

SHU reactor


7. Gasoline & H2 stream Inside SHU

Reactor on the first bed of catalyst




TAHH-1403 o C TAHH-230














Reactor on the second bed of catalyst








S. No. Descriptions Tag no. Unit Value



























TAH-1412 o C TAHH-230













29. Effluent from the SHU Reactor TAHH-1415 o C TAH-225

TAHH-230

30. Gasoline & H2 stream inside the Splitter TAH-1501 o C 127

31. Gasoline & H2 stream inside the Splitter TAH-1502 o C 152

32. Gasoline & H2 stream to the Splitter TAH-1503 o C 170

33. Gasoline & H2 stream below the FEED

TRAY at the 19th tray inside the Splitter

TAH-1505 o C 204

34. Gasoline & H2 stream feed to splitter TAH-1504 o C 170

35. Splitter overhead to Splitter Reflux drum

after Splitter overhead air condenser

TAH-1603 o C 60


36. Fuel gas from Splitter Reflux Drum to

Fuel gas header

TAH-1605 o C *

37. Heavy FCC Gasoline after 3rd HDS

Feed/Effluent Exchanger to first HDS

Reactor

TAH-2001 o C 322

38. On the First bed of catalyst inside first

HDS Reactor



HDS Reactor



HDS Reactor



HDS Reactor


42. On the 2nd bed of catalyst inside first

HDS Reactor


43. On the 2nd bed of catalyst inside first

HDS Reactor


44. First HDS Reactor Effluent TAH-2019 o C TAH-360

TAHH-365

45. HDS Fired Heater Effluent TAHH-

2103A/B

o C TAHH-385

46. LP Steam to Lean Amine Preheater TDAL-2506 o C TDAL-5

47. Stabilizer Feed TAH-3002 o C TAH-179

48. Stabilizer Feed TAL-3002 o C TAL-163

49. Above the 17th plate of Stabilizer

column

TAH-3006 o C 227

50. Above the 12th plate of Stabilizer

column

TAH-3007 o C 227

51. Feed Surge Drum pressure control PAH-1101 Kg/cm2g 3.5

52. FCC Gasoline from FCC unit to SHU

Feed Surge Drum

PDAH-1106 Kg/cm2g 0.5

53. Gasoline & H2 stream before & after

1ST SHU Feed/HDS Effluent

Exchanger



SHU Feed/Effluent Exchanger



SHU Preheater



56. Gasoline & H2 stream before entering

SHU Reactor

PAL-1403 Kg/cm2g 29.2

57. Gasoline & H2 stream after passing

through the 1st bed of catalyst in SHU

Reactor

PAL-1407 Kg/cm2g 28

58. Gasoline & H2 stream before entering

SHU Reactor & after passing through

the 1st bed of catalyst in SHU Reactor


59. SHU Reactor Effluent PAL-1409 Kg/cm2g 27

60. Gasoline & H2 stream after 1st bed of

catalyst in SHU Reactor & Effluent from

SHU reactor


61. Splitter overhead & splitter underflow PDAH-1506 Kg/cm2g 1

62. Light gasoline vapour in splitter reflux

drum

PAH-1601 Kg/cm2g PAH-6.5

63. Light gasoline vapour in splitter reflux

drum

PAL-1601 Kg/cm2g PAL-5.2

64. Gasoline from splitter reflux pumps to

top of splitter column

PALL-1604 Kg/cm2g 4.2

65. Vapour gasoline to HDS feed PAL-1904 Kg/cm2g 21

66. Gasoline & H2 at the inlet of 1st HDS

Feed/Effluent Exchanger & at the outlet

of 3rd HDS Feed/Effluent Exchanger


67. Liq. Gasoline on 1st bed of catalyst in

1st HDS Reactor


68. Liq. Gasoline on 2nd bed of catalyst in

1st HDS Reactor


69. Off gas from Separator Drum PAH-2409 Kg/cm2g PAH-22.5

70. Off gas from Separator Drum PAL-2409 Kg/cm2g PAL-14.2

71. Part of liq. From Separator to 1st HDS

Reactor

PALL-2407 Kg/cm2g 22

72. Amine & Fuel gas in Amine Absorber PDAH-2602 Kg/cm2g 0.5

73. Recycle gas from Recycle Compressor

K.O. drum to Recycle compressor

PAH-2705 Kg/cm2g PAH-22

74. Recycle gas from Recycle Compressor

K.O. drum to Recycle compressor

PAL-2705 Kg/cm2g PAL-13.6

75. Vap. Gasoline from Stabilizer overhead PAH-3003 Kg/cm2g PAH-7.8


76. Vap. Gasoline from Stabilizer overhead PAL-3003 Kg/cm2g PAL-6.5

77. Vap. Gasoline below 1st tray in

Stabiliser

PAH-3004 Kg/cm2g 7.8

78. FCC Gasoline Feed to SHU Feed

Surge Drum

FAL-1102 M3/hr 117.6

79. Gasoline SHU Feed FAL-1202 M3/hr *

80. Gasoline SHU Feed FALL-1205 M3/hr 111.7

81. H2 to SHU section FAL-1203 Nm3/hr 1000

82. VHP Steam to Reboiler Splitter FAH-1501 M3/hr 30.7

83. Separator drum boot drain FAH-2403 M3/hr 5.6

84. Make up H2 to Recycle Compressor

K.O. Drum

FAL-2701 Nm3/hr 1284

85. H2 from Recycle Compressor to HDS

FEED/EFFLUENT Exchanger

FALL-2802 Nm3/hr 20832

86. H2 from Recycle Compressor to HDS

Section

FAL-2803 Nm3/hr 20832

87. H2 to HDS section FALL-2801 Nm3/hr 13020

88. VHP Steam to Stabilizer Reboiler FAH-3002 M3/hr 10.7

89. Heavy Naphtha at the bottom of

Gasoline Splitter

LAH-1502 MM LAH-3750

90. Heavy Naphtha at the bottom of

Gasoline Splitter

LAL-1502 MM LAL-700

91. Heavy Gasoline at the bottom of

Stabilizer Column

LAH-3001 MM LAH-3190


Stabilizer Column

LAL-3001 MM LAL-1630


Stabilizer Column

LALL-3002 MM 300

7.5 OPEARATING CONDITIONS OF DIFFERENT CASES OF OPERATION

Refer to enclosed PFDs as attachment for operating conditions for different

cases.

7.6 EQUIPMENT LIST

7.6.1 PUMPS

Item No. Item Description Normal Cap.(m³/hr)

Rated Cap. (m³/hr)

Disc. Press(Kg/cm²g)

Diff. Head (m)

NPSHA (m)

75-P-01

A/B

SHU FEED PUMPS 167.1 183.8 36.5 498 >8

75-P-02

A/B

HDS FEED PUMPS 112.3 123.5 34.8 472 4

75-P-03

A/B

SPLITTER REFLUX

PUMPS166.6 200 11.3 95.7 3.3

75-P-04

A/BLIGHT GASOLINE PUMPS 79.7 96 10.5 45.5 >8

75-P-05

A/BFCC HEART CUT PUMPS 24.7 27.2 10.1 38.6 >8

75-P-06

A/BQUENCH PUMPS 44.3 53.1 36.2 187.4 3.7

75-P-07

A/B

STABILIZER BOTTOM

PUMPS107.1 117.8 12.7 93.3 2.8

75-P-08

A/B

CORROSION INHIBITOR

PUMPS1.34 2.6 11.7 149.7 >8

75-P-09

A/B

STABILIZER REFLUX

PUMP15 18 12 86.7 2.*9

7.6.2 VESSELS:

Tag No. Item Description Internal Dia.(mm)

TL-TL(mm)

Oper. Temp°C

Oper. Press.Kg/cm²g

75-V-01 SHU FEED SURGE DRUM 3900 11000 70 3.0

75-V-02 SPLITTER REFLUX DRUM 2400 6800 55 5.5

75-V-03 SEPARATOR DRUM 2500 8400 40 21.5

75-V-04 RECYCLE COMP. KOD 900 2800 40 21.4

Tag No. Item Description Internal Dia.(mm)

TL-TL(mm)

Oper. Temp°C

Oper. Press.Kg/cm²g

75-V-05 STABILIZER REFLUX DRUM 1100 3300 40 6.3

75-V-06 AMINE KOD 900 2500 40 21.5

75-V-09CORROSION INHIBITOR

DRUM600 1950 AMB 1.0

75-V-10 SULFIDING AGENT DRUM 1600 5000 AMB 1.0

7.6.3 COLUMNS:

Tag No.

Item Description

No. of tray

Internal Dia (mm)

TL-TL(mm)

Oper. Temp °C

Oper PressKg/cm²g

Top Bottom Top Bottom

75-C-

01

GASOLINE

SPLITTER

52 3100 41550 116 199 6.03 6.47

75-C-

02

AMINE

ABSORBER

20 900 14150 50 14.8

75-T-

1003

STABILISER

COLUMN

30 2100

(Btm);

1100

(top)

26750 177 203 7.85 8.08

7.6.4 REACTORS:Tag No. Item Description Internal

Dia (mm)TL-TL(mm)

Oper. Temp °C

Oper PressKg/cm²g

75-R-01 SHU REACTOR 1800 23420 200 30

75-R-02 HDS REACTOR 2500 12950 355 28.4

7.6.5 HEAT EXCHANGERS (TUBULAR):

Sr. No.

Tag No.

Service Shell side fluid

Tube side fluid

Shell side temp (C)

Tube side temp (c)

IN OUT IN OUT

1 75-E-01 SHU Feed / HDS HDS Effluent SHU Feed 211 156 66 155

Effluent exchanger

2 75-E-02 SHU Feed / Effluent

exchanger

SHU Effluent SHU Feed 219 188 155 188

3 75-E-03 SHU preheater VHP Steam SHU Feed 238 238 128 200

4 75-E-04 Splitter post condensor HC+H2 Cooling water 55 40 33 40

5 75-E-05 Light Gasoline cooler Light Gasoline Cooling water 65 40 33 40

6 75-E-06 FCC Heartcut cooler Gasoline Cooling water 65 40 33 40

7 75-E-07 Splitter reboiler VHP Steam HC 238 238 216 221

8 75-E-08

A/B/C

HDS Feed / Effluent

Exchanger

HDS Feed HDS Effluent 174 312 370 207

9 75-E-09 Reactor effluent trim

cooler

HC Cooling water 65 40 33 40

10 75-E-10 Lean Amine preheater Lean Amine LP steam 40 50 128 128

11 75-E-11

A/B

Stabilizer Feed/Bottom

exchanger

Stabilizer Feed Stabilizer

Bottom

225 107 41 169

12 75-E-12

A/B

Heavy gasoline trim

cooler

Heavy

gasoline

Cooling water 65 40 33 40

13 75-E-13 Stabilizer reboiler VHP steam Stabilizer

bottom

238 238 221 225

14 75-E-14 Stabilizer overhead trim

cooler

Stabilizer

overhead

Cooling water 65 40 33 40

7.6.6 AIR COOLERS

Sr. No. Tag Service Temp. - in Temp. - out1 75-A-01 Splitter overhead air condenser 97 55

2 75-A-02 FCC heart cut air cooler 142 65

3 75-A-03 HDS Effluent air condenser 158 65

4 75-A-04 SHU recycle air condenser 218 65

5 75-A-05 Stabilizer overhead condenser 135 65

6 75-A-06 Light gasoline air cooler 116 65

7 75-A-07 Heavy gasoline air cooler 107 65

7.7 LIST OF INSTRUMENTSIn this section control valves, pressure safety valves, analysers etc are

listed. Information regarding indicators & controllers (temperature, pressure, flow

and level instrument) are already given in previous section.

7.7.1 CONTROL VALVES:

S.

No

.

Tag No. Description Action of CV

on Air failure

SHU FEED SURGE DRUM:

1. PV-1101A Gases from FSD to Flare FC

2. PV-1101B Nitrogen to FSD FC

3. LV-1101 FSD boot draining FC

4. FV-1103 Heavy Gasoline Recycle from SHU Recycle Air

Condenser

FC

5. FV-1104 Feed from storage FC

SHU FEED SECTION:

6. FV-1201

A/B

SHU feed to 75-E-01 FC

7. FV-1202 Charge pump MCF FO

8. FV-1203 Hydrogen to reaction section FC

9. FV-1204

A/B

SHU Feed/Effluent Exchanger bypass to SHU Preheater FO

SHU FEED PREHEATING SECTION:

10. FV-1301

A/B

VHP steam to SHU Preheater FC

SHU REACTOR:

11. PDV-1401 SHU Reactor first bed bypass FC

SHU SPLITTER SECTION:

12. PV-1404 Splitter feed FC

13. PV-1501 Depressurization line FO

14. FV-1501 VHP steam condensate from Splitter Reboiler FC

15. PV-1601

A/B

Splitter reflux drum pressure control FC

16. LV-1601 Reflux line FO

17. FV-1701 Light gasoline to storage FC

18. FV-1702 FCC Heart cut gasoline to storage FC

19. FV-1703 Light gasoline pump min. fliow line FO

HDS FEED SECTION:

20. FV-1801 HDS feed pump min. flow line FO

21. FV-1901 HDS feed to HDS feed/Eff. Exchanger FC

22. FV-1902 HDS Feed / Eff Exchanger bypass FC

S.

No

.

Tag No. Description Action of CV

on Air failure

23. FV-1904 HDS recycle FC

HDS REACTION SECTION

24. FV-2001 Quench to reactor FO

25. FV-2002 Quench to reactor FO

26. FV-2003 Diluant line for start up FO

27. FV-2101 Plant air to HDS Reactor Feed Heater FC

HDS SEPARATOR SECTION

28. FV-2401 Quench pump min. flow line FO

29. FV-2402 Stabilizer feed line FC

30. LV-2401 Sour water boot FC

RECYCLE GAS KOD AND AMINE ABSORBER SECTION:

31. FV-2501 Lean amine to preheater FC

32. TV-2501 LP steam to preheater FC

33. LV-2501 HC liquid from Amine KOD FC

34. LV-2601 Rich amine to amine unit FC

35. FV-2601 Sweet purge gas to FG header FC

36. LV-2701 Amine from Recycle compressor K.O. drum to ARU FC

37. FV-2701 Make up H2 to Recycle Compressor K.O. Drum FC

38. FV-2702 Make up H2 to Recycle Compressor K.O. Drum FC

STABILISER COLUMN:

39. FV-3001 Reflux to Splitter FO

40. FV-3002 VHP condensate from stabilizer reboiler FC

41. FV-3003 Stabilizer bottom pump min. flow line FO

42. LV-3001 VHP Condensate from Condensate Pot FC

43. FV-2901 Heavy gasoline to stabilizer feed / bottom exchanger FC

44. PV-3101 Sour purge gas From stabilizer reflux drum FC

45. LV-3101 Sour water to sour water treater FC

7.7.2 ON-OFF VALVES

SL

NO.

TAG NO. DESCRIPTION/LOCATION ACTION ON

AIR FAILURE

SHU FEED SURGE DRUM:

1. UV-1101 FCC Gasoline Feed to SHU Feed Surge Drum FC

2. UV-1102 Heavy Gasoline Recycle from SHU Recycle Air

Condenser

FC

3. UV-1103 SHU Feed Surge Drum Boot Drain FC

4 UV-1104 Feed from FSD to Charge pump FC

SHU FEED SECTION:

5. UV-1201 Gasoline from SHU Feed pumps to SHU Feed/HDS

Effluent Exchanger

FC

6. UV-1202 H2 from Recycle Compressors to SHU Feed/Effluent

Exchanger

FC

SHU FEED PREHEATING SECTION:

7. UV-1301 VHP steam to SHU Preheater FC

SHU SPLITTER SECTION:

8. UV-1501 SHU emergency depressurisation to flare FO

9. UV-1502 Heavy Gasoline from Splitter bottom FC

10. UV-1503 Splitter Reboiler steam inlet FC

11. UV-1701 Light gasoline to storage FC

12. UV-1702 FCC Heart cut gasoline to storage FC

HDS FEED SECTION

13. UV-1901 HDS Feed to HDS Feed / Eff. Exchanger FC

HDS REACTION SECTION

14. UV-2101 Plant air to feed heater FC

15. UV-2301 BFW injection at HDS Eff. Air condenser FC

SEPARATOR DRUM:

16. UV-2401 Stabiliser Feed from Separator Drum FC

17. UV-2402 Separator Drum Boot Drain FC

18. UV-2403 Flare from Separator Drum for depressurisation FO

AMINE ABSORBER:

19. UV-2501 HC liquid from amine KOD FC

20. UV-2502 LP steam to Amine preheater FC

21 UV-2503 Lean amine to preheater FC

22 UV-2504 LP condensate To 75-V-19 FC

23 UV-2505 LP condensate To OWS FC

SL

NO.

TAG NO. DESCRIPTION/LOCATION ACTION ON

AIR FAILURE

24. UV-2601 Rich Amine from Amine Absorber FC

RECYCLE COMPRESSOR SECTION:

25. UV-2701 H2 from Recycle Compressor K.O. Drum FC

26. UV-2702 Make up H2 to Recycle Compressors K.O. Drum FC

27. UV-2703 Amine as Recycle Compressors K.O. Drum Drain FC

28. UV-2801 Recycle gas comp. discharge FC

STABILISER COLUMN:

29. UV-3001 Heavy Gasoline from Stabiliser bottom to Stabiliser Bottom

Pumps

FC

30. UV-3002 Stabiliser Reboiler Steam Inlet FC

7.7.3 SAFETY VALVES:

S. No. Tag No. Description/Location Set Pressure

(Kg/cm2g)

1. PSV-1101 A/B Feed Surge Drum 5.0

2. PSV-1102 A/B Cold Feed Filter 15

3. PSV-1201 A/B Feed pump discharge 37

4. PSV-1202 A/B SHU Feed to 75-E-03 37

5. PSV-1301 SHU preheater condensate pot 40

6. PSV-1401 SHU Reactor 35.1

7. PSV-1501A/B From Gasoline Splitter to Flare 8

8. PSV-1502 Splitter reboiler condensate pot 40

9. PSV-1601/1602 Sea water return from 75-E-04 7.6

10. PSV-1701/02 Sea water return from 75-E-05A/B 7.6


12. PSV-2001 First HDS Reactor 36.5

13. PSV-2101 First HDS heater outlet 31

14. PSV-2201 Fuel gas KOD 9.0


16. PSV-2401A/B

/2402

Flare from Separator drum 27.5

17. PSV-2601 Flare from Amine Absorber 27.5

18. PSV-2701A/B Flare from Recycle Compressor K.O. Drum 27.5

19. PSV-2801A/B Recycle Compressor 75-K-01A Discharge 38.5

S. No. Tag No. Description/Location Set Pressure

(Kg/cm2g)

20. PSV-2802A/B Recycle Compressor 75-K-01B Discharge 38.5

21. PSV-2803 Recycle Compressor 75-K-01A Discharge

(Regen. Case)

13

22. PSV-2804 Recycle Compressor 75-K-01B Discharge

(Regen. Case)

13

23. PSV-2901/2902 Sea water return from 75-E-12 A/B 7.6

24. PSV-3001A/B Flare from Stabiliser Column 9.0

25. PSV-3002 Stabilizer reboiler condensate pot 40

26. PSV-3101/3102 Sea water return from 75-EE-14A/B 7.6

27. PSV-3201/3202 Corrosion inhibitor pump discharge 13.7

28. PSV-3203/3204 Sulfiding agent injection pump discharge 32

29. PSV-3205 Corrosion inhibitor drum 10.5

7.8 RELIEVE VALVE LOAD SUMMARY

List of safety valves is already given in the previous section. Detail of relive

load summary such as relieve valve tag, location, set pressure, capacity, failure

scenarios considered are given in Flare Load Summary.

Flare Load Summary is given in Annexure IV.

7.9 DETAIL OF INTERLOCK LOGIC AND TRIPS

I.NO CAUSE EFFECTACTUATOR DESCRIPTION DEVICE ACTION DESCRIPTION

101 75-LAHH-1103 Very high level in

SHU feed surge

drum

75-UV-

1101

Close FCC gasoline feed

75-UV-

1102

Close Hydrogenated

gasoline recycle

103 75-PALL-1604 Very low pressure

at 75-P-03A/B

discharge

75-P-03

operating

stop Pump 75-P-03 A/B

protection

75-P-03

spare

Start Spare pump auto

start

106 75-LALL-1701 Low level 75-P-

04A/B

Stop Light gasoline

pump stops

107 75-LALL-1505 C-01 chimney

tray level low

75-P-05

A/B

Stop FCC heart cut

pump stop

108 75-AT-2101

75-TAHH-

1403-1415

High O2 content

Very High temp in

75-R-01

75-UV-

2101

close Air make up during

regeneration

109 75-HS-

1102A(Board)

75-HS-

1102B(Local)

75-ZSC-1104

Case of fire

75-UV-1104

CLOSE

75-UV-

1104

75-P-

01A/B

I-102

Close

Stops

Close SHU feed

surge drum bottom

inventory valve

Stop 75-P-01 A/B

110 75-LALL-1106 Very low level in

SHU feed surge

drum boot

75-UV-

1103

Close Boot drain to OWS

111 75-PAHH-1510 Very high

pressure at

splitter overhead

75-UV-

1503

Close VHP steam to 75-

E-07 stop

112 75-TAHH-2103

75-HS-

2102A(Board)

75-HS-2102B

(Local)

Very high temp in

any of the pass at

heater O/L

75-F-01 Stop Heater shutdown

113 75-HS-

2401A(Board)

75-HS-

HDS reaction

section

depressurization

75-UV-

2502

75-UV-

Close

Close

LP steam to lean

amine preheater

Lean amine to

2401B(Local) 2503

75-UV-

2403

75-UV-

1901

75-UV-

2702

75-F-01

75-UV-

2401

75-UV-

2601

75-UV-

3001

75-UV-

2701

75-UV-

2801

75-P-

07A/B

I-117

I-122

Open

Close

Close

Stop

Close

Close

Close

Close

Close

Stop

Actuate

Actuate

Amine absorber

HDS reaction

section

depressurization

Stop feed to HDS

reaction section

H2 make up

HDS heater burning

off

HC to stabilizer

Rich amine to

amine unit

Close stabilizer

bottom product

valve

Recycle comp

isolation

Recycle comp

isolation

Stop 75-P-01A/B

Recycle comp KOD

interlock

Amine absorber

Low Low level

interlock


separator drum

75-UV-

2401

Close HC to stabilizer

115 75-LAHH-2406 Very high level in

separator drum

boot

75-UV-

2301

Close BFW feed


Amine absorber

75-UV-

2601

Close Rich amine to

amine unit

117 75-LAHH-2704

75-FALL-2801

I-119

I-113

75-TAHH-2807

Very high level in

comp KOD

Very low flow at

comp discharge

Very low flow at

comp discharge

75-K-

01A/B

75-UV-

1901

75-F-01

Stop

Close

Stop

Stop Recycle comp

Stop feed to HDS

reaction section

Heater shutdown


stabilizer bottom

75-UV-

3001

75-P-

01A/B

Close

Stop

Close stabilizer

bottom valve

Stop 75-P-07A/B

119 75-HS-

2801A(Board)

75-HS-

2801B(Local)

75-ZSC-2801

75-ZSC-2701

Case of fire I-117

75-UV-

2801

75-UV-

2701

Actuate

Close

Close

Recycle comp

shutdown

Recycle comp

isolation

Recycle comp

isolation


at 75-P-09 A/B

discharge

75-P-09

operating

75-P-09

spare

Stop

Start

Pumps 75-P-09A/B

protection

Spare pump auto

start

121 75-HS-

3002A(Board)

75-HS-

3002B(Local)

Case of fire 75-UV-

3001

75-P-

07A/B

Close

Stop

Close stabilizer

bottom valve

Stop 75-P-07A/B

75-ZSC-3001 75-UV-3001

Close

122 75-LALL-2502

I-113

Very low level in

amine KOD

HDS

depressurisation

inter lock

75-UV-

2501

Close Hydrocarbon liquid

drain


RGC KOD

75-UV-

2703

Close Hydrocarbon/Amine

liquid drain

124 75-FALL-1903

75-TALL-2003-

2019

Very low flow at

HDS feed pump

discharge

Very high temp in

first HDS reactor

75-UV-

1901

75-UV-

2702

75-F-01

Close

Close

Stop

Stop feed to HDS

reaction section

H2 make up from

OSBL

Heater shutdown

124 75-AT-2101

75-TAHH-

2003-2019

High O2 content

Very high temp in

HDS reactor 75-

R-02

75-UV-

2101

Stop Air to heater during

regeneration


separator drum

boot

75-UV-

2402

Close Close sour water to

SWS


at quench pump

discharge

75-P-

06A/B

operating

75-P-06

spare

Stop

Start

Pump 75-P-06

protection

Spare pump auto

start

128 LAL-3301

LAH-3301

Low level in CBD

drum

High level in CBD

drum

75-P-11

75-P-11

Stop

Start

CBD pump

CBD pump

129 LAL-3401

LAH-3401

Low level in Flare

KOD

High level in Flare

UV-3401

UV-3401

Close

Open

CBD Drain line

CBD Drain line

KOD

130 PAHH-

3012A/B/C

High-high

pressure at

stabilizer O/H.

UV-3002 Close VHP steam supply

to 75-E-13

7.10 EFFECT OF OPERATING VARIABLES ON THE PROCESS

7.10.1 OPERATING PARAMETERSThe operating parameters are the variables affecting the process

performance, which the operator can actually adjust in order to improve or restore

the unit performance.

The purpose of process:

To perform the desulfurization of the gasoline. Regarding product

specifications, refer to the process book.

To limit octane losses.

The operating parameters used to meet these specifications with an optimum

catalyst life are the following:

Reactors inlet temperature

Make-up hydrogen and recycle hydrogen flowrates leading to the hydrogen

partial pressure at outlet of the reactors, the hydrocarbon partial pressure, the

hydrogen sulfide partial pressure.

The space velocity (i. E. Feed rate).

Operator action on these parameter enables the unit to match different feed

and product qualities provided they are within the basis of design of the unit.

7.10.2 REACTOR TEMPERATURE

1. Selective Hydrogenation section:A temperature increase favors di-olefin hydrogenation but also olefin

hydrogenation and coking, which reduces the cycle length. Moreover a high

temperature can lead to excessive vaporization in the reactor which is

theoretically in liquid phase. This may lead to problems with liquid distribution and

pressure drop.

The temperature increase in the selective hydrogenation reactor is a function

of the diolefin content and H2/HC ratio.

Moreover, reactions of oligomerisation can take place if the temperature is too

high, leading to gum formation. In practice, the operating temperature will be set

so that the exothermicity starts to be perceptible. The hydrogen make-up will be

adjusted so that the heavy FCC gasoline MAV is decreased below 2.(Diene value

< 0.5)

2. HDS reaction section:The reactor inlet temperature is adjusted at the value required for gasoline

product sulfur specification without a great loss of olefins. However, because

fresh catalyst is very active, it is sometimes possible to operate at a lower

temperature at start-up.

A temperature increase favors all the following reactions: desulfurization,

hydrogenation of olefins and coking. The latter also reduces the cycle length.

Accordingly, the temperature at reactor inlet must be adjusted at the lowest value

which enable to meet the product specifications.

The temperature increase in the first HDS reactor (75-R-02) is a function of

the olefin content and the olefin hydrogenation level, but the DT is controlled by

the quench.

The reactor weighted average bed temperature (WABT) is the main

parameter used to adjust product sulfur content. The WABT is controlled by the

first HDS reactor inlet temperature and the quench rate (adjusted to limit the HDS

reactor exotherm). Increasing WABT results in lower product sulfur (higher HDS)

and additional olefin hydrogenation. Typically, during operation, when the unit is

lined out at design capacity and the stabilizer bottom product is on-spec there are

only a few cases when the operator needs to adjust the reactor inlet temperature.

In NIT case, non selective mode, the reactor exotherm is limited at 500C

and controlled by the liquid quench between the first and second bed and

between second and third bed. Some part of the hydrogenated product from the

separator drum 75-V-03 is recycled and mixed with the HDS feed for olefin

dilution.

In AM case; selective mode, the exotherm in the HDS rector is controlled at

200C by the liquid quench of the HDS reactor.

7.10.3 OTHER PARAMETER1. Coke accumulation on the catalyst surface:Coke can have 2 different origins.

Catalytic cokeDuring the catalyst cycle, coke may build-up on the catalyst surface within

the pores, reducing the reaction surface and consequently the activity. An

adjustment will be required on the Reactor inlet temperature to compensate for

this activity loss. This change is very gradual over the catalyst cycle and depends

upon the feed quality.

Coke formation due to coke precursors in the feedThis coke formation is due to a combined action of dissolved oxygen, rust

and temperature. Therefore, it is very important to be careful with the quality of

the feed especially to limit content of compounds containing the carbonyl bound

(C=O) and the rust content.

This formation of coke leads to a higher P in reactors and decreases the

catalyst cycle. The coke formation due to coke precursors in feed is more

important than catalytic coke.

2. Feed quality changes

a) Higher level of contaminantsIf there is a higher level of contaminants in the feed, the operator must

increase the reactor inlet temperature until the efficiency of the

hydrodesulfurization reactions is restored.

b) Higher sulfur contentIf the sulfur content of the feed is higher, the operator must increase the

reactor inlet temperature to reach the same sulfur specification.

c) Higher olefin content

In order to avoid high exothermicity, the olefin content must be lower than

35% vol. The reactor inlet temperature needs not to be increased for a higher

olefin content. Quench and eventually top bed diluant shall be adjusted to control

the DT through the catalytic beds.

3. Major changes in feed rateAs catalyst activity is higher with a lower space velocity, then the reactor inlet

temperature at 60% capacity should be different from the one at 100% capacity.

The operator can decrease the reactor inlet temperature at lower space velocity

and therefore preserve catalyst cycle length.

The end of a catalyst cycle is reached when the following takes place:

The catalyst deactivation is such that it is no longer possible to meet the product

specifications.

The maximum allowable temperatures have been reached.

The pressure drop in the reactor is too high.

In this case, the catalyst must be regenerated ex-situ.

7.10.4 MAKE-UP H2 AND RECYCLE H2 FLOW-RATES

1. Hydrogen partial pressure at reactors outlet.

a) First section – Selective Hydrogenation Reactor 75-R-01The H2/HC ratio increases by feeding more make-up hydrogen gas. This

enhances both the di-olefin hydrogenation and the mercaptan removal reactions

and decreases the coke formation rate. However, if the H2 excess is too high, it

could lead to excessive vaporization of naphtha creating problems in distribution

and pressure drop in the reactor. It would result in excessive loss of light FCC

gasoline at the splitter vent gas and excessive olefin saturation.

The hydrogen rate is set to decrease the MAV in the heavy FCC gasoline

product below 2.

b) Second section - HDS reactor 75-R-02 The hydrogen partial pressure is defined by the following formula

ppH2 = reactor outlet pressure

The ppH2 at reactor outlet is a function of:

The total pressure (which is fixed at the design stage and is beyond the reach

of operators).

The hydrogen excess versus the chemical consumption, which depends on

the amount of hydrogen gas make up, and the hydrogen purity (which is also

beyond the reach of operators).

The required ppH2 is achieved when the HDS section is operated at pressure

- around 15 Kg/cm2g at the separator drum (AM case, selective).

- around 21.5 Kg/cm2g at the separator drum (NIT case, nonselective)

In terms of activity, an increase of the hydrogen partial pressure enhances the

hydrodesulfurization and hydrogenation of olefins. In addition, a high hydrogen

partial pressure reduces the polymerization reactions and coke deposit,

increasing the catalyst cycle length.

Actually ppH2 is not a variable that operators adjust but they have to ensure

that it is always around the design value. The design ppH2 is fixed by the system

pressure, hydrogen recycle rate and hydrogen gas purity.

If the recycle gas purity decreases due to lack of make-up gas, the hydrogen

partial pressure will decrease as well. The operator must maintain the hydrogen

recycle quality within the design range by adequate purge and hydrogen make-

up. By increasing the PPH2, the olefin and H2S partial pressures decrease and

then selectivity is improved.

2. Hydrocarbon partial pressure

ppHC = pressure

The ppHC is a function of:

The total pressure.

The hydrocarbon contents i.e. feed rate.

The hydrocarbon partial pressure has no impact on the hydrodesulfurization.

On the other hand, to minimize hydrogenation of olefins, it is necessary to

minimize olefin partial pressure therefore hydrocarbon partial pressure. For

instance, if the feed flowrate is 60% of the normal flowrate, it would be better not

to decrease the H2 flowrate. Indeed, the ratio H2/HC will increase and the

selectivity will be enhanced.

3. Hydrogen sulfide partial pressureThe ppH2S is a function of:

The total pressure.

The H2S content.

H2S has no real impact on olefin hydrogenation but affects

hydrodesulfurization. Therefore, it is necessary to have a low H2S content to

enhance selectivity; this means to maximize the performance of the amine

absorber.

7.10.5 SPACE VELOCITY (FEED RATE)Space velocity coupled with reactor inlet temperature defines the severity of

the hydrotreatment. Severity is increased when either the space velocity is

decreased or the temperature is increased.

Space velocity as defined earlier is the amount of liquid feed (expressed in

weight or volume) which is processed per hour divided by the amount of catalyst

(in weight or volume). The inverse of the space velocity is related to the

residence time or contact time in the reactor.

As the quantity of catalyst is fixed, the space velocity will change by varying

the feed rate. Decreasing the feed rate decreases the space velocity. At constant

temperature this increases the activity as there are now more catalyst active sites

per unit of feed. This will improve the hydrotreatment efficiency. For small

changes in the feed rate, no action is required by the operator. For large

reductions however, the operator may lower the reactor inlet temperature to

preserve the cycle length. It is recommended that, if an adjustment to a new

temperature level is considered, the reduction must be in increments no greater

than 2°C until the new stable performance level is reached.

In general the following rules are valid:

In case of feed is to be increased: first increase the temperature, then

increase the feed rate.

In case of feed is to be decreased: first decrease the feed rate, then

decrease the temperature.

These measures are required to keep the safe side of the gasoline quality.

7.10.6 FEED QUALITY

1. Contaminant contentFeed quality is an indirect variable, a variable that the operator reacts to

rather than adjusts for performance control. The unit is designed for a particular

feedstock with a maximum design level of sulfur, Nitrogen, Mercury, Arsenic and

with other contaminant levels defined within the normal range of most crudes. As

the feed quality changes during processing of different crudes i.e. higher levels of

nitrogen and sulfur, the operator must raise the reactor inlet temperature to

maintain unit performances.

Prior to a crude change, the operator must be made aware of potential higher

contaminant levels than the previous crude by reviewing the crude essays. For

new crude, the raw gasoline feed to the unit must be thoroughly analyzed for all

contaminants including metals. If possible, this must be done prior to feeding the

unit but if not, as early as possible. This will avoid a higher rate of catalyst

saturation due to higher metals content. Moreover, it is important to be careful

with the content of compounds with carbonyl bound (C = O) and of rust. Indeed, a

combined action of dissolved oxygen, rust and temperature leads to a coke

formation, which increases P in reactors and decreases the catalyst cycle.

2. Di-olefin contentDi-olefin content higher than the design means an increased exothermicity for

the Di-olefin reactor. As there is no quench or diluent on them, an increase of

diolefin content in the feed induces a higher DT across the catalyst bed. This

results in a shorter cycle length. If all the di-olefins are not hydrogenated in the

Diolefin reactor, they will reduce the second reactor cycle length.

3. Olefin contentOlefin content higher than the design in the heavy FCC gasoline fraction of

the feed means an increased exothermicity for the HDS reactor. This can be

compensated, in order to keep the same WABT, either by decreasing the inlet

temperature or by higher quench and diluent flow rates.

If these conditions are not sufficient, then the feed flow rate has to be

reduced, while maximizing the diluent rate and quench.

SECTION- 8 SHUTDOWN PROCEDURES

8.1 NORMAL SHUTDOWN PROCEDURE8.1.1 INTRODUCTION

Normal shutdown applies to a shutdown planned in advance for preventive

maintenance or to unexpected events which are not of an emergency nature.

Before initiating any planned shutdown, review all records to determine

what inspections and repair work must be accomplished during the shutdown.

Prepare a shutdown schedule, including plans for pre-arranging feed and product

inventories during turnaround time. Notify all services and other dependent

operating units of the schedule so that all activities can be properly coordinated.

Arrange for all required parts, tools and services in advance, in particular

adequate nitrogen for purging.

While shutting down the unit due to maintenance or emergency care must

be taken not to admit air into the system until all hydrocarbon vapours have been

removed. Operators should be thoroughly familiar with shutdown procedures and

understand the reasons for each work. Good judgement must be exercised as no

written procedure can completely cover all details or problems that can arise in

an emergency. Judgement is more likely to be exact if prior thought and planning

have been made

PrecautionsDuring shutdowns, precautions must be taken to avoid the following, whether

planned or unplanned:

Exposing personnel to toxic or noxious conditions when equipment is drained

or depressurised.

Fire possibilities when the reactors are opened, due to explosive hydrogen-

oxygen mixtures, or exposure of pyrophoric material to air.

8.1.2 PREPARATIONS FOR A PLANNED SHUTDOWN

For a planned shutdown some work can be done in advance, such as:

Prepare blind lists and blind list accounting procedures for required isolations.

Have test equipment onsite for:

Explosive Gas and Hydrogen Analyzers

Oxygen Analyzers (If Vessel Entry is Planned)

If inert atmosphere entry into the vessels is planned, have the necessary

personnel protective equipment on hand.

Have the necessary materials onsite to complete the shutdown.

Inform all interested parties of shutdown plans.

Have temporary piping spools, blinds, gaskets, etc., onsite.

Erect staging (scaffolding).

Ensure adequate storage space is available in the off plot storage system.

Plan for any unbalanced utilities.

8.1.3 GENERAL PROCEDUREWhen shutting down, steps should be taken to prevent catalyst or

equipment damage from expansion, contraction, thermal shock or unusual

pressure surges. Purge with care all vessels, using inert gas and steam until all

equipment is free of hydrocarbon liquids and gases. Purge thoroughly and check

the atmosphere in the vessels before entering or starting repairs. Rigorously

observe all safety precautions.

The general procedure to be followed for a total shutdown is the following:

Lower the capacity and if necessary the severity.

Switch the product to off-spec. or raw storage.

Shutdown the Reaction section.

Drain all hydrocarbons.

Depressurize and purge.

Several shutdown cases are considered :

Short duration shutdowns (i.e. less than 24 hours).

Long duration shutdowns.

Shutdowns to be followed by catalyst regeneration or inspection of equipment.

8.1.4 SHORT PERIOD SHUTDOWNThis shutdown is typically less than 24 hours to carry out minor repairs without

opening any major equipment.

Reduce unit capacity to 60% of normal feed rate. It should not be necessary

to adjust the reactor inlet temperatures immediately before the shutdown.

Maintain hydrogen gas flow rate and make-up hydrogen through selective

hydrogenation reactor.

Disconnect the level cascaded controllers on the separator drum 75-V-03, and

on the Stabilizer bottom while keeping normal flow rates.

Switch the products to off-spec storage. (light cut, heart cut and heavy FCC

gasoline)

Shut down steam flow to the SHU feed steam heater 75-E-03 to decrease

inlet temperature to selective hydrogenation reactor at least down to 10°C

below the normal temperature.

The make-up H2 supply to the selective hydrogenation reactor is also

stopped.

Reduce the temperature at the inlet to the first HDS reactor 75-R-02 by

decreasing firing in 75-F-01 at a rate of 40°C per hour down to 180°C.

Close block valves on liquid flow outlet from the separator drum 75-V-03 when

level decreases below 30%.

Shutdown DEA solution circulation through the Amine absorber and open the

bypass line of absorber.

When the selective hydrogenation reactor temperature is at least 10°C below

the normal temperature, and levels in splitter and stabilizer have decreased,

shut-off level control valves. The evacuation of stabilizer column 75-C-03

depends on pressure in the column. In order to avoid sudden decrease of

pressure, the reflux flow rate must be reduced and fuel gas flow rate to

reboiler heater is controlled consequently. The splitter and stabilizer shall

operate at total reflux.

Stop the fresh feed to the selective hydrogenation reactor 75-R-01.

Close the block valves on the Splitter bottom. The SHU and HDS sections are

now isolated.

The circulation of hydrogen through the HDS reaction section is continued for

a period of two hours to strip out hydrocarbons from the catalyst.

The unit is now considered to be on stand-by with gasoline feed stopped,

hydrogen circulating through the HDS catalyst beds at reduced temperature,

splitter and stabilizer at total reflux.

8.1.5 LONG PERIOD SHUTDOWNThis shutdown is required for major repair of some equipment or some

sections of the unit.

The procedure described above for short period shutdown is followed, but

completed to full cooling of equipment to ambient temperature.

After two hours stripping of catalysts with circulation of hydrogen and make up

hydrogen gas flow through reactor 75-R-01 the temperature is decreased

gradually to 100°C at 40°C/h.

At temperature of 100°C at inlet to reactors 75-R-01, 75-R-02, the firing in

heater 75-F-01 stopped.

The hydrogen recycle gas compressor 75-K-01 A/B remains in operation until

temperature in HDS catalyst beds is below 50°C. The hydrogen make up

remains also in operation until the 75-R-01 reactor beds temperature is below

50°C.

The HDS reaction section shall be isolated from other section of the unit and

kept under pressure of hydrogen gas, provided that no repair or equipment

opening is required in this section.

Splitter and stabilizer sections are shutdown by closing steam to reboiler. The

air cooled condensers are shutdown and water flow to trim coolers closed

when pressure drops below 2 to 3 Kg/cm2g. The extended period of shutdown

requires to introduce nitrogen to the feed drum 75-V-01, and reflux drums 75-

V-02, 75-V-05 in order to keep equipment under positive pressure.

NOTE: 180oC is the maximum allowable at which hydrogen can be circulated on the catalyst without any risk of desulfiding. i.e. (Metal sulfide + H2 ------ H2S + bare metal).

8.1.6 SHUTDOWN FOLLOWED BY MAINTENANCE, INSPECTION OR CATALYST UNLOADING

Shutdown for this purpose requires the complete removal of hydrogen and

hydrocarbons from the equipment. The equipment of reaction section must be

purged with nitrogen before admission of air. The equipment involving the splitter

and the stabilizer must be steamed out. The first steps of shut down are the same

as used for long period shutdown described above.

The reaction section of selective hydrogenation reactor and reaction section

of HDS reactor with compressor should be isolated from the remaining

equipment.

a) Selective Hydrogenation Reaction section 75-R-01The reactor section should be isolated from splitter and feed section at outlet

of SHU feed steam heater 75-E-03 and at inlet line to splitter. The system is

depressurized to the flare system. The remaining pressure should be slightly

above atmospheric pressure to avoid entry of air. The rest of the equipment is

drained and N2 purged.

b) HDS Reaction section 75-R-02 The reaction section should be isolated from the splitter and the stabilizer

section by closing valves on discharge of 75-P-02 A/B pumps, and on

stabilizer inlet line.

The system is depressurized to the flare to a pressure slightly above

atmospheric. The amine solution in 75-C-02 is displaced to the refinery

regenerator before depressurizing this section.

The recycle compressor 75-K-01 A/B is isolated depressurized and purged

with nitrogen.

The block valves on amine absorber are closed. The remaining amine

solution is drained to sewer. The absorber is filled with demineralized water.

The start-up ejector 75-J-01 is lined to the separator drum 75-V-03 outlet line

and gases are evacuated. The system is filled with nitrogen, pressurized,

released to flare and then evacuated by the ejector.

The repeated operation allows to reach the decrease of hydrogen and

hydrocarbon concentration below the explosive limits. The explosive meter is

used to check the limit at which vessels can be opened for entry of atmospheric

air.

Care should be taken given the fact that catalyst pores retain some

hydrocarbons and some time is needed for their release. The period of time of

1-hour minimum is required to ensure that hydrocarbons are released and

tests show less than 0.5% vol of hydrocarbons.

When the catalyst remains in the reactors and only other parts of equipment

are subject of opening, close the reactor block valves and keep a positive

pressure of nitrogen in the reactors from 0.5 to 0.8 Kg/cm2g.

When catalyst is to be unloaded, the pressure is decreased to atmospheric by

opening the top flange and the catalyst is discharged by catalyst unloading

nozzles.

Before entering any vessel, the testing for explosiveness, H2S content and

oxygen content is mandatory.

c) Splitter and stabilizer sectionsAll vessels, exchangers and piping are free from hydrocarbons by pumping

and draining to sewer.

The content of splitter bottom sent to off spec tank via stabilizer. The

remaining hydrocarbons in the splitter, reflux drum and piping should be

drained to closed hydrocarbons collecting system.

The stabilizer bottom should be sent to off-spec storage. The remaining liquid

must be drained. Take care not to pass hydrogen.

When all the liquid is drained from the system, temporary steam hoses are

connected to pumps, columns, and drums and steam out operation started.

This operation is usual in refineries and familiar to operators.

After steam out, cooling down the equipment is ready for opening of

manways, dismounting of flange joints, etc. Before entering any vessel, the

testing for explosiveness and hydrogen sulfide presence is mandatory.

Important notes1. Entry of personnel to vessels needs particular safety precautions. Vessels

operating in presence of H2S may contain sulfides adhered to the surface of

metal. These sulfides are pyrophoric and may release H2S. The forced

ventilation and permanent supervision is required on vessels subject to work

of personnel inside these vessels.

2. The nitrogen purge does not mean that vessel is ready for entering of

personnel. Nitrogen is suffocating gas leading to death. The vessels must be

fully vented and tested for oxygen content before admission of personnel

entry. The "dead" spaces in vessels such as down comers, separation weirs,

etc. must be considered.

8.2 UNIT RESTARTAny unit restart procedure derives from the first start-up procedure. The unit

status after the shutdown will dictate the point where the general start-up

procedure can be resumed.

For instance during a feed pump shutdown for a short duration, the unit

would be kept on standby with the make-up hydrogen flowing at full capacity, the

heater on and the reactor temperatures slightly lowered. The columns would

have no feed but the reboilers would be on and circulating at lower temperatures.

In this case, the restart procedure would begin at the steam-in step with levels

already in the vessels.

For a long duration shutdown, the unit has been cooled down, the SHU

reaction section filled with gasoline, the HDS reaction section left under pressure

of hydrogen and the columns under a nitrogen pressure.

The restart procedure will include the following steps: Start the columns at total reflux by admission of steam to reboiler and inert

naphtha via start-up lines.

Re-pressurize the reaction section to the operating pressure.

Start the 75-P-01 A/B pumps and feed the selective hydrogenation section at

60% of normal flow with raw gasoline.

The 75-E-03 feed steam heater is started by admission of steam.

The gasoline from the SHU reactor is sent to the splitter 75-C-01, the light,

heart cut and heavy FCC gasoline products from the splitter are sent to the

off-spec storage.

The HDS reaction section is started with circulation of hydrogen gas through

the recycle compressor 75-K-01 A/B.

The heater 75-F-01 is put in service and temperature gradually increased up

to 180°C.

The Amine absorber, filled with hydrogen, is lined up with other equipment of

the HDS reaction section, and the recycle gas circulated through the

absorber. Start circulation of amine solution.

When the products are on-spec, the splitter and the HDS section can be

connected. The heavy FCC gasoline product from the splitter is routed to the

HDS reacton section and stabilizer section.

When the product is on specification, slowly increase feed flowrate in steps of

5% up to 100%.

Catalyst sulfiding is not necessary if the catalyst has not been regenerated or

exposed to air during the long shutdown.

SECTION- 9 EMERGENCY SHUTDOWN PROCEDURE

9.1 EMERGENCY SHUTDOWN PROCEDURE9.1.1 GENERAL

Emergencies must be recognised and acted upon immediately. The

operators and supervisory personnel should carefully study in advance, and

become thoroughly familiar with, the steps to be taken in such situations. While

some of the emergencies listed in this section may not only result in a unit

shutdown, they could cause serious trouble on the unit if not handled properly. In

addition, damage to the catalyst might occur. In general the objective of the

emergency procedures is to avoid damage to equipment and catalyst.

Hard and fast rules cannot be made to cover all situations, which might arise.

The following outline lists those situations, which might arise and suggested

means of handling the situation.

Emergency shut down by Operators

Loss of feed

Loss of cooling water

Lack of hydrogen make-up

Loss of Amine

Quench pump failure

Fuel gas failure

Steam failure

Instrument air failure

Power Failure

Automatic shut down

9.1.2 EMERGENCY SHUTDOWN BY OPERATORSGeneralTypically, the following measures must be taken in an emergency situation to

shutdown a reaction unit:

SHU reaction section: Stop the feed steam heater 75-E-03.

Close the H2 make-up supply.

Shut-off the liquid feed to the reaction section.

Fully bypass SHU preheat train exchanger 75-E-01 and 75-E-02.

Stop LCN pump 75-P-04A/B

Stop FCC heart cut pump 75-P-05 A/B.

HDS reaction section: Shut-off the heater 75-F-01.

Stop the feed to the reactor.

If necessary, cool the reactor down through circulation of hydrogen.

When possible, the H2 circulation is maintained.

Otherwise, stop the compressor 75-K-01 A/B.

Close the H2 make-up.

Close the inlet/outlet lines on the Amine absorber.

Close the liquid outlet on the separator 75-V-03.

Close the purge gas on outlet of 75-C-02.

Close water outlet on the separator and BFW feed at upstream of 75-A-03air

cooler.

As a last resort, partial or total depressurization can be used to cool the

reactor down by opening the Emergency Shutdown Push Button on the

separator drum from control room or on site.

This unit is equipped with certain emergency shutdown controls which will

automatically place the unit in a non-hazardous status should a major failure

occur. The actions of the emergency shutdowns are aimed at protecting (a) the

personnel and (b) the catalyst and equipment from heavy coking or serious

damage.

Personnel and equipment protection also results from the following:

Personnel having a satisfactory knowledge of the safe operating and

shutdown procedures.

A compliance with the safety rules in plant construction i.e. safety distances,

adequate orientation etc.

The installation of adequate fire and gas detection devices and fire fighting

equipment.

Adequate operator safety awareness and procedures training.

Concerning the catalyst preservation, operators must avoid :

An excessive catalyst temperature gain which can change the structure of the

alumina (> 700°C). To avoid damaging the catalyst structure, bulk

temperature must never exceed 500°C. Note that the design temperature of

the reactor (under design pressure) is much lower.

The presence of hydrocarbons without a sufficient hydrogen quantity which

would result in a rapid coke deposit and the possible agglomeration of catalyst

particles.

The following sections cover most situations operators may have to face

according to Axens' operating experience. All operating personnel must study

and fully understand the steps to be taken in such situations prior to the unit start-

up.

Many of these situations are handled by automatic shutdown trips. These trips

must always be operational, by-passing must be kept to a minimum e.g. during

start-up, transient periods only.

The following procedures include all the actions to be taken by the operator

assuming no action by the automatic devices. Some of the following situations

may end up in an emergency shutdown. If the right and prompt action is taken,

an orderly normal shutdown is possible.

9.1.3 LOSS OF FEEDA loss of feed may be due to feed pump failure with an unexpected delay in

starting the spare pump or, more commonly, from leaks or other difficulties in the

feed line requiring an interruption of the feed. Loss of feed at the gasoline feed

pump is instantaneous and requires immediate action.

SHU section : If feed is still available to do this operation:

Stop the heater 75-E-03.

Close the H2 make-up supply.

Reduce the unit capacity to 60% of the feed capacity.

Switch the products to off-spec storage.

Stop the unit feed when the reactor temperature is at least 10°C below the

normal temperature.

Close the LCN line (from draw off tray) to storage and stop LCN pump 75-P-

04A/B.

Close the FCC heart cut line (from draw off tray) to storage and stop FCC

heart cut pump 75-P-05A/B.

Allow the splitter to operate on total reflux.

If interruption is to take place for several hours, short shutdown procedure

should be implemented.

When flow to the reactor is re-established, start H2 feed and return to previous

operating temperatures if the feed is shortly recovered.

HDS section:In case of short period loss of feed to the HDS section,

Maintain H2 circulation.

Allow the stabilizer to operate on total reflux.

When the level in the stabilizer starts to fall, close the valves on the stabilizer

bottom and heavy FCC gasoline line to storage.

Maintain these conditions until feed is available again. Maintain pressure in

the HDS reaction section by hydrogen make-up.

Start-up again from former current reactor operating temperature if the feed is

recovered shortly. If not proceed with the normal shutdown as previously

explained (Refer to section “Shutdown of the unit/ Normal shutdown/ Short

duration shutdowns”). Do not leave catalyst under a hot hydrogen circulation for

more than 12 hours, unless the H2S content in the recycle is maintained between

100-200 ppm vol. Note also that an increased H2S content while circulating hot

hydrogen would be the sign of a catalyst desulfiding and would require the

cooling down of the catalyst bed.

9.1.4 LOSS OF COOLING WATERIn case of partial or total cooling water failure, the splitter and stabilizer

overhead will be hotter, and the products to storage will be hotter than normal.

Also, the HDS reactor effluent will be hotter before entering the HDS

separator drum 75-V-03 and vapour phase will be larger leading to a potential

pressure increase of the HDS section.

Reduce the steam flow to the splitter and stabilizer reboiler, 75-E-07/75-E-13

and eventually stop it if the cooling water is not recovered.

Increase the air coolers to their maximum capacity if possible.

Increase vapor purge in HDS section to recover H2 recycle purity as much as

possible.

Route the products to the off-spec storage.

9.1.5 LACK OF HYDROGEN MAKE-UPThe reaction pressure will decrease quickly and if no action is taken, the

catalyst will coke due to hydrogen shortage to saturate the cracked material. The

feed rate has to be decreased rapidly to 50%.

If at 80% of the normal operating pressure, the hydrogen is not restored to

the reaction, the feed has to be cut by stopping the feed until the make-up gas is

back or the normal shutdown procedure should continue.

9.1.6 LOSS OF AMINEIncrease the reactor temperature to achieve the required HDS at a higher

octane loss. The stabilizer operation should be monitored to control the H2S in

the heavy FCC gasoline product.

9.1.7 QUENCH PUMP FAILUREReduce the firing of HDS reactor feed heater to maintain HDS reactor inlet

temperature and to maintain the same WABT provided the reactor DT is not

excessive. Over temperature may cause the shut down of HDS feed heater 75-F-

01, stopping feed and H2 make-up.

9.1.8 FUEL GAS FAILUREThe HDS reactor feed heater will shutdown shutdown as well as the reboiling

of the splitter and stabilizer.

Cut raw gasoline feed immediately and proceeds as per loss of feed.

Follow refinery safety practice for isolation of fuel gas system.

9.1.9 STEAM FAILUREA lack of steam leads to SHU feed steam heater 75-E-03, splitter reboiler 75-

E-07 and stabilizer reboiler 75-E-13 failure.

Cut raw gasoline feed completely, as unstable gasoline product with H2S

cannot be sent to storage.

Follow the same procedure as per loss of feed.

9.1.10 INSTRUMENT AIR FAILUREThe valves take their safe positions according to the fail-open or fail-close

specification. The loss of instrument air pressure is generally slow and there is

time to proceed to a normal shutdown.

9.1.11 POWER FAILUREIt is assumed that all electrical equipment in the unit will shutdown including

air coolers, recycle compressor, and all pumps

The operator shall complete the shutdown procedure with the following actions:

Initiate the I-102 for stopping H2 make up and steam to steam heater 75-E-

03.

Stop heater 75-F-01. Watch the tube skin temperature in heater. If there is an

increasing trend, open the air damper and inject sufficient steam.

Isolation of the feed and make-up gases

Isolation of the product lines by closing control and block valves.

Closing of block valve downstream control valve FV-2901 on stabilizer bottom

outlet line.

Shut-off steam to the reboiler of stabilizer and splitter.

Maintain pressure in the reaction section. If necessary, inject nitrogen in the

stabilizer to maintain pressure.

There is a potential danger for increased hydrocracking in the reactors which

are idle with no flow of hydrogen to strip the hydrocarbons. If power outage is

suspected for a long duration, depressurize the reaction section to flare.

If the critical equipment is fed by an emergency power supply, the operators

must be familiar with the list of equipment that is able to be restarted

immediately.

In addition, the general philosophy is to restart the equipment in the following

order:

- Air fin cooler

The compressor, in order to resume the hydrogen circulation and cool down

the reactors or to maintain the reactors inlet temperature after restarting the

heater.

The reflux pumps of the column, in order to bring under control the overhead

temperature and pressure.

The remaining electrical equipment is restarted as required by the start-up

procedure.

9.1.12 FIRE OR MAJOR LEAK

The following is only an overview of the steps to be taken during the discovery

of a leak resulting in a fire. This section will be defined in detail by the Unit Owner

and the Engineering Contractor according to the refinery safety philosophies and

will include any safety devices (hardware or software) which may be added

during detailed engineering. The following steps are described from a process

point of view, mainly aimed at avoiding runaway reactions and protecting the

equipment and catalyst.

Shut-off fuel to heater by activating the fuel gas emergency shutdown system

from the control room.

Shutdown the raw gasoline feed pump, close the splitter and stabilizer feed

and block-in.

Shut-off steam to the reboiler of the splitter and stabilizer, and to the SHU

feed steam 75-E-03.

Isolate the unit: Block the feed, product and hydrogen make-up gas lines.

Isolate the reaction section from the feed, splitter and stabilizer sections.

Depending on the severity of the leak and its location, shutdown the hydrogen

recycle compressor immediately, block-in and depressurize the HDS reaction

section to the flare.

Depressurize the splitter and stabilizer sections to the flare.

Drain all the vessels to the hydrocarbon blowdown.

As the depressurized hot vessels cool down, watch the pressure and inject N2

as necessary to avoid a vacuum.

Nitrogen purging and steam out should be considered for the splitter and

stabilizer circuits.

If a fire has occurred, then all the steps above will be taken while the fire

fighting is taking place. Note, however, that the depressurizing step may be

needed sooner than described above depending upon the gravity of the situation.

If a small leak occurs in the heater, the hydrocarbons will ignite immediately in

this confined area. Open the snuffing steam and the damper (if possible) and

maximize the draft to keep the fire under control within the heater box.

In case of extreme emergency, the reaction section can be depressurized to

the flare, using the quick depressurization valve by actuating HS-2401

emergency shut down push button.

9.1.13 AUTOMATIC EMERGENCY SHUTDOWNThe actions undertaken in any emergency situation must aim at the following:

Protecting the operators.

Protecting the equipment and the catalyst.

Resulting in a safe situation compatible with an easy restart.

Process vessels, heater, compressors are fitted with switches which actuate

the corresponding devices to avoid damage of equipment in case that operating

variable exceeds the threshold limits. Hereafter are summarized the causes and

effects for the unit shutdown interlocks. Causes and effects for the equipment

safety interlocks are summarized in the Process Book. Other interlocks have to

be specified by Engineering Contractor or Manufacturer of equipment (heater,

compressor, etc).

In several cases, a number of actions are carried out by the emergency safety

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, who can

anticipate the automatic action such as reactors depressurization.

SECTION- 10 TROUBLE SHOOTING

10.1 TROUBLE SHOOTINGThis section offers some guidelines for trouble shooting various problems

that may be encountered over the course of normal operation of the unit and

effects on incoming / out going conditions. The information is given for the

following general subject areas of the unit:

10.1.1 HIGH DIFFERENTIAL PRESSURE (DP) IN THE REACTORHigh pressure drop

This unit is designed for a given maximum reactor pressure drop. During

normal operation the pressure drop will be lower than indicated in the section

1.1.5 of the Process data Book. The reactor pressure drop indicator is transmitted

to the DCS and the trend data will allow the operator to predict when the unit

needs to be shutdown for catalyst skimming.

DP is strongly dependent on the feed quality (precursors of coke in the

feed). That is why a special attention to the feed quality must be taken.

The pressure drop of the HDS reactor, is also dependent on the

performance of the selective hydrogenation reactor.

Leak of SHU feed in HDS effluent / HDS feed in HDS effluent / stabilizer

feed in stabilizer bottoms

Since, for these 3 equipments, the fluid with higher sulfur content is at

higher pressure, contamination of the hydrotreated gasoline is possible. When

sulfur shows up in the stabilizer bottoms and all the proper corrective actions

have been taken with no improvement, then it is highly likely that a leak exists in

either the SHU feed/HDS effluent or reactor feed effluent exchangers or stabilizer

feed bottoms exchangers. These leaks can be easily detected through sampling

upstream and downstream.

10.1.2 CHEMICAL H2 CONSUMPTION INCREASE

Hydrogen gas make up to Selective hydrogenation reactor 75-R-01 In normal operation, the H2 supply to the diolefin reactor is under flow ratio

to the feed. Increased H2 consumption may result from excessive olefin

saturation or higher diolefins content in the feed. Monitoring of the MAV at the

splitter bottom should be used to adjust the make-up H2 rate.

Hydrogen gas make up to HDS reactor 75-R-02 This situation can occur if the olefins content of the feed is higher than

expected, and also if the unit is oversaturating the olefins. The H2 consumption

could be controlled by decreasing the reactor severity without impacting the

product quality.

10.1.3 OCTANE LOSSESA significant octane loss means a too high olefin hydrogenation in the

reactors. This could be controlled by decreasing the reactor severity.

SECTION- 11 SAMPLING PROCEDURE AND LABORATORY ANALYSIS

11.1 GENERALControl tests provide the information to the operating staff for making

necessary adjustments to get the maximum output and “on-spec” quality

products. The control tests are to be made at all steps to monitor the intermediate

and final products whether or not they are at the desired specification. Samples

are taken and analysed at regular intervals such that the operation of the plant

are monitored and any deviation (from specification will indicate some mal

operation / malfunction of the plant which can be spotted and rectified in time

without undue loss of time and product. Sometimes, samples are taken to find out

the effect of certain changes brought about in the operating conditions. The

samples are to be taken with great care so that the samples are representative

samples. The frequency of sampling, the type of analysis and points where

samples are to be taken are attached as annexure. During guarantee tests some

additional samples can be taken at higher frequencies that is also specified in the

technical procedures prior to test run. The following guidelines should be followed

while collecting samples.

11.2 SAMPLING PROCEDURE

a) Liquid Sampling Procedure (Non-Flashing Type)The person taking samples should wear proper or appropriate safety clothing like

face shields, aprons, rubber gloves etc. to protect face, hands and body.

1. Whenever hot samples are taken, check cooling water flow in the sample

cooler is circulating properly.

2. Sample points usually have two valves in series. One gate valve for isolation

(tight shutoff) and other globe valve for regulating the flow. Open gate valves

first and then slowly open the globe valve after properly placing the sample

containers. After the sampling is over, close the globe valve first and then the

gate. Then again open the globe valve and drain the hold up between the

gate and globe valve in case of congealing liquid.

3. Sample valve should be slowly opened, first slightly to check for plugging. If

the plugging is released suddenly, the liquid will escape at a dangerously

uncontrolled rate. Never tap the line to release the plugging. Call the

maintenance gang to properly unplug the line. In case of congealing type

samples, sample point should be equipped with copper coil type steam tracer.

It should be ensured that steam tracing line is functioning normally.

4. The operator taking the sample should be careful to stand in a position such

that the liquid does not splash on him and he has unobstructed way out from

the sample point in case of accident.

5. While taking dangerous toxic material for sampling, it will act as an observer

for safety. Proper gas mask is to be used. It is advisable to stand opposite to

wind direction in case of volatile toxic liquid.

6. Sample should be collected in clean, dry and stoppered bottle. In case of

congealing samples use clean dry ladle.

7. Rinsing of the bottle should be thorough before actual collection.

8. Before collecting, ensure that the line content has been drained and fresh

sample is coming.

9. Gradually warm up the sample bottle / metallic can by repeated rinsing before

collecting the sample.

10. Stopper the bottle immediately after collection of sample.

11. Attach a tag to the bottle indicating date, time, and name of the product and

tests to be carried out.

12. A few products suffer deterioration with time.

For example, the colour of the heavier distillates slowly deteriorates with time.

So these sampls should be sent to laboratory at the earliest after collection.

1. The samples after collection should be kept away from any source of ignition

to minimise fire hazard.

2. Volatile samples (e.g. naphtha) should be collected in bottles and kept in ice

particularly for some critical test like RVP.

b) High Pressure Hydrocarbon Liquid Samples (Flashing Type)

The person who is taking sample should use personal protection appliances

like apron, gas mask and hand gloves to protect himself.

1. Ensure that sample bomb is empty, clean and dry.

2. Connect the sample bomb inlet valve to the sample point with a flexible hose.

3. Open the inlet and outlet valves of the sample bomb. Hold the sample bomb.

Hold the sample bomb outlet away from person. Keep face away from

hydrocarbon vapour and stand in such a way that prevalent wind should blow

hydrocarbon vapour away. Open the gate valve of sample point slowly till full

open. Then slowly cracks open the regulating valve. One should be careful at

the time of draining, because chance of icing is there. As a result, the

formation of solid hydrates is a continuing process that leads to the plugging

of valves.

4. When all the air in the hose and bomb are displaced as seen by the

hydrocarbon vapour rising from the outlet of sample bomb close the sample

outlet valve. Allow a little quantity of liquid to spill to make sure that the bomb

is receiving liquid. Frosting will be an indication of liquid spillage.

5. Allow liquid hydrocarbon to fill the bomb. When the bomb is full up to the

specified level, close both the valves on sample point. Close inlet valve on the

sample point.

6. Carefully disconnect the hose from the sample bomb. To allow for some

vapour space in the bomb for thermal expansion in case of overfilling, crack

open the outlet valve of bomb and discharge a small part of the liquid. Close

outlet valve.

7. Closed sampling facilities are provided at some locations where it is not

desirable to waste the costly product or if the material is toxic. For filling the

sampling bomb, pressure drop across a control valve is usually utilised or

across pump discharge & suction. Air is expelled from the bomb after it is

connected to upstream of control valve or pump discharge side. The sample

is then collected and bomb is detached after closing valves on both sides.

8. Send sample bomb to laboratory for analysis. Protect the bomb from heat

exposure.

c) Gas Sample

For collection of gas sample that are not under high pressure and

temperature, rubber bladders are used. For the operations under vacuum or low

pressure, aspirator is used. For representative sample, purge the bladder 3 to 4

times with the gas and then take t he final sample. Use of 3 ways valve with

bladder / aspirator will facilitate purging and sampling.

Sample bombs are to be used for taking gas samples from high pressure and

high temperature source. Procedure mentioned under high pressure liquid

sampling (flashing type) is to be used.

Sampling method and schedule:

Sr. No. Stream Analyse Method Frequency/day

1 Feed from

FCC1&2

Distillation

Sp. Gravity

Sulphur spec

Total sulphur

ASTM D86

ASTM D-1298

IFP 9416

ASTM D-2622

1

1

As required

1

2 Cold feed from

storage

Mercaptans

Olefins

Bromine number

Diene (MAV)

ASTM D-3227

IFP 0104 /

ASTM D1319

ASTM D-1159

IFP 9407

As required

1

1

2 per week

3 HDS feed Diolefin content

Existing gum

Total nitrogen

RVP

RON

MON

IFP 0104

ASTM D-381

ASTM D4629

NF M 07-007

ASTM 2699

ASTM 2700

As required

As required

As required

As required

1

1

4 SHU H2 make up Gas

chromatography

IFP 9603 1

5 HDS H2 make up

from isom unit

Gas

chromatography

IFP 9603 1

6 HDS H2 make up

from CCR unit

Gas

chromatography

IFP 9603 As required

7 Effluent 75-R-01 Olefins

Bromine number

Diene (MAV)

Diolefin content

IFP 0104 /

ASTM D1319

ASTM D-1159

IFP 9407

IFP 0104

As required

As required

2 per week

As required

8 Light FCC

gasoline

Distillation

Sulphur spec

Sp gravity

Total sulphur

ASTM D86

IFP 9416

ASTM D-1298

ASTM D-5453

As required

As required

As required

1

9 FCC heart cut

gasoline

Mercaptans

Olefins

Bromine number

Diene (MAV)

Diolefin content

RON

MON

RVP

ASTM D-3227

IFP 0104 /

ASTM D1319

ASTM D-1159

IFP 9407

IFP 0104

ASTM 2699

ASTM 2700

NF M 07-007

As required

As required

1

As required

As required

As required

As required

As required

10 Splitter reflux

drum off gas

Gas

chromatography

IFP 9603 As required

11 Stabilizer feed Total sulphur

Olefins

Bromine number

Diene (MAV)

ASTM D-2622

after H2S

washing

IFP 0104 /

ASTM D1319

ASTM D-1159

IFP 9407

As required

As required

As required

As required

12 HDS purge gas Gas

chromatography

H2S

IFP 9603

Dragger tube

As required

As required

13 Recycle gas to

amine

Gas

chromatography

H2S

IFP 9603

Dragger tube

As required

As required

14 Recycle gas from

amine

Gas

chromatography

H2S

IFP 9603

Dragger tube

1

1

15 Heavy FCC

gasoline

Distillation

Sulphur spec

Sp gravity

Total sulphur

Mercaptans

Olefins

Bromine number

Diene (MAV)

Diolefin content

RON

MON

ASTM D86

IFP 9416

ASTM D-1298

ASTM D-5453

ASTM D-3227

IFP 0104 /

ASTM D1319

ASTM D-1159

IFP 9407

IFP 0104

ASTM 2699

ASTM 2700

As required

As required

As required

1

As required

As required

1

As required

As required

As required

As required

16 Stabilizer purge

gas

Gas

chromatography

H2S

IFP 9603

Dragger tube

As required

As required

17 HDS separator

sour water

PH ASTM D 1293 As required

SECTION- 12 SAFETY PROCEDURE

12.1 INTRODUCTIONSafety of personnel and equipment is very important. Ignorance of the

details of the unit or the techniques of safe and efficient operation reduces the

margin of safety of personnel and subjects the equipment to more hazardous

conditions. All the operating and maintenance crew therefore must be fully

familiar with the equipment and materials being handled in the unit, and

recognise the hazards involved in handling them and the measures taken to

ensure safe operations.

Since the unit handles with one of the most potential source of fire and

explosion like LPG; therefore adherence of safety rules should be given uphill

importance.

12.2 PLANT SAFETY FEATURES12.2.1 GENERAL

Safety is the first consideration for all operations in the plant. Procedures,

practices, and rules have been established as guides to assure a safe working

environment. Safety also plays a major role in the efficient operation of the

refinery facilities.

This section is prepared to reemphasize the plant safety incorporated in the

unit and equipment design.

12.2.2 EMERGENCY SHUTDOWNThe emergency shutdown is already described

These different shutdowns are completed by different trips to protect the main

equipment and to prevent any misoperation. Alarms always precede these trips,

they allow operators to have corrective actions before the automatic shutdown.

12.2.3 OVERPRESSURE PROTECTIONOver pressure of equipment occurs in many ways. The basic reason of

overpressure is imbalance in heat and material flow in one or more equipment.

Pressure relief valves have been installed after careful evaluation of conceivable

of overpressure sources.

12.2.4 SAFETY SHOWER AND EYE WASHSafety shower and eye wash stations are located in the chemical handling areas.

12.2.5 OPERATIONAL SAFETY STATIONSThe safety rules and instructions also emphasise safety hazards. Safe

behaviour, practices and habits are necessary for safe and efficient operation of

the unit.

12.2.6 HIGH PRESSUREOn high-pressure lines, extreme caution must be taken when opening any

sample or bleed valve. Improper opening or shut-off of some valves on

interconnecting lines may result in exceeding pressure limits on vessels,

exchangers, valves and lines.

Improper isolation of lines vessels, exchangers, pumps may result in very

high pressure due to thermal expansion of a liquid enclosed inside.

12.2.7 REACTOR PROTECTIONManufacturer of the reactors provides the following information necessary for

the operation:

Pressure versus temperature diagram,

Rate of temperature increases and decreases,

Rate of pressurizing and depressurizing the reactor,

Risk of polythionic acids corrosion.

12.2.8 PERSONNEL PROTECTIONThe refinery personnel has to be aware of the different materials involved in

the process: dangerous or toxic materials. Any chemical used in the plant should

have its toxicity recorded and the first aid labeled.

HydrogenHydrogen is a flammable gas, which in concentrations from 4.1 to 74%

volume in air is explosive.Care must be taken to purge the air out of the unit as

required before start-up and to purge hydrogen of the unit for shutdown.Tightness

tests are to be made before all start-ups on every vessel containing or likely to

contain hydrogen.

Operators must continually inspect each equipment and flanges for leaks.

All leaks require immediate action. The pressure reduction results in heating of

hydrogen contrary to hydrocarbons, or other gases which are cooled down

(Joule-Thomson effect). When heated above its ignition temperature by pressure

release from high pressure the hydrogen gas starts to burn in presence of air.

Hydrogen sulfide H2S

a) Physical propertiesPhysical state : gas

Color: : colorless

Boiling point : -79.2°F (-61.8°C)

Melting point : -117.2°F (-82.9°C)

Molecular weight : 34.08

Specific gravity/air : 1.189

b) Chemical and hazardous propertiesHydrogen sulfide is one of the most dangerous material handled in oil

industry. Two types of hazards must be taken into account: explosive nature,

extreme toxicity when mixed with air or sulfur dioxide.

The maximum safe concentration of hydrogen sulfide is about 13 ppm.

Although at first this concentration can be readily recognized by its odor,

hydrogen sulfide may partially paralyze the olfactory nerves to the point at which

the presence of the gas is no longer sensed.

Therefore, though the odor of the gas is strongly unpleasant, it is neither a

reliable safeguard nor a warning against its poisonous effects. Hydrogen sulfide

in its toxic action, attacks nerve centers. Early symptoms of poisoning are slight

headache, burning of eyes and clouded vision. A concentration of 100 ppm of

hydrogen sulfide in air causes coughing, irritation and loss of smell after 2-15

minutes and drowsiness after 15-30 minutes.

A concentration of 1000 ppm of hydrogen sulfide in air can make person

suddenly unconscious with early cessation of respiration and death in a few

minutes.

Hydrogen sulfide is a combustible material and, when mixed with air or

sulfur dioxide, may be explosive. It is essential, therefore, to avoid such mixtures

in the processing of hydrogen sulfide. The explosive range of hydrogen sulfide in

air is from 4.5-45%. The ignition temperature of such mixtures is around 250°C.

Some precautions against poisoning to be taken in working with hydrogen

sulfide are:

Closed in areas should be well ventilated preferably with forced draft.

Equipment containing hydrogen sulfide should be tightly sealed. Any leaks

should be repaired immediately.

At seals or stuffing boxes where leaks might occur during normal operation,

means should be provided for venting the escape gas to a safe location.

Vessels should be purged of hydrogen sulfide before being opened.

Masks furnishing purge air should be worn by personnel who are likely to be

exposed to the gas.

Personnel who may be exposed to even low concentrations of this gas should

frequently retire to areas of fresh air.

As a good safety measure, personnel should learn to recognize the early

symptoms of hydrogen sulfide poisoning.

c) Detection of hydrogen sulfideA simple test with lead acetate solution on white paper will detect the

presence of hydrogen sulfide. Depending on the concentration the paper will turn

yellow or brown.

Adequate Dragger tubes can be used in the same way.

d) Personal protectionGas mask of appropriate type or positive air mask should be used.

e) First aidA person unconscious in an atmosphere which may be contaminated with

hydrogen sulfide should be assumed to have hydrogen sulfide poisoning. This is

a serious medical emergency and requires immediate attention. The affected

individual should be immediately removed to a clean atmosphere, so that

rescuers are not also exposed to hydrogen sulfide. Artificial respiration should be

resorted immediately, if necessary, and the victim should be kept warm and at

rest.

DMDSThe material safety data sheet must be obtained from the

manufacturer/supplier.

Catalysts

The material safety data sheets for HR 845, HR 806, HR 841, ACT 065, ACT 077

and ceramic balls are attached in Attachment

12.3 SAFETY OF PERSONNELGeneral safety rules, which shall be practised and enforces for all personnel

who enter the unit, are summarised below:

1. Safety helmets and boots shall be worn by all personnel at all times in the plant.

They may be removed when inside rooms or buildings that do not have

overhead or other hazards.

2. Smoking shall be permitted only in specified areas, which are clad as non-

hazardous and are pressurized through a ventilation system. Failure of the

ventilation system automatically cancels the smoking privilege until the system

is repaired, inspected and authorised operation.

3. Each employees assigned to work in the unit shall know where the safety and

fire suppression equipment is located and how to operate this equipment.

4. Safety glasses, goggles or face shields shall be worn while performing work,

which could result in eye or face injury.

5. Operations personnel golden rule

Do not open or close any valve without first determining the effect.

6. Maintenance personnel golden rule:

Treat each piece of equipment or piping as if it is under pressure.

12.4 WORK PERMIT PROCEDUREThe appropriate operations group must issue a work permit system before

commencing any maintenance work affecting the operation of the unit. The work

permit is issued for “Hot” and “Cold” work. The “Hot” work permit must include as

a minimum, a precise description and mode of execution of “Hot” works, the

equipment to be used, the expected time which “Hot” works is scheduled to start

and expected completion, an exact location of the “Hot “ works and precautions

to be taken.

Unit areas are generally identified as hazardous areas as far as the threat of

fire is concerned. Therefore, in order to carryout works within these areas, a

written work permit is required. The work permit, when approved, indicates that a

specific work can be carried out in safe conditions provided that all safety

precautions are observed.

a) Permit for “Hot” workPermits of hot works are required for any work involving the use of or

generation of heat sufficient to ignite flammable substances.

Typical sources of ignition are:

Electric and gas welding

Any machine capable of producing a spark

Not explosion-proof electrical equipment

Internal combustion engines

Ferrous tools, both hand operated and pneumatic or other type

b) Permit for Cold-WorkPermits for cold-work are required for any work not involving the use of a local

ignition source.

Typical examples of cold work are:

Disconnecting of lines for the insertion of blinds, etc

Opening of any equipment such as vessels, filters, etc.

c) Entry permitsEntry permits are required for entering enclosed spaces such as vessels,

sewer, pits, trenches, etc.

The use of any tool or machinery, which could provide a source of ignition, is

forbidden. Also, prior to entry it should be ensured that area is well ventilated and

the oxygen content in air is about 21% by volume. A fresh airflow to be ensured

in the enclosed space through out the duration of work. A gas test for H2S and

flammable gases should also be performed before entry. A person should also be

on alert outside the enclosed space for rescue in case of emergency. Procedure

for carrying out work and rescue plan shall be formulated before commencement

of work.

d) Guidelines for release of permits The equipment item, on which works have to be carried out, shall be clearly

indicated. During the shutdown of any system, permits covering the whole

section with above-mentioned item shall be issued, if possible. The type of

work permitted shall be clearly indicated.

The date and the period of validity of the permit shall also be indicated. If the

work does not get over within the period of validity of the permit, the permit

can be extended provided that, at each start of the works the safety conditions

are checked again and signed by the operator in-charge and by safety officer.

Beyond this extended period, a next permit will have to be issued. The

explosiveness test and the check of toxic gases shall be performed always at

the last moment before each start of the work and subsequently every time

the work is resumed or whenever doubts arise.

The validity of the permit can be cancelled at any moment by the operator or

by safety officer in case they deem that the conditions are not safe.

The conditions to be complied with shall include special precautions, such as

the use of protective clothing, breathing apparatus, safety equipment and the

tools to be used etc.

No one shall be allowed to enter the vessel or other enclosed spaces without

suitable protective clothing until the vessels or the enclosed spaces become

safe for entry by means of proper isolation, proper ventilation and suitable

check of the atmosphere inside and availability of rescue person outside the

enclosed equipment.

If welding or hot work is to be done ensure that

Fire fighting system is ready

Close the neighbouring surface drains with wet gunny bags

Keep water flowing in the neighbouring area to cool down any spark.

Responsible operation supervisor should be present at the place of hot work

till the first torch is lighted.

12.5 PREPARATION OF EQUIPMENT FOR MAINTENANCE

a) Process Equipment: Towers, Vessels etc. Before opening any equipment, it should be purged to render the internal

atmosphere non-explosive and breathable. Operations to be carried out are: -

Isolation with valves and blinds.

Draining and depressurisation.

Replacement of vapours or gas by steam, water or inert gas.

Take care about instrument tapping.

Washing of towers and vessels with water.

Ventilation of equipment.

Opening of top manhole.

Testing of inside atmosphere with explosive meter.

Complete opening if inside atmosphere is satisfactory.

Analyse the atmosphere inside for O2 content and any poisonous gas.

Note:Open a vent on the upper part of the vessel to allow gases to escape during

filling and to allow air inside the vessel during draining. Ensure proper ventilation

inside the vessel by opening all manholes. For hydrocarbon or other gases,

pressurise the vessel with N2 or gas and fill in the liquid and drain under pressure.

This is to avoid hydrocarbon going to atmosphere.

b) Precautions Before Handing Over Equipment A responsible operating supervisor should check following items before

equipment is handed over for maintenance after it has been purged.

Assure that equipment is isolated by proper valves and blinds.

Ascertain that there is no pressure of hydrocarbons in the lines, vessels and

equipment.

Purge the system with N2 first and later by air and check for O2 content at vent

and drain to ensure that the vessel is full of air.

Check that steam injection lines and any inert line connections are

disconnected or isolated from the equipment.

Provide tags on the various blinds to avoid mistakes. Maintain a register for

blinds.

Check for pyrophoric iron and if existing, keep this wet with water.

Keep the surrounding area cleaned up.

Get explosive meter test done in vessels, lines, equipment and surrounding

areas.

If welding or hot work is to be done, also: Keep fire-fighting devices ready for use nearby.

Close the neighbouring surface drains with wet gunny bags.

Keep water flowing in the neighbouring area to cool down any spark bits etc.

Keep stem lancers ready for use.

After the above operations have been made, a safety permit should be

issued for carrying out the work. A responsible operating supervisor should be

personally present at the place of hot work till the first torch is lighted. Hot work

should be immediately suspended if instructed by the supervisor or on detecting

any unsafe condition.

When people have to enter a vessel for inspection or other work, one

person should stand outside near the manhole of the vessel for any help needed

by the persons working inside. The person entering the vessel should have tied

on his waist a rope to enable pulling him out in case of urgency. Detail procedure

for preparation for vessel entry is given in next sub-section.

12.6 PREPARATION FOR VESSEL ENTRY12.6.1 GENERAL PROCEDURE

Whenever a Licenser technical advisor must enter a vessel a meeting

should be arranged between Licenser and the plant personnel who will be

involved. The meeting should include review of the Licenser vessel entry

procedures, the refiner’s safety requirements and facilities, preparation of a

vessel entry schedule, assignment of responsibility for the preparation of a blind

list, and assignment of responsibility for the vessel entry permits.

The most common tasks of a Licenser technical advisor that requires

potentially hazardous vessel entry are:

Unit Checkout Prior to Start-up

Turnaround Inspections

Vessel internals

The precautions apply equally to entry into all forms of vessels, including

enclosed areas, which might not normally be considered vessels.

Positive Vessel IsolationEvery line connecting to a nozzle on the vessel to be entered must be

blinded at the vessel. This includes drains connecting to a closed sewer, utility

connections and all process lines. The location of each blind should be marked

on a master piping and instrumentation diagram (P&ID), each blind should be

tagged with a number and a list of all blinds and their locations should be

maintained. One person should be given responsibility for the all blinds in the

unit to avoid errors.

The area around the vessel man ways should also be surveyed for possible

sources of dangerous gases that might enter the vessel while the person is

inside. Examples include acetylene cylinders for welding and process vent or

drain connections in the same or adjoining units. Any hazards found in the

survey should be isolated or removed.

Vessel AccessSafe access must be provided both to the exterior and interior of the vessel

to be entered. The exterior access should be a solid, permanent ladder and

platform or scaffolding strong enough to support the people and equipment that

will be involved in the work to be performed.

Access to the interior should also the strong and solid. Scaffolding is

preferred when the vessel is large enough to permit it to be sued. The

scaffolding base should rest firmly on the bottom of the vessel and be solidly

encored. If the scaffolding is tall, the scaffolding should be supported in several

places to prevent sway. The platform boards should be sturdy and capable of

supporting several people and equipment at the same time and also be firmly

fastened down. Rungs should be provided on the scaffolding spaced at a

comfortable distance for climbing on the structure.

If scaffolding will not fit in the vessel a ladder can be used. A rigid ladder is

always preferred over a rope ladder and is essential to avoid fatigue during

lengthy periods of work inside a vessel. The bottom and top of the ladder should

be solidly anchored. If additional support is available, then the ladder should also

be anchored at intermediate locations. When possible, a solid support should

pass through the ladder under a rung, thereby providing support for the entire

weight should the bottom support fail. Only one person at a time should be

allowed on the ladder.

When a rope ladder is used, the ropes should be thoroughly inspected prior

to each new job. All rungs should be tested for strength, whether they are made

of metal or wood. Each rope must be individually secured to an immovable

support. If possible, a solid support should pass through the ladder so that a

rung can help support the weight and the bottom of the ladder should be fastened

to a support to prevent the ladder from swinging. As with the rigid ladder, only

one person should climb the ladder at a time.

Wearing of a Safety Harness

Any person entering a vessel should wear a safety harness with an

attached safety line. The harness should be strong and fastened in such a

manner that it can prevent a fall in the event the man slips and so that it can be

used to extricate the man from the vessel in the event he encounters difficulty. A

parachute type harness is preferred over a belt because it allows an unconscious

person to be lifted from the shoulders, making it easier to remove him from a tight

place such as an internal man way.

A minimum of one harness for each person entering the vessel and at least

one spare harness for the people watching the man way should be provided at

the vessel entry.

Providing a Man way Watch

Before a person enters a vessel, there should be a minimum of two people

available outside of the vessel, one of who should be specifically assigned

responsibility to observe the activity of the people inside of the vessel. The other

person must remain available in close proximity to the person watching the man

way so that he can assist or go for help, if necessary. He must also be alert for

events outside of the vessel, which might require the people inside to come out of

the vessel, for example, a nearby leak or fire. These people should not leave

their post until the people inside have safely evacuated the vessel.

A communication system should be provided for the man way watch so that

they can quickly call for help in the event that the personnel inside of the vessel

encounter difficulty. A radio, telephone, or public address system is necessary

for that purpose.

Providing Fresh AirThe vessel must be purged completely free of any noxious or poisonous

gases and inventoried with fresh air before permitting anyone to enter. The

responsible department, usually the safety department, must test the atmosphere

within the vessel for toxic gases, oxygen and explosive gases before entry. This

must be repeated every 4 hours while there are people inside the vessel. When

possible the Licenser technical advisor should personally witness the test

procedure. Each point of entry and any dead areas inside of the vessel, such as

receiver boots or areas behind internal baffles, where there is little air circulation

should be checked.

Fresh air can be circulated through the vessel suing an air mover, a fan, or,

for the cases where moisture is ca concern, the vessel can be purged using dry

certified instrument air from a hose or hard piped connection. When an air mover

is used, make certain that the gas driver uses plant air, not nitrogen, and direct

the exhaust of the driver out of the vessel to guarantee that this gas does not

enter the vessel. When instrument air is used, the Licenser technical adviser

must confirm the checking of the supply header to ensure that it is properly lined

up. It should be confirmed that there are no connections where nitrogen can enter

the system (Sometimes nitrogen improperly used as a backup for instrument air

by some refiners). The fresh air purge should be continued throughout the time

that people are inside of the vessel. The responsible control room should be

informed that instrument air is being used for breathing so that if a change to

nitrogen is required the people are removed from the affected vessel.

A minimum of one fresh air mask for each person entering the vessel and at

least one spare mask for the Manway watcher should be provided at the vessel

entry. These masks should completely cover the face, including the eyes, and

have a second seal around the mouth and nose. When use of the mask is

required, it must first be donned outside of the vessel where it is easy to render

assistance in order to confirm that the air supply is safe. Each mask must have a

backup air supply that is completely independent of the main supply. It must also

be independent of electrical power. This supply is typically a small, certified

cylinder fastened to the safety harness and connected to the main supply line via

a special regulator that activates when the air pressure to the mask drops below

normal. The auxiliary supply should have an alarm, which alerts the user that he

is on backup supply and it should be sufficiently large to give the user 5 minutes

to escape from danger.

12.6.2 PREPARATION OF VESSEL ENTRY PERMITBefore entering the vessel a vessel entry permit must be obtained. A vessel

entry permit ensures that all responsible parties know that work is being

conducted inside of a vessel and establishes a safe preparation procedure to

follow in order to prevent mistakes, which could result in an accident. The permit

is typically issued by the safety engineer or by the shift supervisor. The permit

should be based on a safety checklist to be completed before it is issued. The

permit should also require the signatures of the safety engineer, the shift

supervisor, and the person that performed the oxygen toxic and explosive gas

check on the vessel atmosphere. Four copies of the permit should be provided.

One copy goes to the safety engineer, one to the shift supervisor, one to the

control room, and one copy should be posted prominently on the man way

through which the personnel will enter the vessel. The permit should be renewed

before each shift and all copies of the permit should be returned to the safety

engineer when the work is complete. The refiner may impose additional

requirements or procedures, but the foregoing is considered the minimum

acceptable for good safety practice.

12.6.3 CHECKOUT PRIOR TO NEW UNIT START-UPThe risk of exposure to hydrocarbon, toxic or poisonous gases, and catalyst

dust is low during a new unit checkout; the primary danger is nitrogen. There will

be pressure testing, line flushing, hydro testing, and possibly chemical cleaning

being conducted in the unit and nitrogen may be used during any of these

activities. Some of the equipment may have been inventoried with nitrogen to

protect the internals from corrosion. An additional hazard is imposed by

operations in other parts of the plant, which may be beyond the control of the

people entering the vessel. For these reasons vessel entry procedures must still

be rigorously followed during the checkout of a new unit.

The oxygen content of the atmosphere inside of the vessel should be

checked before every entry and the vessel should be blinded. Independent

blinds at each vessel nozzle are preferred. However, in the event that many

vessels are to be entered in a new unit, which is separate from the rest of the

plant, the entire unit can be isolated by installing blinds at the battery limits rather

than by individually isolating every vessel nozzle.

12.6.4 INSPECTIONS DURING TURNAROUNDSIn turnaround inspections, the possibility that vessels will contain dangerous

gases is much higher. Equipment that has been in service must be thoroughly

purged before entry. The vessel should have been steamed out unless steam

presents a hazard o the internals and then fresh airs circulated through it until all

traces of hydrocarbons are gone. If liquid hydrocarbon remains or if odours

persist afterwards, repeat the purging procedure until the vessel is clean. The

service history of the vessel must also be investigated before entry so that

appropriate precautions may be taken. The service may require a neutralisation

step or a special cleaning step to make the vessel safe. Internal scale can trap

poisonous gases such as hydrogen sulfide or hydrogen fluoride that may be

released when the scale is disturbed. If this sort of danger is present, fresh air

masks and protective clothing may be required to worn while working inside of

the equipment.

In a turnaround inspection, every vessel nozzle must be blinded at the

vessel with absolutely no exceptions. There will always be process material at

the low and high points in the lines connecting to the vessel because it is not

possible to purge them completely clean. The blinds must all be in place before

the vessel is purged.

Another factor to be cautious of, especially if entering a vessel immediately

after the unit has been shut down, is heat stress. The internals of the vessels

can still be very hot from the steam-out procedure or from operations prior to the

shutdown. If that is the case, the period of time spent working inside of the

vessel should be limited and frequent breaks should be taken outside of the

vessel.

12.7 FIRE FIGHTING SYSTEM

The operating personnel should be fully conversant with Fire fighting system

provided in the unit. All of them should have adequate fire fighting training and

will serve as an auxiliary Fire Squad in the event of a fire breakout. It will be the

primary responsibility of unit personnel to fight the fire at the very initial stage

and, at the least, localise it.

Major Fire fighting facilities provided in the unit comprising the following:

a) Fire Water System

Water is most important fire fighting medium. Water is used to extinguish the

fire, control, equipment cooling & exposure protection of equipment/personnel

from heat radiation.

An elaborate firewater distribution network is provided around unit. Firewater

Hydrants/Monitors are provided around unit, which give coverage to most of

equipment.

b) Foam SystemFor containing large Hydrocarbon fires, foam systems are useful. They

have inherent blanketing ability, heat resistance and security against burn back.

Low expansion foam is used for hydrocarbon oil fire.

Foam can be applied over burning oil pool with the help of foam tenders/foam

delivery system.

c) Portable Fire ExtinguishersFire should be killed at the incipient stage. Portable fire extinguishers are

very useful in fighting small fires. All extinguishers in the unit must be located in

specified places only. The operating crew should be acquainted with exact

location of the extinguishers. They also must know most suitable type, which,

when and how to use an extinguisher. For example, electrical fires should be put

out with CO2 or dry power extinguishers; water and foam should not be used.

The used extinguishers should be checked and restored by fire station personnel.

d) Fire SignalBreak Glasses have been provided at strategic locations of unit to see fire

alarm in fire station. If a fire is sighted, glass of window should be smashed,

causing fire alarm switch to actuate. This is an emergency call & should be

periodically tested for proper functioning.

e) Steam SmotheringLP Steam hose connections have been provided at every convenient point

inside unit. Steam lances of standard 15M length can be fitted with these hose

stations. Wherever hydrocarbon leakage is detected which is likely to catch fire,

Steam blanketing may be done. Apart from diluting combustible Hydrocarbons,

steam prevents atmospheric oxygen from taking part in combustion & thus help in

extinguishing fire. However, steam should never be applied on large pool of

hydrocarbon fire. Direct application of steam on burning oil may result in spillage

of burning hydrocarbon & spread of fire. Similarly use of firewater on hot oil

surfaces may cause sputtering & spread of fire.

12.7.1 USE OF LIFE SAVING DEVICESafety of the personnel should the prime concern. Life saving device is to

be used for personnel protection. Important life saving devices which are required

to be used are given below:

Head protection:

Safety helmets shall be worn by all personnel at all times in the plant for

protection of the head. They may be removed when inside rooms or buildings

that do not have overhead or other hazards.

Eye and face protectionSafety glasses, goggles or face shields shall be worn while performing work,

which could result in eye or face injury.

Hand ProtectionProper hand protective gloves should be worn.

Foot protectionSafety shoes are to be worn for foot protection.

Ear protectionWhenever persons are required to be work in noisy areas proper ear protection

device such as earplug etc, is to be used.

Breathing apparatusWhenever persons are required to work or enter an area of high

toxic/aromatic/hydrocarbon vapour concentration, wear appropriate respiratory

protection, such as self-contained breathing apparatus or an air mask with an

external air supply.

SECTION- 13 GENERAL OPERATING INSTRUCTIONS FOR EQUIPMENT

13.1 GENERALThis section covers the general procedure for operation and trouble

shooting of commonly used equipment like pumps, heat exchangers and furnace

etc. For specific information and more detail refer to vendor's manuals.

13.2 CENTRIFUGAL PUMPS

Start-up Inspect and see if all the mechanical jobs are completed.

Establish cooling water flow where there is such provision. Also open steam

for seal quenching in pumps having such facilities.

Check oil level in the bearing housing, flushing may be necessary if oil is dirty

or contains some foreign material.

Rotate the shaft by hand to ensure that it is free and coupling is secure.

Coupling guard should be in position and secured properly.

Open suction valve. Ensure that the casing is full of liquid. Bleed, if necessary,

from the bleeder valve.

Energise the motor. Start the pump and check the direction of rotation. Rectify

the direction of rotation if it is not right.

Check the discharge pressure. Bleed if necessary to avoid vapour locking.

Open the discharge valve slowly. Keep watch on the current drawn by the

motor, if ammeter is provided. In other cases check at motor control centre.

In some pumps a by-pass has been provided across the check valve and

discharge valve to keep the idle pump hot. In such pumps, the by-pass valve

should be closed before starting the pump. It should be ensured that casing of

these pumps are heated up sufficiently prior to starting of the pump to guard

against damage of the equipment and associated piping due to thermal shock.

Shutdown Close discharge valve fully.

Stop the pump

a) If pump is going to remain as standby and has provision for keeping the pump

hot, proceed as follows:

Open the valve in the by-pass line across the discharge valve and check

valve.

The circulation rate should not be so high to cause reverse rotation of idle

pump and also overloading of the running pump.

b) If pump is to be prepared for maintenance, proceed as follows:

Close suction and discharge valves.

Close valve on check valve by-pass line, if provided.

Close cooling water to bearing, if provided. Also shut off steam for seal

quenching, if provided.

Slowly open pump bleeder and drain liquid from pump if the liquid is very hot

allow sufficient time before draining is started. Ensure that there is no

pressure in the pump. Also drain pump casing.

Blind suction and discharge and check valve by-pass line and flare connection

if any.

Cut-off electrical supply to pump motor prior to handling over for maintenance.

Trouble Shooting

a) Pump not developing pressure Bleed to expel vapour/air

Check the lining up in the suction side.

Check the suction strainer.

Check the liquid level from where the pump is taking the suction the suction.

Check pump coupling and rotation.

Get the pump checked by a technician.

b) Unusual Noise Check the coupling guard if it is touching.

Check for proper fixing of fan and fan cover.

Check for pump cavitations.

Get the pump checked by a technician.

c) Rise of Bearing TemperatureGenerally the bearing oil temperature up-to 800C or 500C above ambient

whichever is lower, can be tolerated.

Arrange lubrication if bearing is running dry or oil level is low.

Adjust cooling water to the bearing housing, if there is such provision.

Stop the pump, if temperature is too high, call the pump technician.

d) Hot Gland Adjust cooling water if facility exists.

Slightly loosen the gland nut, if possible.

Stop the pump and hand over to maintenance.

Arrange external cooling if pump has to be run for sometime.

e) Unusual Vibration Check the foundation bolts.

Check the fan cover for looseness.

Stop the pump and hand over to maintenance.

f) Leaky Gland Check the pump discharge pressure.

Tighten the gland nut slowly, if possible.

Prepare the pump for gland packing or adjustment/replacement of mechanical

seal as the case may be.

g) Mechanical Seal Leak Stop and isolate the pump and hand over to maintenance.

13.3 HEAT EXCHANGERS

13.3.1 GENERALThe unit has a number of heat exchangers, air coolers. Suitable valves for

bypassing and isolation were provided wherever necessary to offer the required

operational flexibility.

The exchangers have been provided with draining and flushing connections.

The coolers and condensers have been provided with TSV's on the cooling

waterside to guard against possible rise of pressure due to faulty operations with

the safety release to atmosphere. Temperature gauges or Thermowells have

been provided at the inlet and outlet of exchangers. Where water is the cooling

medium, no temperature measurement is provided for water inlet temperature,

which is the same as cooling water supply header temperature.

13.3.2 AIR COOLERS

Air coolers/condensers comprise of a fin tube assembly running parallel

between the inlet and outlet headers. These are of the forced draft type. The

forced draft fans provided have auto variable speed rotors in which the fan

speeds are adjusted during rotation. This allows variation in airflow as per the

cooling requirements. A high vibration switch is provided with alarm to indicate

any mechanical damage.

13.3.3 EXCHANGERSShell and Tube type heat exchangers can be broadly classified into following types:

Water Coolers/condensers

Steam heaters (Reboiler)

Exchangers

Start-up/shut down procedures for each unit shall vary slightly from case to case.

However, general start-up/shut-down procedures are discussed in the following

paragraphs.

START-UP After the heat exchanger has been pressure tested and all blinds removed,

proceed as follows:

Open cooling medium vent valve to displace non-condensable (air, fuel gas,

inert gas etc.) from the system. Ensure the drain valves are capped. For high-

pressure system, drain valves should be flanged. This activity is not required if

gas is the medium.

Open cooling medium inlet valve. Close vent valve when liquid starts coming

out through it, then open cold medium outlet valve and fully open the inlet

valve also. Where cold medium is also hot, warming up of cold medium side

gradually is also essential.

Open hot medium side vent valve to displace non-condensable (air, fuel inert

gas etc.). Check that the drain is closed and capped. This activity is not

required if gas is the medium.

Crack open hot medium inlet valve. When liquid starts coming out from the

vent valve, close it. Open hot medium inlet valve and then open the outlet

valve fully. In case of steam heaters, initially the condensate shall be drained

to sewer till pressure in the system builds up to a level where it can be lined

up to the return condensate header.

In case by passes are provided across shells and tube side, gradually close

the bypass on the cold medium side and then the bypass across the hot

medium side.

Check for normal inlet and outlet temperatures. Check that TSVs are not

popping.

The operation of inlet and outlet valves should be done carefully ensuring that

the exchangers are not subjected to thermal shock.

In case of coolers/condensers, adjust the water flow to maintain the required

temperature at the outlet.

For avoiding fouling, velocity of water should be at least 1 m/sec in a

cooler/condenser.

Shutdown Shut down of an exchanger, coolers, condenser is considered when the equipment

is to be isolated for handling over to maintenance while the main plant is in

operation. The following is the suggested procedure for isolation of the piece of

equipment

Isolate the hot medium first. In case both hot and cold medium are from

process streams, exchanger shall remain in service till the hot stream has

cooled down enough.

In case of a cooler, adjust cooling water flow to the cooler, which is in line so that

product temperature is within allowable unit.

Isolate the cold medium next.

Drain out the shell and tube sides to OWS/Sewer/Closed blow down system as

applicable. In case flushing oil connection is given flush the exchanger to CBD.

Ensure that the CBD drum has sufficient usage to receive the flushing of the

exchanger

Depressurise the system to atmosphere/flare/blow down system as applicable.

Purge/flush if required. This is particularly important in congealing services.

Blind inlet and outlet lines before handing over the equipment for maintenance.

Fccnht Manual

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